7/12/081

CAUSES OF KICKS

7/12/082

Causes Of Kicks

The main causes of kicks are:

1: Failing to ensure that the hole takes the correct amount of mud when tripping out.

2: Swabbing in a kick while tripping out.

3: Insufficient mud weight.

4: Abnormal formation pressure.

PresenterPresentation NotesThe main causes of kicks are: 1:Failing to ensure that the hole takes the correct amount of mud when tripping out.2:Swabbing in a kick while tripping out.3:Insufficient mud weight.4:Abnormal formation pressure.

7/12/083

CAUSES OF KICKS

main causes of kicks are:5: Lost circulation

6: Shallow gas sands

7: Excessive drilling rate in gas bearing sands.

8: Human error.

9: Failing to ensure that the hole returns the correct amount of mud when tripping in.

PresenterPresentation NotesContinue the main causes of kicks are:5:Lost circulation

6:Shallow gas sands

7:Excessive drilling rate in gas bearing sands.

8:Human error.

9:Failing to ensure that the hole returns the correct amount of mud when tripping in.

7/12/084

Well Control

CAUSES OF

KICKS

Swabbing in a kickThe principal factors that

contribute to swabbing are:

Pipe Pulling Speed, it takes more energy to move mud quickly, so the faster the string is moved upward, the greater the pressure drop (swab pressure).

Cause is movement

PresenterPresentation NotesSwabbing in a kickThe principal factors that contribute to swabbing are:Pipe Pulling Speed, it takes more energy to move mud quickly, so the faster the string is moved upward, the greater the pressure drop (swab pressure).

7/12/085

Well Control

CAUSES OF

KICKS

Swabbing in a kickThe principal factors that contribute

to swabbing are:

Small Annular Clearance, or Slim Hole Geometry, it takes more energy to move the same volume of mud through a smaller space, so the less the annular space available, the greater the pressure drop (swab pressure).

PresenterPresentation NotesSwabbing in a kickThe principal factors that contribute to swabbing are:Small Annular Clearance, or Slim Hole Geometry, it takes more energy to move the same volume of mud through a smaller space, so the less the annular space available, the greater the pressure drop (swab pressure).

7/12/086

Well Control

CAUSES OF

KICKS

Swabbing in a kick

High Mud Viscosity, or Gel Strength, it takes more energy to move a thick mud than a thin one, therefore the more viscous the mud, the greater the pressure drop (swab pressure).

Balled up Bit or Stabilizers, the BHA becomes surrounded by clay or sticky shale and the diameter of the bit or stabilizers are enlarged and act like pistons as they are pulled from the hole.

7/12/087

Shale hydration Rig Site Indications1. Soft , hydrated or mushy cuttings at shale shakers

2. Clay balls in the flowline.

3. Shale shaker screens blind off

4. Increase in LGS, filter cake thickness, PV, YP and MBT

5. Increase or fluctuations in pump pressure

6. Circulation is restricted or sometimes impossible

7. Bit and stabiliser balling when POH

8. Mud rings which may also be seen at the shale shaker

9. Generally occurs while POH (Tight hole) and problems while logging

10. Problems increase with time.Video mud rings

PresenterPresentation NotesShale hydration Rig Site IndicationsThe following are the main indications you see at the rig site when you have swelling or sloughing shale problems:

Soft , hydrated or mushy cuttings at shale shakersClay balls in the flowline. Sometimes the flow gets blocked and requires cleaningShale shaker screens blind off and require cleaning by a strong water jetIncrease in low gravity solids (LGS), filter cake thickness, PV, YP and MBTIncrease or fluctuations in pump pressureCirculation is restricted or sometimes impossibleBit and stabiliser balling when POHMud rings which may also be seen at the shale shaker ( Animator :please show animation of mud rings, see CD)

Generally occurs while Pulling out of hole when the hole is observed to be very tight. Similar problems occur while loggingShale problems always get worse with time as the shale has absorbed a large volume of water causing it to expand and slough into the wellbore.

7/12/088

PresenterPresentation NotesAnimator: please show this picture after point 7

7/12/089

Bit balling occurs whilst drilling reactive shales which exhibit plastic properties

The Problem occurs when using poorly inhibited water-based muds

In these muds drilled shale particles adhere to the face of the drillbit, stabilisers and drillcollars.

Bit Balling

Rig Site Indications: Reduced ROP as the bit cutting face is completely covered with a cake Increased pump pressure due to reduced annular diameter Blocked shaker screens with soft clays Overpull on trips

PresenterPresentation NotesBit balling occurs whilst drilling reactive shales which exhibit plastic properties. Theproblem occurs in poorly inhibited water-based muds when drilled shale particles adhere tothe face of the drillbit, stabilisers and drillcollars.

In practice bit balling can be recognised by:

Reduced ROP as the bit cutting face will be completely covered with a mud all preventing the cutting structure from contacting the bottom of the hole Another indication of bit balling is Increased pump pressure due to reduced annular diameter because of the large volume of shale cuttings and sloughed shale A good surface indicator of bit balling is when the shaker screens are blocked with soft clays Finally, Overpull on trips is another good indicator of shale swelling and bit balling

Bit balling can be prevented by using inhibited mud systems which prevent the dispersion ofthe clay plates. If bit balling is observed while drilling, a detergent is usually added todisperse the balled clays. The use of a small percentage of glycol also helps to reduce bitballing.

Bit balling rarely occurs in oil-based muds, but when it occurs, the cure is achieved byincreasing the mud salinity in order to draw moisture from the shale and increase itshardness.

7/12/0810

Well Control

The likelihood of swabbing in a kick can be reduced by good drilling practices, including use of an adequate trip

margin. These include: Circulating the hole clean before starting a trip. Noting the pressure and position of tight-spots from previous

trips. Conditioning the mud to as thin a condition as well

circumstances permit. Controlled pipe-pulling speeds. Pumping out of hole on trips.....why??? Calculating the correct swab and surge pressure prior to a

trip.

PresenterPresentation NotesThe likelihood of swabbing in a kick can be reduced by good drilling practices, including use of an adequate trip margin. These include:Circulating the hole clean before starting a trip.Noting the pressure and position of tight-spots from previous trips.Conditioning the mud to as thin a condition as well circumstances permit.Controlled pipe-pulling speeds.Pumping out of hole on trips.Calculating the correct swab and surge pressure prior to a trip.

7/12/0811

Well Control

Surge & Swab

PresenterPresentation NotesHer we see the difference between running in and pulling out. The so called swab and surge pressures.

7/12/0812

CAUSES OF KICKS

o 0 to a: the swab pressure generated pulling the pipe out of the slips.

o a to b: the pressure required to break the gels in the drilling fluid as the pipe is lowered in to the well.

o b to c: minimum pipe velocity is reached.

o c to d: maximum pipe velocity is reached.

o d to e: negative surge pressure is reached as the drillstring is stopped and set in the slips.

PresenterPresentation NotesA typical graph showing the pressure changes during pipe movement.

7/12/0813

Well Control

CAUSES OF

KICKS

LC

PresenterPresentation NotesDue to surge pressures the formation can break and losses can be introduced.

7/12/0814

Well Control

KICK INDICATORS

Kicks can be divided into two groups:

1:Positive indicators of a kick in progress.

2:Warning signs of approaching balance or underbalance.

PresenterPresentation NotesKicks can be divided into two groups: 1:Positive indicators of a kick in progress.2:Warning signs of approaching balance or underbalance.

7/12/0815

KICK INDICATORS

SURFACE INDICATIONS OF RISING FORMATION PRESSURE

Drilling rate, sometimes using 'd' exponent trends.

Increasing torque and drag, possible fill on connections.

Total gas levels/gas cut mud.

PresenterPresentation NotesSURFACE INDICATIONS OF RISING FORMATION PRESSURE

Drilling rate, sometimes using 'd' exponent trends.

Increasing torque and drag, possible fill on connections.

7/12/0816

KICK INDICATORS

SURFACE INDICATIONS OF RISING FORMATION PRESSURE

Increasing mud flowline temperature.

Mud flow properties.

Mud salinity.

Shale density, cuttings size shape and volume.

PresenterPresentation NotesSURFACE INDICATIONS OF RISING FORMATION PRESSURE

Increasing mud flowline temperature.

Mud flow properties.

Mud salinity.

Shale density, cuttings size shape and volume.

7/12/0817

KICK INDICATORS

SURFACE INDICATIONS OF RISING FORMATION PRESSURE

Heaving shales.

Shale type.

ECD drilling.......????

PresenterPresentation NotesSURFACE INDICATIONS OF RISING FORMATION PRESSURE

Heaving shales.

Shale type.

ECD drilling.

7/12/0818

POSITIVE KICK INDICATORS

An increase in return flow from the wellbore

An unexpected pit level increase

PresenterPresentation NotesPOSITIVE KICK INDICATORS

An increase in return flow from the wellbore

An unexpected pit level increase

7/12/0819

POSITIVE KICK INDICATORS

An increase in return flow from the wellbore

An unexpected pit level increase

PresenterPresentation NotesPOSITIVE KICK INDICATORS

An increase in return flow from the wellbore

An unexpected pit level increase

7/12/0820

Typical Flow Checks would be made but not limited to: Prior to commencing trip out of the hole. After pumping heavy pill. At anytime during the trip in the open hole where

volumes are in doubt. When the bit enters the casing shoe.

Flow Check

PresenterPresentation NotesTypical Flow Checks would be made but not limited to:Prior to commencing trip out of the hole.After pumping heavy pill.At anytime during the trip in the open hole where volumes are in doubt.When the bit enters the casing shoe.

7/12/0821

Typical Flow Checks would be made but not limited to:

When the bottom hole assembly is reaching the drill floor.

Any time during pulling out/running-in the hole where volumes are inconsistent with calculated displacement volumes.

Flow Check

PresenterPresentation NotesTypical Flow Checks would be made but not limited to:

When the bottom hole assembly is reaching the drill floor.Any time during pulling out/running-in the hole where volumes are inconsistent with calculated displacement volumes.

7/12/0822

This confirms that a kick is in progress. If any of the previously mentioned signs occur, either singly or together, a flow check should be carried out toconfirm the situation.

Flow Check

PresenterPresentation NotesFlow Check This confirms that a kick is in progress. If any of the previously mentioned signs occur, either singly or together, a flow check should be carried out to confirm the situation.

7/12/0823

Flow Check Procedure

1: Pick up of bottom and space out.

2: Shut down the pumps.

3: Line up the well on the trip tank with a known volume already in the tank.

4: When wall sticking changes are existing: Check for flow whilst reciprocating the drill string.

5: Record the depth, time and duration of the flow check, make record of returned fluids.

PresenterPresentation NotesFlow check procedure.1:Pick up of bottom and space out.2:Shut down the pumps. 3:Line up the well on the trip tank with a known volume already in the tank.4:When wall sticking changes are existing: Check for flow whilst reciprocating the drill string.5:Record the depth, time and duration of the flow check, make record of returned fluids.

7/12/0824

Well Control

The size and severity of a kick depends upon:

1: The degree of under balance.

2: The formation permeability.

3: The length of time the well remains under balanced.

4: The time taken to shut-in the well.

PresenterPresentation NotesThe size and severity of a kick depends upon:

1:The degree of under balance.

2:The formation permeability.

3:The length of time the well remains under balanced.

4:The time taken to shut-in the well.

7/12/0825

Shut-in Procedures

PresenterPresentation NotesThe driller closes the well in.

7/12/0826

SHUT-IN PROCEDURES

Surface BOPs while Drilling. SOFT SHUT-IN (API)

a. More influxb. Less hydraulic shock to the formation

HARD SHUT-IN (API)a. Less influxb. More hydraulic shock to the formation

FAST SHUT-IN (North Sea)a. A combination of both of the above

PresenterPresentation NotesSHUT-IN PROCEDURESSurface BOPs while Drilling.

SOFT SHUT-IN (API)a.More influxb.Less hydraulic shock to the formationHARD SHUT-IN (API)a.Less influxb.More hydraulic shock to the formationFAST SHUT-IN (North Sea)a.A combination of both of the above

7/12/0827

Choke Manifold

A choke manifold in a simple version. At point A the mud flows into the choke manifold and can be diverted to the manual, automatic choke and to the bypass line. REMOTE CONTROLLED chokeWhen the returned fluids go into the buffer they are diverted to the poor-boy degasser, mud-tanks or to the flare line.

PresenterPresentation NotesA choke manifold in a simple version. At point A the mud flows into the choke manifold and can be diverted to the manual, automatic choke and to the bypass line. A point of notice is that the so called automatic choke only means that the operation of the choke is automatic meaning the opening and closing. The setting is not automatically achieved but is controlled from distance. A better name for it is REMOTE CONTROLLED choke. When the returned fluids into the buffer come from there on they are diverted to the poor-boy degasser, mud-tanks or to the flare line.

7/12/0828

Remotely operated choke

P

P

To mud/gas separatorand/or pit

2 in nominal2 in

2 in Adjustable choke

2 in nominalTo pit

To pit

2 inChokeline

Blowoutpreventerstack outlet

Remotely operated valve

Sequenceoptional

3 in nominal2 in

Bleed line

4 in nominal

2 in nominal

To mud/gasseparatorand/or pitRemotely operated choke

(c)

Remotely operated choke

P

P

To mud/gas separatorand/or pit

2 in nominal2 in

2 in Adjustable choke

2 in nominalTo pit

To pit

2 inChokeline

Blowoutpreventerstack outlet

Remotely operated valve

Sequenceoptional

3 in nominal2 in

Bleed line

4 in nominal

2 in nominal

To mud/gasseparatorand/or pitRemotely operated choke

(c)

API 10k & 15 K Choke Manifold

7/12/0829

Soft Shut-in Drilling (North Sea Standard)

1: Call alert.2: Stop rotating and raise the

string to proper tool joint space out in BOP.

3: Stop the pumps.4: Open the choke line HCR

valve.5: Close the annular preventer.6: Close the remote choke.7: Ensure the well is secure.8: Read and record SIDPP,

SICP and pit gain,

PresenterPresentation NotesSoft Shut-in Drilling (North Sea Standard)1:Call alert.2:Stop rotating and raise the string to proper tool joint space out in BOP.3:Stop the pumps.4:Open the choke line HCR valve.5:Close the annular preventer.6:Close the remote choke.7:Ensure the well is secure.8:Read and record SIDPP, SICP and pit gain,

7/12/0830

Soft Shut-in Drilling (API Standard)

1: Stop rotating and raise the string to proper tool joint space out in BOP.

2: Stop the pumps.3: Open the choke line

HCR valve.4: Close the BOP.5: Close the remote

choke.6: Read and record

SIDPP, SICP and pit gain.

PresenterPresentation NotesSoft Shut-in Drilling (API Standard)1:Stop rotating and raise the string to proper tool joint space out in BOP.2:Stop the pumps.3:Open the choke line HCR valve.4:Close the BOP.5:Close the remote choke.6:Read and record SIDPP, SICP and pit gain.

7/12/0831

Hard Shut-in Drilling(API Standard)

1: Stop rotating and raise the string to proper tool joint space out in BOP.

2: Stop the pumps.3: Close the BOP.4: Open the choke line (HCR

valve).5: Read and record SIDPP,

SICP and pit gain.Note: the remote choke is

closed during drilling operations.

PresenterPresentation NotesHard Shut-in Drilling (API Standard)1:Stop rotating and raise the string to proper tool joint space out in BOP.2:Stop the pumps.3:Close the BOP.4:Open the choke line (HCR valve).5:Read and record SIDPP, SICP and pit gain.Note: the remote choke is closed during drilling operations.

7/12/0832

Hard Shut-in Drilling(North Sea Standard)

1: Call alert.2: Stop rotating and raise the

string to proper tool joint space out in BOP.

3: Stop the pumps.4: Open the choke line (HCR

valve).5: Close the pipe rams.6: Ensure the well is secure.7: Read and record SIDPP,

SICP and pit gain.

Note: the remote choke is closed

during drilling operations.

PresenterPresentation NotesHard Shut-in Drilling (North Sea Standard)1:Call alert.2:Stop rotating and raise the string to proper tool joint space out in BOP.3:Stop the pumps.4:Open the choke line (HCR valve).5:Close the pipe rams.6:Ensure the well is secure.7:Read and record SIDPP, SICP and pit gain.

Note: the remote choke is closed during drilling operations

7/12/0833

Fast Shut-in Drilling (North Sea Standard)

1: Call alert.2: Stop rotating and raise the

string to proper tool joint space out in BOP.

3: Stop the pumps.4: Open the choke line HCR

valve.5: Close the annular preventer.6: Ensure the well is secure.7: Read and record SIDPP, SICP

and pit gain.

Note: the remote choke is closed during drilling operations.

NO API FAST SHUT-IN

7/12/0834

Well ControlFast Shut-in Drilling Sub-sea

BOP (North Sea Standard)

1: Call alert.2: Raise string and space out.3: Stop pumping.4: Open the choke line failsafe

valves.5: Close the upper annular

preventer.6: Ensure the well is secure.7: Read and record SIDPP, SICP

and pit gain.8: Hang off the string on the upper

rams.

Soft Shut-in Drilling Sub-sea

BOP (North Sea Standard)

1: Call alert.2: Raise string and space

out.3: Stop pumping.4: Open the choke line

failsafe valves.5: Close the upper annular

preventer.6: Close the remote choke.7: Ensure the well is secure.8: Read and record SIDPP,

SICP and pit gain.9: Hang off the string on the

upper rams.

PresenterPresentation NotesDifferences in shutting in procedures.

7/12/0835

Well ControlSurface and Subsea BOPs while out of the hole

1: Open choke line HCR or failsafe valves.

2: Close blind rams or blind/shear rams.

3: Allow pressure to stabilize and record casing pressure and pit gain.

7/12/0836

Choke Manifold Line-up

Hard Shut-in, Drilling or Tripping:

1: Chokeline HCR or failsafe valves closed.

2: Remote choke closed.

3: Flow path after remote choke open to mud gas separator or as procedures dictate.

PresenterPresentation NotesCHOKE MANIFOLD LINE-UPHard Shut-in, Drilling or Tripping:

1:Chokeline HCR or failsafe valves closed.

2:Remote choke closed.3:Flow path after remote choke open to mud gas separator or as procedures dictate.

7/12/0837

Choke Manifold Line-up

Soft Shut-in, Drilling or Tripping:

1: Chokeline HCR or failsafe valves closed.

2: Remote choke open.

3: Flow path after remote choke open to mud gas separator or as procedures dictate.

7/12/0838

Fast Shut-in, Drilling or Tripping:

1: Chokeline HCR or failsafe valves closed.

2: Remote choke closed, upstream valve from remote choke may be closed rather than choke. Closing the valve downstream of the choke on the choke manifold, instead of the valve upstream, is allowable if this downstream valve is rated to the BOP full working pressure and equipped to allow opening under full working pressure.

3: Flow path after remote choke open to mud gas separator.

Choke Manifold Line-up

PresenterPresentation NotesCHOKE MANIFOLD LINE-UPFast Shut-in, Drilling or Tripping:1:Chokeline HCR or failsafe valves closed.2:Remote choke closed, upstream valve from remote choke may be closed rather than choke. Closing the valve downstream of the choke on the choke manifold, instead of the valve upstream, is allowable if this downstream valve is rated to the BOP full working pressure and equipped to allow opening under full working pressure.3:Flow path after remote choke open to mud gas separator.

Slide Number 1Causes Of Kicks Slide Number 3Well ControlWell ControlWell ControlShale hydration Rig Site IndicationsSlide Number 8Slide Number 9Well ControlWell ControlCAUSES OF KICKSWell ControlWell ControlKICK INDICATORSKICK INDICATORSKICK INDICATORSPOSITIVE KICK INDICATORSPOSITIVE KICK INDICATORSSlide Number 20Slide Number 21Slide Number 22 Flow Check ProcedureWell Control Shut-in ProceduresSHUT-IN PROCEDURESSlide Number 27Slide Number 28Soft Shut-in Drilling (North Sea Standard)Soft Shut-in Drilling (API Standard)Hard Shut-in Drilling (API Standard)Hard Shut-in Drilling (North Sea Standard)Fast Shut-in Drilling (North Sea Standard)Well ControlWell Control Surface and Subsea BOPs while out of the holeChoke Manifold Line-upChoke Manifold Line-upSlide Number 38