Drilling Course

Differential Stuck Pipe Mechanism: Causes and Solutions

2022-02-13T13:49:00.002+01:00

Differential sticking is one of the mechanisms of stuck pipe problems and it can be defined as the sticking force generated by the level of the overbalance between the hydrostatic pressure and the formation pressure, this pressure overbalance pushes the static drill string into the filter cake. Many factors can lead to this problem:

- The hydrostatic overbalance exposed on a permeable layer of formation ( sand or fractured limestone)

- Pipe movement stopped for any reason for instance make connection or rig repair which put the string in contact with permeable zone.

- Thick static filter cake

- The large contact area between the drill string and the formation

Analyzing these factors, it can be concluded that differential sticking occurrence is related to the presence of these factors simultaneously, the string has to be static and in contact with a permeable zone and pushed by high force generated by the pressure overbalance.

The filter cake develops when the liquid phase of the drilling fluids can flow in the permeable zone and the solids present in the drilling fluids system deposits on the borehole walls forming the filtered cake. It has to be mentioned here that the filter cake is necessary to manage the fluid loss but the thickness of this filter cake has to be controlled to avoid stuck pipe by this mechanism. There are two types of the filter cake: dynamic and static. Under dynamic conditions, the filter cake thickness decreases due to the mechanical forces of the drill string and the fluids flow which washes the top layer of the filter cake leading to thickness decrease. Under static conditions, the rate of solids depositions increases which leads to thickness increase.

Also, during the dynamic conditions, the hydrostatic pressure is exerted equally around the drill string and the differential sticking force cannot develop but after ceasing drill string motion, the static filter cake starts to develop and string can be pushed toward the borehole walls.

Mathematically, the sticking force is described as follows:

Fs = PDiff x A

Where:

Fs : Sticking force

PDiff: Pressure difference

A : Contact area

Fig 1 . Sketch of Differential Stuck Pipe

There are some indicators of differential pressure stuck pipe:

- Increase in torque and drag while drilling

- In severe situation, getting high level of overpull after making connections

- Inability for reciprocating the drill string

- The circulation is not interrupted

Differential pipe sticking can be prevented by following some precautions:

- Apply the minimum possible safe overbalance while drilling

- Controlling the fluid loss and consequently reducing the filter cake.

- Optimize the drilled solids percentage in the mud system.

- Drill with low friction coefficient mud system (The friction coefficient can vary from 0.04 for oil based drilling fluids to 0.35 for water based muds)

- Reduce the timing while the string is static for example when repairing or making a connection.

The contact area represents the total pipe surface which is in the direct contact with the walls of the open hole. This surface of contact can be affected by many factors:

- Length of the permeable zone

- Hole size

- Pipe size and shape

- Filter cake thickness

It is obvious that the length of the permeable zone cannot be controlled and even the hole size which generally a fixed parameter. Using spiral drill collars and heavy weight drill pipe can contribute in reducing the contact area with the permeable zone and consequently reducing the sticking force.

Controlling the high temperature high pressure filtration rate is an important field practice to minimize the risk of differential sticking. The contact area can increase enormously with important filter cake which increases the risk of such type of stuck pipe.

Fig 2 . Spiral Drill Collar can reduce the contact area by more than 30%

There are many methods used to free the differential stuck pipe. Considering that the differential sticking force increases with time, torque up the drilling string and jarring down can be the effective first action to perform. This action can be applied quickly with the little possibility of creating other problems. Combining the torque and the down- jarring can generate a great load which increases the possibility of freeing the drill string. This action can be applied as follows:

- Circulating at the maximum rate while applying string torque because circulation washes the static filter cake and reduces its thickness.

- The torque has to reach the 80% of the make up torque of the drill pipe, then the string has to be carefully reciprocated to transfer the torque to the deepest point which normally be the stuck point.

- Reduce the pump speed to 1 bbl/min to decrease the annular friction pressures

- Jarring down the torqued drill string

- If the string does not come free , repeat these actions and keep jarring down

- If you decide to jar up for any reason, carefully release the string torque. This is very important because the combined torque and tension reduces the tension capacity of the string.

If the first action described above failed to free the string, then pumping a chemical agent should be pumped down hole and placed at the stuck zone. Pumping this chemical agent is to destroy the filter cake around the stuck point. These products work to loose the contact between the pipe and the filter cake. The chemical products have to be displaced by steps to re-fresh the chemicals around the stuck point and make them more effective. Also, the string has to be worked up and down. This action can be performed with some precautions:

- First, determining the stuck point is important to know where to spot the pill. If the jar can be tripped this means that the stuck point is below the jar. If the drilling jar cannot be tripped this means that the stuck point is at some depth above the drilling jar. Also, the stuck point can be determined by using a free point indicator tool or by performing some pipe torque calculations.

- The chemical agent pill should be 1 to 2 ppg greater than the drilling fluid density to keep the pill on spot. Also the pill volume should be 1.5 times required volume to make sure it is sufficient to cover the stuck area.

- If the well can be pressurized without risking of generating down hole mud losses. The pressure applied at the annular space by closing the BOP has to be held for 10 to 15 minutes in order to pressurize and drive the chemical agent into the filter cake. After waiting the recommended timing, the pressure has to bled off through the choke, then the BOP can be opened.

- After, bleeding the pressure and waiting the recommend timing for the chemical agent, jarring down is the next action to perform. As mentioned above, the string has to be torqued till 80% of the make up torque of drill pipe and torque should be transferred to the stuck point by reciprocating the string up and down, then jarring down with maximum load till getting free.

If the string does not come free after applying these two options, the fishing operation can be the next action after performing a back off.

Functions of Drilling Fluids

2022-02-05T13:18:00.000+01:00

One of the success keys in drilling projects is the Drilling fluids which are circulated down hole through the drill string and drilling bit then up in the annular space towards the surface. The drilling fluids program which includes design, formulation, and reactions with the formation and also surface treatment are crucial for operations.

Drilling fluids have many functions which can involve:

- Controlling the formation pressure to do not allow formation fluids to come into the well which can lead to well control situations

- Hole cleaning and that means suspending and removing drill cuttings from the wellbore

- Provide mechanical and chemical borehole stability

- Allow for reliable formation rocks information

- Drilling bit and string lubrication

- Minimize the formation damage

- Limit the level of the corrosion

Many functions can be listed which are related to the drilling fluids. The important ones are detailed below.

1. Hydrostatic Pressure

While performing drilling operations, part of the rock is removed and has to be replaced by the drilling fluids for two reasons:

- Supporting and stabilizing the drilled rock

- Overcoming the formation fluids pressure do not allow them to enter into the wellbore and this issue is related to safety.

The hydrostatic pressure is generated by the column of the drilling fluids. This pressure has to be calculated correctly and accurately because exceeding this planned limit can lead to damaging the formation or even worse formation fracture can be faced leading to drilling fluids losses and well control situations. Gathering data about the formation stresses, strength and pore pressures is very important to planning drilling fluids muds and casing setting depths.

The pressure generated by the drilling fluids in static situation can be estimated as following

Hydrostatic Pressure HP = 0.052 x MW x TVD

Where

MW is the mud weight in ppg

TVD is the total vertical depth in feet

When circulating fluids downhole additional impact on the formation is generated which can be added to the hydrostatic pressure level, this impact is represented by the equivalent circulated density and can be calculated as follows:

ECD = MW + [APL / (0.052 x TVD)]

Which

ECD is the equivalent circulating density in ‘’ ppg’’

APL is the estimated annular pressure losses ‘’Psi’’

2.Cuttings Transport and Hole cleaning

Cuttings are generated while drilling and have to be removed from the wellbore to allow for better drilling progress. Cuttings are transported to the surface by the drilling fluids then they are separated by the solid control equipment. The transporting of the cuttings is related to many factors including the annular velocity which should be greater than the slip velocity. The drilling fluids should help to remove the cuttings away from the area where they are generated below the drilling bit, and should also have the ability to suspend the cuttings when the mud pumps are shut off for any reasons for instance making connections. Removing the cuttings can be affected by the mud pumps rate, mud properties and hydraulics. The drilling fluids properties can help improving the lifting capabilities and the suspension of the cuttings but the volumetric flow is important to sweep area below the bit and transport the cuttings to the surface. Poor hole cleaning and cuttings transport can overload the annular space which can affect the mud density and lead to excessive hydrostatic pressure and this can happen especially when drilling surface formations where the rate of penetration are higher. One of the solutions when drilling surface section is controlling the rate of penetration in order to avoid facing severe losses and may be total losses. For this reason the flow rate is critical for overall drilling performance.

Fig 1 - Stuck Pipe Due to Pack Off

3.Filtration Control

Fluid loss of the drilling fluids is related to the level of the overbalance between the hydrostatic pressure generated by the column of the drilling fluids and the pore pressures, formation permeability, filter cake permeability and the temperature. Uncontrolled fluid loss can raise many issues while drilling such as reduced penetration rate, poor hole cleaning, formation damage and differential sticking. Mud filtration can become more critical when drilling through depleted formations, zones with high level of permeability and naturally fractured layers and this can be more severe when hydrostatic pressure is higher. Also, it can be mentioned here that the level of invasion into producing zones can cause formation damage and affect the production level from this affected zone or layer. A good filter cake can help to maintain fluid invasion under control, unlike the thick filter cake leads to excessive torque and drag and in some cases to stuck pipe by differential sticking mechanism.

Fig 2 - Stuck Pipe by Differential Mechanism

4.Mechanical Stability

The mechanical instability or rock failure results from the imbalance between the different stresses. When drilling a new hole, the stresses have to be rebalanced to avoid wellbore collapsing. There are many factors which can affect the shale stability and they are listed as follows:

- Proper Drilling fluids density to keep the borehole walls stable and avoid cavings

- Erosion which can be caused by uncontrolled hydraulics

- Contact with drill string equipment like drill pipe which can with high rotating level destabilize the formation

- High fluid losses can contribute in weakening the formation

Rock instability can result many downhole problems which increase the non-productive time NPT and lead in worse cases to loss the hole. Tight spots can be faced when running in or out of the hole and result in excessive wear on drilling bit and stabilizers. Formation cavings can come into the drilling fluids system and when the mud can not transport these cavings to surface they can cause stuck pipe which is considered may be the most costly problem. Dealing with stuck pipe takes rig time and consequently extra project budget. In some cases, it becomes impossible to recover the fish and the project has to be modified which can include very expensive operation such as setting a cement plug, side tracking the well to come the original point.

In this mechanism, it can be listed three types of subsurface stresses. The overburden pressure which is the pressure exerted by the formations layers weight above the concerned zone. The pore pressure is the pressure of the formation fluids inside the pore spaces and this pressure helps in supporting the overburden pressure. The matrix stresses which are considered as a part of the overburden pressure and it is supported by the formation physical structure, the matrix stresses can be divided into three components one vertical and two horizontal.

General Questions With Answers - 9 -

2022-02-01T15:49:00.000+01:00

1 . You have taken a 10-bbl kick with 500 psi shut in drill pipe pressure and 900 psi shut in casing pressure. The mud weight is 13 PPG and the TVD is 10,000 ft. You are unable to circulate the kick out due to power failure. After 1 hour the driller notices that both the drill pipe and the annulus pressures have increased by 100 psi. We decide to let the influx come to surface without circulation.

1.1) What will happen to the casing pressure as we do this?

a) Decrease

b) Increase .

c) Stay the same.

1.2) What will happen to the casing shoe pressure as we bring the influx up towards the shoe?

a) Decrease

b) Increase .

c) Stay the same.

1.3) What will happen to the pressure inside the influx?

a) Decrease .

b) Increase

c) Stay the same.

1.4) What will happen to the bottom hole pressure?

a) Decrease

b) Increase

c) Stay the same .

1.5) In this situation the influx is probably:

a) Impossible to tell

b) Salt water

c) Fresh water

d) Gas

1.6) It seems that the kick is:

a) Staying on bottom

b) Coming to surface

c) Breaking down the shoe

d) Expanding around the drill collars.

1.7) If we cannot circulate, we can bring the influx to surface by:

a) Keeping the casing pressure constant at 900 psi

b) Keeping drill pipe pressure constant at 900 psi

c) Keeping casing pressure constant at 500 psi

d) Keeping drill pipe pressure constant at 500 psi

2. List 5 warning signs that could indicate a potential kick while drilling. NOTE: 2 of these might only be seen if the kick was already of a large volume

3. Consider the following two pressure tests of an annular preventer :

Choose the single best answer from the following:

a. Generally speaking test a. and test b. are both acceptable.

b. Generally speaking test a. and test b. are both unacceptable.

c. Generally speaking test a. is acceptable and test b. is not.

d. Generally speaking test b. is acceptable and test a. is not.

4. If a ram type preventer is operated closed, what happens to the accumulator fluid on the open side of the operating cylinders? Describe the path of the open side fluid in some detail for this situation.

5. What items must be readily available for use and easily accessible to the drill floor workers in case the well needs to be shut in during tripping?

6. While drilling in the open hole what position must the BOP control function 4-way valves on the accumulator never be left in?

7. What is the bypass on the accumulator for? What position should handles of 4-way valves be in and why?

8. What effect will reciprocating casing have on down-hole pressures?

What effect will reciprocating casing have on annular velocities?

Based on these two ideas, how will you manage casing reciprocating practices?

Answers

1. You have taken an 10 bbls kick…..

1.1) b) Increase

1.2) b) Increase

1.3) a) Decrease

1.4) c) Stay the same.

1.5) d) Gas

1.6) b) Coming to surface

1.7) c) Keeping drillpipe pressure constant at 500 psi

2. List 5 warning signs……..

- ROP increase.

- Temperature increase.

- D exponent increase.

- Gas cut mud.

- Increase in string weight. After large kick is taken

- pump circulating pressure reduction. After large kick is taken

3. c. Generally speaking test a. is acceptable and test b. is not.

4. Oil flow will return back to the 4 way valve and from there it will go back into the reservoir.

5. Full opening safety valves with key's, Stab-in valve (Gray valve), Cros over(X/over) for DC to safety valve size.

6. Never in the neutral position. Leaking of the 4 way valves can close the rams while drilling.

7. To increase the manifold pressure for Shear-rams or to increase the closing pressure for every ram. Open or close.

8. Reciprocating down will have positive pressure surges (increase in ECD), and up will be negative(swab pressure).

On the down stroke, annular velocity will increase enhancing the pressure surge. Casing may be moved relatively faster (swab considerations) on the up stoke.

Casing must be lowered relatively slowler on the down stroke. “Do” reciprocation with care and control the speed.

General Questions With Answers - 8 -

2022-02-01T14:13:00.001+01:00

1. Hardened cement is

a. Porous and permeable

b. Slightly porous but not permeable.

c. Non Porous and permeable

d. Slightly permeable and porous.

2. A pit drill is :

a. A drill used to excavate waste pits.

b. A drill to test the mud hardness.

c. Raising the pit level recorder manually to test the alertness of the driller.

d. short for "a pittyfull driller"

3. How do we know what pressure the formation just below the shoe can stand?

a. By using a Repeat Formation Tester (RFT) logging tool.

b. By performing a formation strength test.

c. By pressure testing the casing.

d. By calculation from the well programme.

4. If the influx volume is large because of late closing in of the well, the following pressure(s) are affected

a. Drill Pipe PressurePdp

b. Annular Pressure Pann

c. Pdp + Pann

d. Pdp and formation pressure.

5. In which way is the first build-up of Pdp and Pann affected by the permeability of the formation?

a.Low permeability -slow build up + High permeability - rapid build-up.

b.Low permeability -rapid build up + High permeability - slow build-up.

c.Low permeability -slow build up + High permeability - slow build-up.

d.Low permeability -rapid build up + High permeability - rapid build-up.

6. What is the influence of a the volume of gas influx on the height of the "Peak Pressure"?

a. The larger the initial volume the higher the peak pressure.

b. The larger the initial volume the lower the peak pressure.

c. The larger the initial volume the peak pressure stays the same.

d. The smaller the initial volume the higher the peak pressure.

7.Well control equipment should be pressure tested :

a. Once every two weeks.

b. After installation of wellhead and BOP's.

c. Prior to drilling into a presumed high pressure zone.

d. all of the above

e. When the DSV says so.

8. What is Key seating?

a. The place for the key of the V-door.

b. When drillpipe wears a slot in the wall of the hole.

c. When stabilisers are held up under the shoe.

d. When the hole is undergauged and a new drilling bit gets stuck.

9. What is a typical fishing assembly with a spear?

a. spear - spear stop - safety joint - jar - drillcollars - drillpipe - kelly

b. spear - spear stop - jar - safety joint - drillcollars - drillpipe - kelly

c. spear - safety joint - spear stop - jar - drillcollars - drillpipe - kelly

d. spear stop - spear - safety joint - jar - drillcollars - drillpipe - kelly

10. What is Formation Dip ?

a. The angle between the wellbore and a vertical.

b. The angle between a geological strata and a vertical

c. The angle between a geological strata and a horizontal.

d. The angle between the up dip and the down dip of the formation.

Answers

1. Hardened cement is : b. Slightly porous but not permeable.

2. A pit drill is : c. Raising the pit level recorder manually to test the alertness of the driller.

3. How do we know what pressure the formation just below the shoe can stand? b. By performing a formation strength test.

4. If the influx volume is large because of late closing in of the well, the following pressure(s) are affected b. Annular pressure Pann

5. In which way is the first build-up of Pdp and Pann affected by the permeability of the formation? a.Low permeability -slow build up , High permeability - rapid build-up.

6. What is the influence of a the quantity of gas influx on the height of the "Peak Pressure"? a. The larger the initial volume the higher the peak pressure.

7.Well control equipment should be pressure tested : d. all of the above

8. What is Key seating? b. When drillpipe wears a slot in the wall of the hole.

9. What is a typical fishing assembly with a spear?

a. spear - spear stop - safety joint - jar - drillcollars - drillpipe - kelly

10. What is Formation Dip ? c. The angle between a geological strata and a horizontal.

General Questions With Answers - 7 -

2022-02-01T09:57:00.001+01:00

1. Pressure sensors should always be installed vertically on top of the mud discharge line to :

a. Prevent from being clogged by solids.

b. Reduce the change of gas bubbles being trapped.

c. Give the most accurate reading of the pumps.

d. All of the above.

2. The MAC value for H2S is :

a. 1 ppm

b. 5 ppm

c. 10 ppm

d. 15 ppm

3. Why does a drillpipe have upsets?

a. To increase the strength of the welding areas

b. To give the elevator a shoulder for pulling.

c. To prevent the pipe of slipping through the slips.

d. To gradually change the transition from the pipe to the tool joint.

e. a+b+d

f. b+c+d

g. a + d

4. The RPM of a mud motor depends on :

a. Size of tool

b. Volume pumped

c. The number of stages

d. All of the above

e. a+b

5. What is meant by source rock?

a. A rock which generates Hydrocarbons.

b. A rock containing heavy metals.

c. A sedimentary rock.

6. The resistivity of a rock formation will be high unless the formation contains water. Resistivity will be increased by :

a. Lowering the temperature

b. Lowering the salinity

c. Lowering the porosity

d. Increasing the oil content

e. All of the above

f. a+b

g. a+b+d

7. A float collar is used in a casing string to :

a. Ensure the casing will NOT float

b. Ensure the casing will float

c. Duplicate the back pressure valve of the float shoe and as a stop for the cementing plugs.

d. a+c

e. b+c

8. A side door elevator must be replaced by a slip type elevator when :

a. There is enough weight down

b. When its permissable load capacity has been reached.

c. When the casing starts to float.

d. When the casing enters the Open Hole.

e. a+d

f. a+c

g. b+d

h. c+d

9. An "AW" slip & seal assembly has:

a. A selfenergising seal

b. Energising screws to be thightened manually.

c. Both the above.

d. Neither of the above.

10. Which part of the casing has to have a particularly good cement bond ?

a. All of the casing

b. The shoetrack

c. The upper part of the casing.

d. Across any loss zone.

Answers

1. Pressure sensors should always be installed vertically on top of the mud discharge line to : a. Prevent from being clogged by solids.

2. The MAC value for H2S is : c. 10 ppm

3. Why does a drillpipe have upsets? g. a + d

4. The RPM of a mud motor depends on : e. a+b

5. What is meant by source rock? a. A rock which generates Hydrocarbons.

6. The resistivity of a rock formation will be high unless the formation contains water. e. All of the above

7. A float collar is used in a casing string to : c. Duplicate the back pressure valve of the float shoe and as a stop for the cementing plugs.

8. A side door elevator must be replaced by a slip type elevator when : g. b+d

9. An "AW" slip + seal assembly has: b. Energising screws to be thightened manually.

10. Which part of the casing has to have a particularly good cement bond ? b. The shoetrack

General Questions With Answers - 6 -

2022-01-31T22:16:00.005+01:00

1. What is primary Blow-Out Prevention?

a. BOP's

b. Drilling Mud

c. Float shoe

d. P.V.T.

2. Why do we drill surface hole with a reduced R.O.P.?

a. To give the mud longer to form a wall cake, preventing hole collapse

b. To reduce the penetration in a possible shallow gas pocket.

c. To reduce the cuttings volume in the annulus.

d. To prevent wash-outs.

3. What brake system uses a steel drum rotated through a magnetic field produced by concentric electromagnets mounted inside the drum.

a. Hydromatic brake

b. Magnetic Particle brake

c. Eddy Current brake

d. Drum brake

e. Disc brake

4. An 18° type elevator is used for :

a. Drillpipe

b. Tubing

c. Casing

d. Pump Rods

5. What is the function of drilling fluid in a well ?

a. Remove cuttings from the bottom of the hole

b. Transmit power for downhole motors

c. Acts as a transmission fluid for some logging tools

d. All of the above.

6. Lignosulphonate (as a thinner) will:

a. Absorb on the negative edges of clay platelets

b. Absorb on the positive edges of clay platelets

c. Encapsulate the clay platelets.

d. All of the above.

7. A filtercake is build up from :

a. Mud solids from the wellbore

b. Mud solids from the wellbore and solids added to the system.

c. Mud solids from the wellbore and a chemical reaction.

d. Solids added to the mud.

8. Why is the PH of the drilling mud so important?

a. To minimise corrosion

b. To improve ROP

c. To reduce the resistance to flow.

d. To neutralise acidic fluids from the formation.

e. All of the above

f. a+d only.

9. What is the approximate PH value of mud?

a. + 5

b. +10

c. +15

d. +20

10. "Roping" in a hydrocyclone is :

a. Using a rope or stick to clean the apex.

b. Flooding liquid out of the apex.

c. A type of discharge out of the apex

d. A leak in the cone

Answers

1. What is primary Blow-Out Prevention? b. Drilling Mud

2. Why do we drill surface hole with a reduced R.O.P.? c. To reduce the cutting volume in the annulus.

3. What brake system uses a steel drum rotated through a magnetic field produced by concentric electromagnets mounted inside the drum. c. Eddy Current brake

4. An 18° type elevator is used for : a. Drillpipe

5. What is the function of drilling fluid in a well ? d. All of the above.

6. Lignosulphonate ( as a thinner) will: b. Absorb on the positive edges of clay platelets

7. A filtercake is build up from : b. Mud solids from the wellbore and solids added to the system.

8. Why is the PH of the mud so important? f. a+d only.

9. What is the approximate PH value of mud? b. +10

10. "Roping" in a hydrocyclone is : c. A type of discharge out of the apex

General Questions With Answers - 5 -

2022-01-31T18:30:00.006+01:00

1. What is "Chip Hold Down "pressure? How does this affect penetration rate?

2. Happily drilling an 8.1/2" hole at 12200 ft with a 0.6 psi/ft mud. The well starts to flow. Outline the step by step procedure for shutting in the well.

3. In the same well above Pdp = 500psi and Pann = 620psi. While mixing the kill mud (30 minutes) Pdp rises to 600 psi and Pann rises to 720 psi.

a. Explain what has happened.

b. What do you undersand by the term primary and secondary build up.

c. Outline the step by step procedure for starting to kill the well and establishing the correct Standpipe pressure.

4. After drillling to 13000 ft a gas sand is penetrated and it is decided to pull out for coring. The brake cooling system fails on the trip out and it is decided to stop at the 9.5/8" casing shoe and carry out repairs.

a. What are the precautions that you would take to safe guard the well during the period that the cooling system is being repaired.

b. It takes 5 hours to finish the repairs. Outline the procedure that you would take until the bit reaches surface.

5. Why do we drill top hole ( 17.1/2") with a reduced ROP :

a. better determination of formation tops.

b. prevent sticking.

c. to keep the mud weight low.

d. lower torque.

e. because we always do it.

f. to prevent swabbing.

g. to prevent gas cut mud.

6. Poor-Boy Mud/Gas Separator

a. Which one of the poor-boy mud gas separator dimensions limits the capacity of the seperator before gas blow through occurs?

b. Which of the dimensions of the same mud/gas separator determines the presure build up in the separator?

c. What is the maximum that the pressure gauge could read before the mud seal is lost in the separator? Assume that the mud weight in use is 12.5 ppg.

d. What aspect of your killing procedure would you consider for controlling pressures that may be encountered in the poor boy mud/ gas separator?

dimensions are ;

D1 = 8" D2 = 6" D3 = 48" L1 = 140" L2 = 20" L3 = 8'' L4 = 10''

Answers

1. When the bottom hole pressure BHP of the fluid column is greater than the formation pore pressure, the bit tooth will have to overcome this pressure to push the chip out.

The smaller the difference between the BHP and the pore pressure, the easier/faster the bit will drill.

2. Space out (almost tool joint 1 m above the rotary table), Stop pumps, close one preventer ( Annular or pipe rams), open HCR, note down drill pipe pressure (Pdp) and casig pressure (Pann)

3. a) The gas is migrating up to surface.(Without expanding)

b) Primary build-up is the initial pressure build-up showing an indication of the Permeability of the reservoir. Secondary build up is when both Pdp and Pann are going up at the same rate, showing the migration speed of the gas in the well.

c) Start pumps by keeping Annular pressure Pann constante until the correct kill pump speed is obtained, then keep drill pipe pressure Pdp constante by opening or closing the choke till evacuating the gas out of the hole.

4. Line the well up on the trip tank and keep the trip tank pump running. Keep watch on trip tank level. I would run back to bottom and circulate bottoms-up to ensure no problems.

5. a) Length L3

b) D1 and L1

c) 12.5*0.052*8(L3)= 5.2 psi

d) The kill pump speed.

General Questions With Answers - 4 -

2022-01-31T13:30:00.003+01:00

1. On a tripping out of the hole a pill has been pumped so that the pipe pulls dry. The hole fill up has been correct for the first 9 stands. Stands # 10 and 11 take 1/3 as much mud as they should. Stands no.12 and 13 take the correct amount of mud again.

- Describe what has happened and what the driller should be concerned about.

- What should the driller's next action be .

- What are your instructions on how to proceed from here.

2. While circulating out a kick, the pumps break down. During repairing the mud pumps, the pressures on both gauges drill pipe (Pdp) and annular (Pann) have risen by 300 psi. Everything is ready to go now. How will you proceed to kill the well?

3. If shallow gas is encountered, do we :

a. Increase pump speed and activate diverter.

b. Stop pumps and activate diverter.

c. Reduce pump speed, change to sea water and activate diverter.

4. What is the difference between a square and hexagonal kelly? Which one is better and why?

5. What is the purpose of having a relief valve (safety pop off valve) on the mud pumps?

6. What are the purposes of installing a float valve when drilling top hole?

7. What type of cement would you use for setting a balance cement plug for a side track operation and explain why you would use this cement?

8. What gas is used for precharging the pulsation dampeners and to what pressure are they charged to?

9. What is the purpose of a weep hole?

Answers

1. Over stand 10 and 11 you have swabbed in some formation fluid/gas. You will be worried that it is gas and will expand on its way to surface. You will have to do a flow check and if the well is static you will have to run back to bottom. On bottom you will have to circulate bottoms up.

Instructions :

1. Flowcheck

2. Rih carefully, be carefull, you might run the BHA assemblie in the gas and the well might kick.

3. Circulate Bottoms up, flowcheck halfway and 2/3 of the way. After Bottoms up Pooh (pull out of the hole)

carefully.Pump pill when at shoe.

2. Bleed annulus down till gettig the initial Pdp (Pressure on gauge after closing the well for mud pumps repair). Then continue pumping keeping Pann as Pchoke till correct pump strokes (kill rate) are achieved, than keep Pdp constant.

3. We do A. Increase the pump speed to give a higher annular pressure and to keep the hole as full as possible.

4. A square Kelly has four sides, hexagonal Kelly has eight sides. The loading on a square kelly is at four points, while on a hexagonal kelly the loading is on eight points and therefor less prone to distortion.

5. To protect the pressurised system of over pressurising, and to protect the pump of pressure failure.

6. To prevent back flow whilst drilling top hole. This is likely in top hole due to the many cuttings in the annulus.

7. Neat class "G" because this has the highest compressive strength.

8. Nitrogen is used. They are charged to 75% of the working pressure of the pump, but the maximum is 750 psi.

9. The weep hole in the BOP Rams, is there to show either a leak with the primary seals (leaks mud), or to show a leak of the piston seal (leaks accumulator fluid)

General Questions With Answers - 3 -

2022-01-30T22:13:00.004+01:00

1. What is the difference betwen a counter balanced drum and a smooth drum?

2. While circulating out a kick during first circulation of drillers method Pst ( DrillPipe Pressure) was held constant. After a while the pump speed was decreased while hold the same Pst by adjusting the choke. Explain what happens to the bottom hole pressure.

3. Which of the follwing threaded connections are the same as 4½ IF

a. 5 XH

b. NC38

c. 5DSL

d. NC50

4. If the string volume is greater than the open hole annular volume. Which kill method will give lower shoe pressures and why? (Explain your answer). What is the preferred kill method in these situations and why?

5. Which pressure is used for calculating pore pressure (casing pressure Pc or drill pipe pressure Pdp) and why?

6. When tripping out of hole using an accurate trip tank for keeping the hole full, will the amount of mud that is actually added to the hole be equal to, greater than or less than the volume of steel removed? (Explain your answer ).

7. To run casing you string up 12 lines instead of 10. Neglecting line weight, is the load on the derick the same, less or more?

8. In what phase of killing is Pchoke the highest? What effect will kill mud have on this highest pressure?

9. Annular volume is less than the string volume. Which method : Drillers method or Weight and Wait method will give the highest Pchoke pressures.

Answers

1. The drum surface is either smooth or grooved. A counterbalance drum has a grooving pattern which allows spooling of the wire to be controlled and prevents deformation of the wire. a smooth drum has not got this spooling control and needs one full layer of wire to prevent any force on the wire clamp in the drum.

2. If you decrease the pump speed and keep the pressure constant you will have to close the choke to do so. If you close the choke you will increase the BHP.

3. 4 1/2 IF = 5 1/2 DSL = 5 XH = NC 50

4. None. Both Drillers and Wait and Weight Method will have the same shoe pressure if the drillstring volume is larger than the open hole volume. The Kill mud is not yet in the annulus to reduce the shoe pressure when using the Wait and Weight method.

5. Pdp is used, because the Pann has an influx in the hole with an unknown density.

6. It should be theoretically be the same volume. However there will be mud which will cling on the inside of the pipebody. This will make the volume of mud to be added to the system slightly larger.

7. Static Derrick load with 10 lines = (N+2)/N = (10+2)/10 = 1.2 x Hook load

With 12 lines, The Static Derrick load = (N+2)/N = (12+2)/12 = 1.1667 x Hook load

Therefore the load is less with 12 lines than 10 lines

8. The highest pressure during a gas kick is when the gas reaches the choke. The kill mud reduces the choke pressure because of the extra hydraustatic head in the annulus.

9. Both methods will give the same Pchoke. The heavier kill mud has not reached the annulus and the influx is already out of the hole.

General Questions With Answers - 2 -

2022-01-28T21:07:00.087+01:00

1.Stuck pipe and Fishing

1.1 What is in most cases the limiting factor for maximum pull when dealing with stuck pipe?

1.2 What is normally the limiting factor for maximum “Torsion” in a string?

1.3 What is the correct procedure prior to maximum pull on a stuck string when the BHA contains a JAR.

1.4 Name 2 different types of fishing grapples we can dress an overshot with? Which one is the stronger of the two?

1.5 An "FS" or "SH" type? What do these abbreviations stand for?

1.6 What is good practice to do prior to POH (Tripping) after you twisted off?

1.7 Does a Bowen type "Z" fishing jar strike downwards also?

2. Directional Drilling

2.1 If deviation in top hole is checked at intervals because of close well spacing, what special sub has to be incorporated in the BHA? What adjustment does it require at surface prior to RIH?

2.2 What exactly is the purpose of the channel (along axis) through the rotor of a mud motor? It can either be blanked off or be provided with a nozzle. Give one reason for each configuration.

2.3 What do the terms DTU and AKO stand for?

2.4 Which one has the largest bit offset for the same dog leg capabilities?

2.5 What checks are made at surface before mud motor is re-run (e.g. after bit trip)? Give two indications that would tell you there is something wrong with the motor?

Answers

1. Stuck pipe and fishing

1.1 The yield strength of the drillpipe.

1.2 The Make-Up torque of the tooljoint.

1.3 Let the jar stroke out before you pull maximum pull.

1.4 Spiral and Basket grapples. Spiral Grapples are strongest.

1.5 An FS type meaning Full Strength, The SH means Slim Hole.

1.6 To circulate clean above the fish and spot a viscous pill.

1.7 No.

2. Directional drilling

2.1 UBHO sub > Univeral Bottom Hole orientation Sub. You need to orientate the UBHO sub to the Mud motor / turbine.

2.2 By-Pass for the fluid. Use the blank if all fluid is required to go to the motor (In case of high system pressure losses). Use the nozzle if enough fluid is available to by-pass the motor and give higher HP at the bit.

2.3 DTU: Double Tilted Unit. AKO: Adjustable Kick Off.

2.4 AKO.

2.5 Play on the bearing. Test motor on Kelly for dump valve and rotation. If the Motor stalls quicker with the same amount of pressure. A sudden pressure loss showing the dump valve opening.

General Questions With Answers - 1 -

2022-01-28T12:22:00.017+01:00

1. Drilling Fluids

1.1 For what reason do we use KCl in our mud system?

1.2. Name three properties that are immediately affected by an increased percentage of fine solids in the mud. What can be done to correct this?

1.3. What properties immediately change when mud is contaminated with cement? What can be done beforehand when cement contamination is expected? If chemical treatment is your answer, then state three chemicals that can be used.

1.4. What are the common sizes of cones on the desander and the desilter?

1.5. What type of LCM is used to cure mud losses in the reservoir section?

2. Casing & Cementation

2.1 What do the term BWOC and BWOW stand for?

2.2. What chemical can be used to accelerate the thickening time of cement slurry?

2.3. What does BTC stand for? What is the make up torque on BTC connection?

2.4. After the plugs are bumped and the casing has been pressure tested, what do we always check prior to disconnecting the cementing lines from the cementing head?

3. Hoisting Equipment / Mud pumps

3.1 Which device should always be re-adjusted and tested when a drilling line is slipped/cut? Why?

3.2 What do we pre-charge pulsation dampeners with?

3.3 What determines the correct pre-charge pressure? What is the maximum?

3.4 What determines the pressure relief valve setting?

4.Pressure control equipment

4.1 Name the different types of regulators and valves used on BOP control system?

4.2. What are the functions of BOP control system?

4.3. How is the accumulator recharged?

4.4. The drilling bit has been changed after Pooh. BOPS were closed. The BOP’s are opened to run the bit & BHA. The bit has passed BOP’s. After five minutes the accumulator pumps can still be heard firing. What do you think is happening? What can be the cause of it? What action is to be taken?

Answers

1. Drilling Fluids

1.1 To stabilise the shales.

1.2 Density, yield point (YP) and plastic viscosity (PV)

In order to remedy this problem we use the centrifuge and also we can dump mud and dilute.

1.3 The PH goes down, increase in hardness due to increase in CA++.

in case of cement contamiation these properties increase: gels, plastic viscosity and the yield point.

to avoid this problem the drilling mud system can be treated beforehand with Sodium Carbonate, Sodium Bi-Carbonate.

1.4 For Desander 8” to 12” and for desilter 4” to 6”.

1.5 Marble chips or Salt flakes.

2. Casing & Cementation

2.1 BWOC: By Weight Of Cement. BWOW: By Weight Of Water.

2.2 Calcium Chloride, Sodium Chloride.

2.3 BTC stand for:Buttress Thread Coupling. The casing joint has to be torqued up to the base of triangle.

2.4 Check for back flow to see if shoe and/or float is holding back pressure.

3. Hoisting Equipment / Mudpumps

3.1 The Crown O Matic, or crownsaver device. Setting changes after a slip/cut.

3.2 Nitrogen.

3.3 75% of the Minimum Anticipated Working Pressure of the Pump. Maximum is 750 psi.

3.4 Either the Pressurised system (Standpipe, hose connections, hoses) or the liners used in the pump.

4. Pressure control equipment

4.1 Manifold Regulator, Annular Regulator, Air pressure regulator.

4.2 To close a well in with Hydraulic Energy.

4.3 By an air driven pump and/or an electric driven pump. Switched on automatically after a drop in accumulator pressure.

4.4 The accumulator can not reach its charge pressure because there is a leak in the system. Till repairing the system, the 4 way valve of the blind rams should be put in neutral position.

Constant Bottom Hole Pressure MPD technique

2021-10-11T19:10:00.002+01:00

Managed pressure drilling can be defined as a closed path drilling technique. Unlike the conventional drilling where the mud is flowing to atmospheric pressure, in managed pressure drilling, the mud flows out of the annular space with a back pressure which is provided by MPD choke. The bottom hole pressure in managed pressure drilling is a sum of the hydrostatic pressure HP of the column of drilling fluid, annular frictional pressure AFP and the back pressure BP. The bottom hole pressure BHP with this combination can be effectively controlled by manipulating the mud flow rate or the back pressure and this lead to better well pressure management.

BHP = HP + AFP+ BP

Constant bottom hole pressure CBHP is considered as one of the most used managed pressure drilling - MPD - techniques which is based on maintaining the bottom hole pressure within a given interval under both static or dynamic conditions. Using this method helps to keep the bottom hole pressure BHP (which is composed of back pressure BP, hydrostatic pressure HP and annular frictional pressure AFP) greater than the pore pressure PP and less than the fracture pressure FP.

In most cases, the hydrostatic pressure HP provided by the mud weight used in such method is less than the pore pressure PP and the back pressure BP is regulated to bring the bottom hole pressure BHP inside safe window above the pore pressure. Among the objectives of this strategy is to overcome the kick-loss issues when drilling narrow windows environments.

Among the issues which are related to this technique is how to shift from static situation (no circulation) to dynamic situation (with circulation) or from dynamic to static without losing control on operations - facing loss or gain situation-. The tip behind this strategy is applying a back pressure BP to compensate the annular pressure AFP (loss of AFP when shutting the pumps off) while making connections or surface equipment issues. Shifting from one situation to another is performed by gradually opening or closing the MPD choke while simultaneously increasing or reducing the mud pumps speed.

Fig 1. Mud Pump Speed vs Back Pressure

This principle of keeping the wellbore pressure constant has many benefits such as avoiding drilling problems related to mud weight changes, drilling through tight pressure windows and reaching the total depth of drilling in optimized conditions.

Under this category of constant bottom hole pressure, two different methods can be applied to achieve the target: back pressure BP application and continuous mud circulation CCS. The back pressure BP method is based on using surface equipment such as MPD pump and choke (Manual or automatic) to keep the well bore pressure above the pore pressure. The CCS system is based on using a continuous circulation system that provides mud circulation when making or breaking connections so the wellbore is kept circulated during all the operations which helps to stay within the required pressure profile.

Fig 2. MPD System Layout

The automatic choke used for the back pressure application is considered more precise when drilling through narrow pressure windows. The semi-automatic or manual are less accurate and needs to be used in more or less sufficient pressure windows.

Many hydraulics models have been developed to be integrated in computer control system designed for automatic chokes. These models involves many parameters and correlations for bottom hole pressure profiles to predicts the required surface back pressure. The use of MPD choke has been supported by the MPD pump to make a surface circulating loops to maintain a continuous circulation through the choke to get to precise annular surface pressure.

The continuous circulation system was developed to help keeping the circulation during make up or break connections and consequently steady bottom hole pressure which is chosen to be inside the designed pressure profile ( between pore pressure and fracture pressure). This system can be used to prevent the drilling problems which are caused by the frequent switching on or off of the mud pumps.

Fig 3. Continous Circulating System

The continuous circulating system is composed of many parts. The three important parts are: the coupler, mud diverter and the hydraulic power unit. This system is also consisted of three preventers: upper pipe rams, middle blind rams and lower pipe rams. The principle is based on creating an isolated chamber around the connection by closing around the drill pipe. Then this chamber is pressurized by CCS mud circulation path to allow for making or breaking joints. Above the continuous circulation system, there is a snubber that helps to control the upward movement of the pipe due to the upward force generated after pressurizing the chamber. During making or breaking connection, the bottom hole pressure is kept steady and the equivalent density is not allowed to fall below the pore pressure. After making the connection, the closed chamber is depressurized and the CCS can be opened to recover operations.

we advise the audience to check the listed articles bellow for better understunding:

Managed Pressure Drilling - Basics and Definitions -

Bottom Hole Pressure Concept

Basic Pressure Definitions

Introduction to Drilling Fluids

Activity: Pressure and Friction Losses

Activity: Kick Causes - Total Loss of Circulation

Managed Pressure Drilling - Basics and Definitions -

2021-10-06T09:32:00.001+01:00

Managed pressure drilling (MPD) is presented as one the techniques that can be used to overcome the drilling problems faced when using the conventional drilling techniques. Stuck Pipe, lost circulation and well control situations can be considered as the main problems faced while drilling operations leading to high level of non-productive time (NPT) and consequently an excessive operations cost. Mainly, these problems are caused by the non-control of the annular pressure losses and here comes the role of the managed pressure drilling technique to allow for better management of the annular frictional pressure losses which contributes positively in drilling operations performance.

There are many definitions of the managed pressure drilling MPD. It can be defined as an advanced form of primary well control barrier that applies a closed and pressurizable drilling fluid system that allows precise control of the annular pressure than the conventional technique (Brainard & Al, 2006).

The IADC underbalanced operations committee has defined the MPD as the following:

Managed pressure Drilling is an adaptive drilling process used to precisely control the annular pressure profile throughout the wellbore. The objectives are to ascertain the down hole pressure environment limits and to manage the annular hydraulic pressure profile accordingly.

The managed pressure drilling can be also described through some technical notes for better illustration:

- Annular pressure profiles can be proactively managed while drilling through narrow downhole environmental limits using a collection of tools and techniques which can mitigate the risks during operations.

- Managed pressure drilling performance can include back pressure control, drilling fluid density and reology, circulating friction estimation and hole geometry profile.

- Managed pressure drilling can help to avoid formation influx and safely contains the influx in case of well control situation.

- In case of pressure deviations, managed pressure drilling technique has the ability to allow for faster corrective actions. This ability to dynamically control the annular pressures facilitates drilling operations.

The MPD is becoming popular especially for offshore projects where hydrocarbon resources are not economically drillable with the conventional drilling. The risk of facing these challenged projects increases with the water depth and it is related to many obstacles such as:

- Loss circulation

- Differential stuck pipe

- Narrow pore to fracture pressure margins

- Shallow hazards when drilling top holes

- Failure to reach the reservoir with large boreholes.

Fig 1- MPD System Layout

Managed Pressure Drilling principle

The basic behind the MPD technique is the ability to manage the bottom hole pressure profile. The bottom hole pressure in conventional drilling is calculated by combining the hydrostatic pressure of the drilling fluids and the estimated annular friction pressure. Unlike the conventional drilling, MPD applies a closed and pressurized mud system. The total bottom hole pressure in case of the MPD is a sum of the hydrostatic pressure, annular friction pressure and the back pressure applied at the surface. This principle of adjusting the back pressure helps to react quickly and accurately to maintain the required bottom hole pressure.

The basic configuration of the MPD system is consisted of rotating control device and choke manifold. The RCD is used keep the system closed and diverts flow toward the MPD choke manifold. The choke is used to generate the back pressure and allow for the pressure adjustment as required. The pressure profile is kept inside the pressure window using the automatic opening and closing of the choke.

Types of Managed Pressure Drilling

According the IADC MPD subcommittee, the MPD can be categorized into two categories: reactive and proactive.

In reactive plan, the well is designed conventionally but the MPD equipment are rigged up in order to react quickly in case for any unexpected pressure change. In this plan, the MPD equipment and technique are considered as a contingency to face any drilling problems during conventional operations. for example if any unexpected downhole pressure environments limits, at least the rig has to be equipped with rotary circulating device RCD, choke and drillstring floats to activate the MPD plan.

In proactive plan, the drilling program is designed with MPD technique to take advantage of precisely manage the wellbore pressure profile which can show many features such as:

- Optimize the casing seats and may be reducing the casing strings.

- Optimize mud density requirements and consequently the overall mud cost.

- Advanced warning signs for pressure control situations.

MPD Applications

Managed pressure drilling plan is application dependent technique. The success of the planned managed pressure drilling projects is related to the minimum of the required equipment, technology and also knowledge. Drilling industry is extending towards more challenging regions and reservoirs and facing many problems when performing operations. MPD can help to deal with such projects, for instance, depleted reservoirs, high pressure high temperature wells and extended reach wells.

Depleted reservoir drilling

Drilling through depleted zone which is above or below a high pressure formation can face loss of returns or differential sticking due to maintaining the overbalance at the high pressure formation. Drilling using the MPD technique can help to perform drilling operations effectively using the control bottom hole pressure principle. The pressure can be maintained within the required window that does not exceed the fracture pressure at the depleted zone and simultaneously can be kept overbalance at the high pressure zone.

HPHT Drilling

HPHT wells are one the most challenging wells to drill due to the high requirement of advanced planning and equipment. One of the features of the HPHT wells is the limited or low level of kick tolerance. The MPD for HPHT application is adapted with the retention of the high pressure blow preventer below the MPD control stack which can be activated or engaged when needed. Also, it can be mentioned that the use of the automated choke control system contributes effectively to perform safe HPHT drilling by compensating the bottom hole pressure variation which is related to the downhole temperature, swab / surge and drill pipe rotation. The pressure variation is compensated by adjusting the annular back pressure. The choke system is regulated using an advanced dynamic flow model which is run in real time.

Extended Reach Drilling

The extended reach well is one the types of the directional wells. It is characterized by the shallow depth of the kick off point and the great horizontal departure which can exceed at least twice the total vertical depth of the well. The features of the extended reach well have led to many operational challenges such as torque and drag, casing design and hole cleaning. Controlling the annular frictional pressure is one of the keys in the success of ERD project. The measurement of the annular pressure losses can help in the detection of the poor hole cleaning and consequently avoiding many problems such as stuck pipe. One the principle of the MPD is friction management techniques which contributes in the constant bottom pressure system.

Interactive Quiz: Well Control - Top Hole -

2021-08-05T00:08:00.003+01:00

Interactive Quiz: Well Control - Leak Off Test & MAASP -

2021-08-03T21:26:00.000+01:00

Interactive Quiz: Well Control - Static & Dynamic Pressures -

2021-07-31T21:55:00.030+01:00

Well Control Quiz: Kick Warning Signs - Part 3 -

2021-07-31T10:15:00.002+01:00

1. The crew must be prepared to act quickly and effectively if there is an influx. What is one action the crew can take in advance to minimize the volume of a potential influx?

a- Build drilling fluid volume in the active tank.

b- Continue well operations while the Pit Volume Totalizer (PVT) is offline for maintenance.

c- Run regular drills to ensure that the crew is competent.

d- Store the Drill Pipe Safety Valve (DPSV) and the crossovers in the heavy tool store.

2. Why do you conduct a trip drill when running in the hole?

a- To determine how long it will take to shut in the well.

b- To give you time to check the pipe tally and hole fill volume.

c- To give you time to safety grease the travelling block from a riding belt.

d- To provide the drill crew with training if there is a kick while tripping.

3. Which action helps to prevent swabbing?

a- Installing a Non Return Valve (NRV) in the drill string.

b- Monitoring trip tank levels.

c- Pumping a heavy slug before pulling out of the running in the hole,

d- Pumping out of the hole.

4. After a connection, the active pit level does not return to the same volume level as before the connection. What could this indicate?

a- Air was pumped into the well during the connection

b- The drilling fluid in the annulus is over loaded with cuttings

c- The vacuum degasser was left running during the connection

d- There was an influx during the connection

5. On a trip out of hole, you are about to pull non-shearable BHA components through the BOP. Before continuing, what procedures must you follow? Choose two answers

a- Confirm that the crew and the rig have the ability to follow the non-shearable shut in procedure

b- Do a flow check before non-shearable components enter the BOP

c- Function test the BOP and do a tripping well control drill

d- Have a crew tool box meeting, so that the crew pulls the non-shearable quickly

e- Secure the well before inspecting and re-testing the shear rams

6. During well operations, the drilling fluid becomes gas-cut. What is the impact on the operation?

a- This is a kick warning sign, and using the vacuum degasser may complicate pit volume measurements

b- This is a warning sign, and the well must be flow checked

c- This is a positive kick indicator, the well must be shut in before notifying the supervisor, and well pressures must be recorded

d- This is normal, and will not affect ongoing operations

7. During well operations, the drilling fluid becomes gas-cut. What action should be taken?

a- Divert the fluid to the waste mud pit, and continue the operation.

b- Notify the Supervisor and turn on the vacuum degasser.

c- Shut in the well, notify the Supervisor and record the well pressures.

d- Stop operations, flow check the well, and notify the Supervisor.

8. What is the positive indicator that the well is flowing?

a- A decrease in pump pressure

b- An increase in flow returns

c- An increase in gas-cut drilling fluid

d- An increase in torque

9. The flow sensor shows a total loss of returns and the mud level cannot be seen in the annulus. What immediate action should be taken?

a- Shut the well in and pump lost circulation material.

b- Fill the annulus with water (or lightest mud available) and record volume.

c- Pump at reduced rate adding lost circulation material.

d- Continue drilling ahead cautiously.

10. What is the main role of the Driller in preventing well control incidents?

a- Taking actions to always keep the hole full.

b- Taking actions to prevent abnormal pressures.

c- Taking actions to prevent gas cut mud.

d- Taking actions to prevent lost circulation.

11. What should the Driller do after seeing a drilling break?

a- Circulate bottoms up.

b- Flow check the well.

c- Increase the pump speed.

d- Reduce the weight on the bit.

12. What should the Driller do when kick warning signs are seen?

a- Alert the Tool Pusher and request assistance.

b- Be alert to shut the well in quickly

c- Check for flow

d- Shut the well in.

ANSWERS

1. C 4. D 7. D 10. A

2. D 5. A-B 8. B 11. B

3. D 6. B 9. B 12. C

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Well Control Quiz: Kick Warning Signs - Part2 -

2021-07-30T11:20:00.001+01:00

1. How can the Driller prevent swabbing? Choose two answers

a- Increase the viscosity of the drilling fluid

b- Pull the drill pipe fast

c- Pull the drill pipe slowly

d- Pump a slug

e- Pump out of the hole

2. If connection gas is detected, what action should be taken?

a- Flow check

b- Directly shut in the well

c- Ask the Supervisor.

3. After a round trip, the driller circulate bottom up. The mud logger noticed gases in the shale shaker area. What is the cause of this?

a- Trip gas

b- Connection gas

c- Background gas

4. You are tripping into the hole and have broken circulation. The measured gas percentage in the drilling fluid suddenly increases from 10% to 23%, before decreasing back to 10%. What type of gas is this?

a- Background gas

b- Connection gas

c- Shallow gas

d- Trip gas

5. While drilling, gas levels increased in the return flow from 8% to 9%. Which type of gas is this?

a- Trip gas

b- Connection gas

c- Background gas

6. What should be done if the shaker man / Derrick Man noticed an increase in the cutting size and the shaker is over flowing?

a- Contact the supervisor.

b- Inform the driller to perform flow check.(as this is a warning sign)

c- Open the Shaker bypass.

d- Change screen

7. While drilling, the cuttings returning to the shakers become bigger and splintered. What should you do?

a- Communicate the kick warning sign to the Supervisor.

b- Communicate the situation to the Mud Engineer.

c- Instruct the Derrickman to change the shaker screens.

d- Instruct the Shaker Hand to by-pass the shale shakers.

8. While drilling, the shape of the cuttings on the shaker changes and there is significant increase in gas percentage; while there is no increase in mud pits. What should the supervisor should do with the driller?

a- Stop drilling and perform a flow check

b- Continue drilling

c- Increase Mud density.

9. What is the best practice from the well control point of view while RIH with casing

a- Flow check every 10 joints

b- Calculate the trip sheet using closed end displacement.

c- Monitor the closed end displacement returning on the active system.

d- Use self-filing float valve, monitor that the open end displacement is returning on trip tank

10. After connection and while circulating bottom up circulation, it was observed that the return flow increase. How do you explain this?

a- Blow out

b- Connection gas

c- Swabbed Kick

11. Trip drill takes time to be done while POOH and RIH. Why trip drill should be done?

a- To make trips faster

b- To POOH pipes more than rig hoisting capacity

c- To train crew to shut in the well with safety valve.

d- To increase ROP

12. According to API, which of the following statements is true regarding a well control drill?

a- A well control drill should be announced
b- A well control drill Should be scheduled after drilling casing shoe
c- A well control drill Should be scheduled with the crew change
d- A well control drill should not be announced, so no one is aware about the time of the drill.

ANSWERS

1. C - E 4. A 7. A 10. B

2. A 5. C 8. A 11. C

3. A 6. B 9. D 12. A

Well Control Quiz : Kick Warning Signs - Part 1 -

2021-07-29T18:14:00.002+01:00

1. While drilling a head through a faulted formation, the flow meter drops from 50% to 42% What is the most likely cause of this?

a- A swabbed kick on last connection.

b- A washout in the drill string.

c- Partial lost circulation

d- Total lost circulation.

2. Which are warning signs of abnormal pressure at when there is constant rotary RPM, constant weight on bit (WOB) and constant pump rate? Choose three answers

a- A change in the shape of the cuttings at the shakers

b- A decrease in flow line temperatures

c- A drop in active tank level

d- An increase in pump pressure

e- An increase in trip tank level

f- Increased connection gas in returns

g- Varying penetration rate

3. What should the driller do when connection gas is detected? Choose two answers

a- Control the drilling rate so that only one slug of connection gas is in the hole at any time

b- Increase the yield point in the active system

c- Minimize the time during a connection when the pumps are switched off

d- Pull out the hole to change the drilling bit

e- Pump a low viscosity pill to reduce balling of bit and stabilizers

4. After a connection, the gas alarm sounds after bottoms-up strokes. Which type of gas is this?

a- Background gas

b- Connection gas

c- Drilled gas

d- Recirculated gas

5.During the trip out of the well, and with the drilling bit 1200 ft from bottom, the hole failed to take the calculated volume of drilling fluid from the trip tank, there is no flow from the well What is the next step that should be taken?

a- Pump remaining stands out of the hole.

b- Flow check, if negative continue to pull out of the hole.

c- Shut the well in and circulate hole clean.

d- Flow check, if negative run back to bottom and monitor returns.

6. After pulling ten stands out of the hole, the fluid it takes to fill the hole from the tank is less than calculated on the trip sheet. What action is required?

a- Flow check. If there is no flow, continue to pull out of the hole to surface

b- Flow check. If there is no flow, displace a heavy slug into the annulus and continue to pull out of hole

c- Flow check. If there is no flow, run back to bottom while monitoring returns

d- Pump the remaining stands out of the hole

7. When tripping out of the hole using a trip tank, which factors could indicate a possible influx to the Driller? Choose two answers

a- The hook load decreases as each stand is pulled

b- The trip tank level falls less than expected for each pulled stand

c- The trip tank level falls more than expected for each pulled stand

d- When pulling pipe, the flow meter in the flowline shows an increase flow

e- With no pipe movement, the trip tank level increases

8. During a trip 15 stand of dry pipe have been pulled out, the volume of drilling fluid use to fill the hole was 8.2 bbl.

Well data:

Well depth: 5800 ft

Stand Length: 90 ft

Drill pipe Capacity: 0.01782 bbl/ft

Drill pipe metal displacement: 0.0082 bbl/ft

Drilling mud density: 11.2 ppg

Select the correct action from the following list.

a- The volume is not corrected due to swabbing but as long as the well is stable continue to pull out.

b- Continue to pull out since the situation seems to be under control.

c- Start pumping high density drilling mud in to the annulus.

d- An influx has been swabbed in, check for flow, if no flow, trip back to bottom while monitoring displaced volume and carefully then circulate bottom up.

9. After pulling 10 stands of pipe, a well takes less fluid than expected. The driller completes a flow check and confirms the well is not flowing. What should the driller do next?

a- Because the well is not flowing, continue pulling pipe from the hole.
b- Establish if there has been an influx by running back to bottom and circulate bottom up
c- Pull another 10 stands and flow check.

d- Shut-in the well immediately and check for pressures.

10. While tripping out of the hole, the well starts flowing. What is the first action to take?

a- Close the annulus and then make up the top drive

b- Pull back to shoe

c- Run back to bottom as quickly as possible

d- Stab in a Drill Pipe Safety Valve (DPSV) in the drill string and shut the well in.

ANSWERS

1. C 4. B 7. B-E 10. D

2. A.F.G 5. D 8. D

3. C 6. C 9. B

Well Control: Principles and Procedures - Leak Off Test and MAASP -

2021-07-28T10:04:00.001+01:00

1. When drilling into new formation, the formation pressure increases. To maintain a reasonable overbalance on bottom, the drilling fluid density is increased. How will this affect the MAASP?

a. The MAASP will decrease.

b. The MAASP will increase.

c. The MAASP will stay the same.

2. When should MAASP be recalculated?

a- After changing the mud density

b- After each drilling bit change

c- At the beginning of each shift

d- Immediately before entering a pay zone.

3. Which critical pressure is calculated using the results of the Leak-Off Test (LOT)?

a- Dynamic Casing Pressure

b- Final Circulating Pressure (FCP)

c- Initial Circulating Pressure (ICP)

d- Maximum Allowable Surface Pressure (MAASP)

4. Which parameter would affect the Leak-off Test (LOT) pressure?

a- The fluid pump circulating rate for the next drilling operation

b- The hydrostatic pressure at the casing shoe

c- The pressure limit for the fluid pump

d- The volume of the fluid in the annulus from the casing shoe to surface

5. Which of the following need to be known for a leak-off test to be correct? (TWO ANSWERS)

a. The mud density in the well.

b. The volume of mud in the annulus from casing shoe to surface.

c. Slow circulating rate.

d. The pressure limit for the mud pump.

e. Mud hydrostatic pressure in the casing annulus.(TVD)

6. What is one condition that must be achieved to complete a successful Leak-Off (LOT)?

a- The casing pressure test value will equal to the LOT value

b- The hole must be drilled to Total Depth (TD)

c- The Initial Circulating Pressure (ICP) must be used

d- The drilling fluid must be conditioned

7.Which information do you need for an accurate Leak Off Test (LOT). Choose two answers.

a. The fluid density in the well.

b. The fluid pump circulating rate for the next drilling operation.

c. The pressure limit for the fluid pump

d. The True Vertical Depth (TVD) of the casing shoe.

e. The volume of fluid in the annulus from casing shoe to surface

8.When performing a Leak-Off Test (LOT), which parameter must be accurately measured and recorded?

a. Fluid volume in open hole, density of the fluid used, and the True Vertical Depth.

b. Fluid volume in the casing, and Measured Depth (MD).

c. Pumping time until the leak-off, and the Measured Depth (MD).

d. Fluid volume pumped, density of the fluid used, and True Vertical Depth.

ANSWERS

1. A 4. B 7. A-D

2. A 5. A-E 8. D

3. D 6. D

Well Control: Principles and Procedures - Top Hole -

2021-07-26T10:09:00.000+01:00

1. Formation strengths are generally weak when drilling top hole and total losses may occur. How can the risk of total losses be reduced when drilling top hole?

a. By pumping slowly to reduce the drill string pressure loss.

b. Keeping a high overbalance.

c. By controlling penetration rate to prevent loading the annulus with cuttings.

d. Reduce the Mud weight as possible to reduce the risk of formation fracture

2. What is one good operating practice to help to minimize well control problems while drilling top-hole section?

a- Maintain a high drilling rate

b- Maintain a high over-balance in the drilling fluid to avoid going under-balance

c- Maintain the drilling fluid density as low as possible to prevent formation fracture

d- Maintain very high tripping speeds when running in or out of the hole

3. Which of the following statements are good operating practices when drilling TOPHOLE formations where there is a risk of shallow gas? (TWO ANSWERS)

a. Maintain high rate of penetration and keep mud viscosity as high as possible.

b. Use a heavy weight mud to create maximum overbalance.

c. Pump out of the hole on trips.

d. Use oil-based mud.

e. Drill a pilot hole at a controlled rate.

4. During top hole drilling from a jack-up rig, the well starts to flow due to shallow gas. What will be the safest action to take to secure the safety of the rig and personnel? (TWO ANSWERS)

a- Start pumping mud into the well at the highest possible rate.

b- Activate the diverter system and remove non-essential personnel from the rig floor.

c- Shut in the well and prepare for kill operation.

d- Activate the blind/share ram to shut in the well.

e- First, line up to the mud/gas separator, close the diverter and send personnel from the rig floor.

5. When drilling top hole with a risk of shallow gas, which actions are considered good practice? (TWO ANSWERS)

a- Drill a pilot hole at a slow controlled rate.

b- Maintain high Rate of Penetration (ROP) so that fluid viscosity is as high as possible.

c- Pump out of the hole while tripping

d- Regularly pump a fresh water pill to clean cuttings from the hole.

e- Use heavy density fluid to create maximum overbalance

6. When top hole drilling, a well starts to flow due to shallow gas. What is the safest action to take to secure the safety of rig and personnel?

a- Activate the blind/shear rams to shut in the well

b- Activate the diverter system, and remove non-essential personnel form the rig floor and hazardous areas.

c- Line up the Mud Gas Separator, (MGS), activate the diverter system and remove personnel from the rig floor

d- Shut in the well and prepare for kill operations immediately

7. If a shallow gas flow is detected, which action is required as the flow is diverted?

a- Decrease the pump rate

b- Increase the pump rate

c- Maintain the pump rate

d- Stop pumping

8. Is it true that shallow gas kicks are easier to handle than those taken when drilling deeper?

a. Yes.

b. No.

ANSWERS

1. C 4. A-B 7. B

2. C 5. A-C 8. B

3. C-E 6. B

Well Control: Principles and Procedures - Static and Dynamic Pressures

2021-07-25T11:20:00.000+01:00

1. Which one of the following will affect Bottom-hole pressure (BHP) while circulating at a constant flow rate (TWO ANSWERS)

a- Mud density

b- Annulus pressure loss

c- Pump pressure

d- Pressure loss through the drilling bit nozzles

2. The equivalent circulating density (ECD) determines the actual bottom hole pressure while circulating. Which part of the system pressure losses contributes to the ECD?

a- The pressure loss in the surface system

b- The pressure loss over the nozzles

c- The pressure loss in the drill string

d- The pressure loss in the annulus

e- The pressure loss in the open hole section only

3. The Driller pumps a heavy slug and displaces it to the drill pipe with active pit fluid. What effect will this have on the fluid pits after disconnecting the top drive?

a- Decrease in volume

b- Increase in volume

c- No change in volume

4. During normal drilling operations, 20 bbl of light fluid is pumped into the string followed by original mud. With the light fluid inside the drill pipe, the Driller shuts down the pumps to monitor the well. What happens to the Bottom Hole Pressure (BHP)?

a- The BHP pressure will increase, and the back pressure will show on the drill pipe pressure gauge.

b- The BHP pressure will remain the same, but a back pressure will show on the drill pipe pressure gauge

c- The BHP will decrease, and there will be no back pressure showing on the drill pipe pressure gauge.

5. Which factors will affect Bottom Hole Pressure (BHP) while circulating at a constant flow rate? Choose two answers

a- Annulus pressure losses

b- Drill string pressure loss.

c- Drilling fluid density

d- Pressure losses through the drilling bit nozzles

e- Pump pressure

6. The pit level increases when the pumps are off, but the pit level stays constant when the pumps are running. What could be the problem?

a- The hydrostatic pressure is greater than the formation pressure.

b- Annular pressure losses are creating an overbalance that prevents the well from flowing.

c- The pump pressure is greater than the hydrostatic pressure.

d- The pumps have failed

7. If light pill is pumped in the drill string and followed by 10 bbls original mud, What can it lead to after disconnect the Top Drive/Kelly if the light pill doesn’t come out from the nozzles ? (NO FLOAT VALVE IN THE STRING)

a- Reduction in the bottom hole pressure

b- Increase in the overbalance

c- Nothing will happen

d- Back flow from the drill string

8. With the pumps running continuously a heavy mud pill is circulated. When will bottom hole pressure start to increase (ignore dynamic pressure losses in the well)?

a. Once all the pill is in the annulus.

b. Once the pill starts to be displaced into the annulus.

c. As soon as the pill is pumped into the drill string.

d. Once all the pill is inside the drill string and is about to exit the drilling bit.

9. What is the reason for having a trip margin?

a- To allow for a level drop in the well if there are losses.

b- To compensate for possible swabbing effects during pulling out of the hole.

c- To create a safety margin in case the trip tank readings are inaccurate.

d- To create an overbalance when back on bottom drilling.

ANSWERS

1. A-B 4. B 7. D

2. D 5. A-C 8. B

3. B 6. B 9. B

Well Control: Principles & Procedures - Barriers -

2021-07-24T18:55:00.002+01:00

1. What is the main purpose of BOP equipment?

a- To provide a hydraulic barrier against unplanned flow between the drillstring and casing

b- To provide a mechanical barrier against unplanned flow to surface during well operations

c- To provide a mechanical barrier to prevent dropped objects falling into the well

d- To provide a mechanical seal to pressure test the casing and wellhead.

2. What type of well barrier elements are required to form a barrier envelope?

a. A combination of well barrier elements that prevent flow to the environment or to an open formation.

b. A combination of well barrier elements to prevent flow into open formation.

c. Several BOP rams to prevent flow to the environment.

d. The wellhead, casing and cement in a well

3. What is the meaning of well-barrier envelope?

a. All Mechanical barrier.

b. Use the mud with surface pressure to prevent intrusion of formation fluids to the well.

c. It is a combination of barriers that prevent the intrusion of formation fluids to the well, to another formation or to the atmosphere

d. The use of over balance to prevent intrusion of formation fluid to the well.

4. Which correct action should be taken if a well barrier fails while testing, as per API Standard RP 53?

a. Tightening, Repair or any other work must be done under pressure then retest it again.

b. It is not important neither to pressure test this barrier after fixing the problem nor the corrective action.

c. Bleed off pressure to half pressure, repair and pressure test it.

d. Tightening, Repair or any other work must done only after verification that all pressure is released and all parties are agreed that no chance of trapped pressure.

5. What should you do if an annular BOP fails its pressure test?

a- No action is required if the rams are successfully tested.

b- You do not need to retest it until the next planned test date

c- You should remove the annular from service

d- You should repair it immediately and then re-test it

6. Who is authorized to sign the test chart?

a. Mechanic

b. Pump operator, drilling contractor representative and operator represantative.

c. BOP engineer

d. Electrician

e. Driller or Senior Tool Pusher

7. Which of the following is necessary to maintain primary well control during tripping?

a- The hydrostatic pressure exerted by the drilling mud column must remain higher than the formation pressure

b- Mud pumps must be in good working order

c- A minimum of one inside blowout preventer (IBOP) must be available on the drill floor

d- The level in the active tank must be constant

8. From A well control point of view, what is the primary reason for performing a check trip followed by bottoms up circulation?

a. To verify that the pressure surge during the running in of the pipe will not lead to lost circulation

b. To reduce the thickness of the filter cake

c. To cool the drilling bit

d. To verify that the primary well control can be maintained during the pulling of the pipe.

9. What is the correct definition of “primary well control” during normal drilling operation?

a- Preventing a kick by maintaining drilling mud hydrostatic pressure equal to or greater than formation pressure.

b- Preventing the flow of formation fluid into the well bore by maintaining the sum of drilling mud hydrostatic pressure and dynamic pressure loss in the annulus equal to or greater than formation pressure.

c- Preventing the flow of formation fluid into the well bore by keeping the dynamic pressure loss in the annulus equal to or greater than formation pressure.

d- Preventing the flow of formation fluid into the well bore by using BOP equipment when the hydrostatic pressure in the well bore does not balance or exceed the formation pressure.

10. Which statement describe the secondary well barrier?

a- A secondary well barrier is the secondary object that prevents flow from a source

b- A secondary well barrier will not prevent flow from a source

c- A secondary well barrier controls the closure of blow out preventer

d- A secondary well barrier is the first object that prevents flow to well bore.

11. Pressure has built up between two casing strings in a well, a poor cement job has been performed on the inner casing string, what could the consequences of this pressure build-up be? (THREE ANSWERS)

a- The inner casing could collapse

b- The ECD will increase

c- These could be different sticking

d- The formation below the outer casing shoe could fracture

e- The outer casing could burst

12. A cement bond log (CBL) showed that there is a bad cement job between two casing strings. What is the immediate effect of a bad cement job?

a- The inner casing could collapse

b- The ECD will increase

c- These could be different sticking

d- The formation below the outer casing shoe could fracture

e- The outer casing could burst

ANSWERS

1. B 5. D 9. A

2. A 6. B 10. A

3. C 7. A 11. A-D-E

4. D 8. D 12. A-D-E

Drill Pipe: Descriptions and Specifications

2021-02-18T19:38:00.002+01:00

The drill pipe can be classified according to many parameters such as length, diameter, weight, upset and grade of steel. There are many factors which can influence drill pipe selection:

- Hole size

- Circulating and drilling parameters

- Casing and cementing requirements

- Hole size

- Hoisting capacity

- Pipe availability

Drill Pipe Size and Weight

The drill pipe can be available in three length ranges:

- Range 1 ( 18-22 ft )

- Range 2 ( 27-30 ft )

- Range 3 ( 38-45 ft )

Range 2 is the most commonly used.

Drill Pipe Strength

The strength of the drill pipe can be defined according to:

- Pipe body yield strength: it can be presented by the resistance of the pipe body to the axial tension

- Collapse Resistance: it is presented by the ability of the drill pipe to resist to the external pressure

- Internal yield pressure: it represents the ability of the pipe to withstand the internal pressure

- Torsional Yield: it is the resistance to the torque

The level of these types of strength is related to the grade of steel used to manufacture the pipe and other parameters such as the drill pipe size and weight per unit of length.

Drill Pipe Upset

The drill pipe can be also categorized according to its upset area ( shape of pipe at the ends). The upset area is thicker than the rest of the pipe to allow for the welding on the tool joints. The upset can be internal, external or internal-external upset. The upset used in the welding area depends on the pipe diameter.

In an internal upset, the required welding area thickness is provided by decreasing the pipe inside diameter at the upset area, the outside diameter remains the same.

In an external upset is got by increasing the pipe outside diameter at the upset area, the inside diameter remains the same.

In an internal-external upset, extra wall thickness at the upset area is reached by decreasing the inside diameter and increasing the outside diameter.

Fig 1- Drill Pipe Upset Types

Tool Joints

Tools joints are the thickest and the strongest part of the drill pipe joints. They can be defined as pin-box connections with rounded threads and they are manufactured separately from the drill pipe body. The tool joints, at later stage, will be welded on the upset area. The most important parameter when designing the tool joint is the torsional yield strength because the most common problem which tool joints can face is the thread damage. The tool joint performance specifications should include the torsional yield strength and the recommended make up torque required for connections which is related to the type, size, outside diameter, inside diameter and the tool joint condition.

Fig 2 - Pin and Box Tool Joints

There are many types of tool joints such as internal flush (IF), full hole (FH) and slim hole (SH).

The tool joints can be identified by a code contains 5 information stenciled at the pin connection (Example: ZZ 6 70 N E ). The information are represented as follows:

- First marking designates the company which has manufactured the tool joint

- Second marking indicates the month of fabrication of the tool joint

- Third marking indicates the year of fabrication

- Fourth marking is the code of the pipe body manufactureur

- Fifth marking is the pipe grade code ( example: E, X-95,G-105,S-135 )

FIG 3 - Tool Joint Marking

Drill Pipe Fatigue failure

The drill pipe while drilling operations is subjected to many forces and stresses and can fail when the stresses are greater at a certain limits. The steel is weaker under dynamic conditions than static conditions but it is capable of resisting to dynamic loading or cycles of stresses for unlimited cycles if the forces are below a certain limit which is called the endurance limit.

Fatigue failure can be defined as the failure which is caused by the cyclic stresses. The fatigue failure happens progressively, it starts like a submicroscopic cracks which increase gradually till becoming visible cracks. The drill pipe failure can be recognized as a circumferential damage. As a rule of thumb, the fatigue strength can be roughly estimated as the half of the tensile strength. The drill pipe during operations is under many types of loading: tension, compression, torsion and bending. The failure can be due to one or a combination of these loadings.

Drilling directional wells can increase the risk of drill pipe failure due to the high level of cyclic stresses applied on it. One portion of drill pipe shifts from tension to compression while rotating the drill string. These cycles of tension-compression and with the contribution of the bending increases the risk of failure.

Drill Pipe and Tool Joints Inspection

The Drill pipe specifications are very important but cannot give us information about the pipe condition and for this reason a physical inspection is crucial in drilling operations. The inspection can be simple as visual inspection to more sophisticated inspection using a sonic and gamma ray tools.

Fatigue is considered as the main source of drill pipe failure. It can be defined as the failure originates from a cyclic or fluctuating stresses at maximum values (less than the tensile strength of the used metal). These stresses are caused by bending, torsion, vibration and tension and can be increased by corrosion and erosion.

Drill pipe inspection can involve:

- Magnetic particle inspection to locate cracks

- Measurement of wall thickness

- Outside diameter measurement

Tool joints inspection involves:

- Outside diameter measurement

- Checking shoulders and looking for any type of wear

- Checking the thread profile and looking for any over torqued areas and galled threads.

Introduction to Drilling Fluids Additives

2021-01-21T13:23:00.011+01:00

The drilling fluids have an important role in oil and gas drilling process. They have many functions such as hole cleaning, bit lubrication, pressure control, wellbore stability and many other functions. The cost of the drilling fluids in the overall cost of drilling project can reach 15% of the budget. Controlling the drilling fluids properties is the key in keeping drilling fluids efficient for the project targets. There are many additives can be used in the drilling industry to control the drilling fluids properties. Most common additives categories will be discussed below.

Weighting Materials

Weighting materials or density control additives are used in the drilling fluids system in order to increase the mud weight to the required level needed for safe operations. There are some features of the weighting materials which should be taken in consideration:

- Chemical inertness

- Specific gravity

- Availability in large quantities

- Easy to be grounded to the required particle size

- Limited abrasiveness

- Safe for drilling crew and equipment

Related the factors mentioned above, the barite is the most recommended weighting materiel used in the drilling industry. It has a specific gravity at 4.5, it is virtually insoluble in water and it does not react with other mud components. There are other good candidates for weighting materials such as the calcium carbonates , hematite and ilmenite.

Fig 1 - Barite Sacks

Viscosifiers

This type of additives defines the level of the viscosity of the drilling fluids. The suspension ability of the drill cuttings and weighting materials is related to the viscosity of mud. Missing the appropriate viscosity can lead to solids settlement when the circulation is ceased. The increasing pressure losses in the circulating system can be a straightforward indication of an increased viscosity. Clays can be used as viscosifier due to their feature of developing plasticity, the most used clay is bentonite.

Bentonite is classified as sodium bentonite or calcium bentonite depending on the dominant exchangeable cation and in terms of performance it is classified as high yield and low yield bentonite. Bentonite can be added to the fresh water for many reasons such as:

- Increase hole cleaning capability

- Reduce water seepage

- Form thin filter cake of low permeability

- Avoid loss of circulation

Attapulgite is another viscosifier which is also used in drilling fluids due to its ability to retain excellent viscosity and yield strength when mixed with salt water. The suspending property of attapulgite is not affected by the dissolved salt. In fact higher viscosity can be produced in saturated sodium chloride solution. Attapulgite has no filtration control and this can be positive or negative feature depending on the application. It can be a drawback when drilling through porous and permeable formations which can shows high water loss, but this feature can be an advantage when using the attapulgite in high filtration slurries to cure loss of circulation.

Organic polymers have many functions such as reducing filtration, stabilizing shales, increasing drill cuttings carrying capacity and flocculating drilled solids and they can be also used as viscosifiers. Polymers are chemicals composed of chains made up of many similar small units or groups of atoms called monomers consisting mainly of carbon compounds. The organic polymers have a high level of water affinity and they develop high swollen gels in low concentration.

Organic polymers which are used in drilling fluids can be roughly classified according to their origin and composition. Some are naturel and ready to be used after simple processing, others require more complex process and can semi-synthetic or purely synthetic. There are many factors which can affect the choice of polymers for instance: effect of shear conditions, temperature, dissolved salt, time of use of polymer, ease of preparation, environmental effects and polymer cost.

Filtration Control and Mud Conditioning Additives

These additives can be also called thinners and they are added to drilling fluids system to reduce flow resistance and gel development. According to experience, it has been proven that some of these thinners deliver other important functions in addition to improving the flow properties of drilling mud. They can be used to control the filtration, reduce the filter cake thickness, counteract the effect off salt, minimize the water effect on the formation, emulsify oil in water and stabilize mud properties at elevated temperature.

Filtration control compounds are additives used to reduce the amount of fluids that can flow from the drilling fluids into the formation due to the differential pressure between the exerted hydrostatic pressure and formation pressure.

Lost Circulation Material

Loss circulation is one of the drilling problems which can lead to very complicated situation such as well control situation. Curing the losses depends on the severity of the mud losses; they can be cured by reducing the flow rate to minimize the ECD effect for the very low rate losses or seepage till performing a cement job for high level of losses. One of the techniques to deal with the mud losses is pumping lost circulation materials LCM which can be used to plug the region from where the drilling fluids are lost.

The most common LCM can be classified as flaky (ex: cellophane & Mica), granular (ex: nut shells & calcium carbonate) or fibrous (ex: leather); related to the size they can be classified as fine, medium and coarse LCM. The LCM can be pumped down hole as LCM plugs with reduced flow rate to minimize the mud losses till getting the LCM at the thief zone or they can be diluted in the active system.

Fig 2 - Loss Circulation Material ( Courtesy of Prince International Corporation )

Surfactants

Surface active agent or surfactant is a substance which can build an interface between two dissimilar phases and diminishes the surface tension between them. The surfactant can be defined as an organic compound which its molecular structure is made of two dissimilar groups having opposing solubility tendencies.

Surfactants are used in drilling fluids systems for many reasons. They can be used as emulsifiers in oil based muds. For water based muds, the surfactants can serve many applications such as: shale swelling inhibitors, prevent cuttings sticking, wetting agents and corrosion inhibitors.

PH Control Additives

The PH level can affect many drilling fluids properties such as the solubility of many thinners. PH control is required for prevention of corrosion and hydrogen embrittlement. The desired level of PH in drilling fluids lies between 9.5 to 10.5. NaOH and KOH are some additives which can be part of the drilling system to control the alkalinity and PH.

Drilling Course

Differential Stuck Pipe Mechanism: Causes and Solutions

Functions of Drilling Fluids

1. Hydrostatic Pressure

2.Cuttings Transport and Hole cleaning

3.Filtration Control

4.Mechanical Stability

General Questions With Answers - 9 -

General Questions With Answers - 8 -

General Questions With Answers - 7 -

General Questions With Answers - 6 -

General Questions With Answers - 5 -

General Questions With Answers - 4 -

General Questions With Answers - 3 -

Answers

General Questions With Answers - 2 -

1.Stuck pipe and Fishing

2. Directional Drilling

1. Stuck pipe and fishing

2. Directional drilling

General Questions With Answers - 1 -

1. Drilling Fluids

2. Casing & Cementation

3. Hoisting Equipment / Mud pumps

4.Pressure control equipment

1. Drilling Fluids

2. Casing & Cementation

3. Hoisting Equipment / Mudpumps

4. Pressure control equipment

Constant Bottom Hole Pressure MPD technique

Managed Pressure Drilling - Basics and Definitions -

Managed Pressure Drilling principle

Types of Managed Pressure Drilling

MPD Applications

Interactive Quiz: Well Control - Top Hole -

Interactive Quiz: Well Control - Leak Off Test & MAASP -

Interactive Quiz: Well Control - Static & Dynamic Pressures -

Well Control Quiz: Kick Warning Signs - Part 3 -

Well Control Quiz: Kick Warning Signs - Part2 -

Well Control Quiz : Kick Warning Signs - Part 1 -

Well Control: Principles and Procedures - Leak Off Test and MAASP -

Well Control: Principles and Procedures - Top Hole -

Well Control: Principles and Procedures - Static and Dynamic Pressures

Well Control: Principles & Procedures - Barriers -

Drill Pipe: Descriptions and Specifications

Drill Pipe Size and Weight

Drill Pipe Strength

Drill Pipe Upset

Fig 1- Drill Pipe Upset TypesTool Joints

Drill Pipe Fatigue failure

Drill Pipe and Tool Joints Inspection

Introduction to Drilling Fluids Additives

Weighting Materials

Viscosifiers

Filtration Control and Mud Conditioning Additives

Lost Circulation Material

Surfactants

PH Control Additives

Fig 1- Drill Pipe Upset Types

Tool Joints