Basic Well Control

8. BASIC WELL CONTROL

Habiburrohman abdullah 1

Basic Well Control

• Origin of overpressure

• Kick recognition

• Shut-in procedure

• Kill Procedure

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Kick Detection and Control

• Primary well control involves efforts at preventing formation fluid influx into the wellbore.

• Secondary well control involves detecting an influx and bringing it to the surface safely.

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Basic Well Control

Two primary objectives:

1. To kill the well safely

2. To minimize borehole stresses

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Blow Out Preventer (BOP)

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Successful Well Control

• Keep the BHP constant throughout using the choke.

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Slow Pump Rate

• The pump rate at which the system pressure loss is recorded for purposes of well control is called the slow pump rate, slow pump pressure, kill rate, or reduced circulating pressure

• Also called slow pump rate, slow pump pressure, kill rate, reduced circulating pressure or slow circulating rate

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Slow Pump Rate: When To Take

• Every tour

• After repairing the pumps or when the liner is changed

• When the mud properties are changed

• Every 500 ft of new hole drilled

• BHA changes

• When the bit nozzles are changed

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SIDPP

• Shut-in DP Pressure is the measure of the difference between the formation pressure and the hydrostatic column of the mud in the drillstring.

• Gives a direct reading of the formation pressure

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Formation Pressure / Kill MW

• FP (ppg) = (SIDPP / (0.0519 x TVD)) + Original MW

• BHP = ((SIDPP x 19.23) / TVD) + Original MW

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SICP

• Shut-in Casing Pressure is the measure of the difference between the formation pressure and the hydrostatic column of the fluids in the annulus during a kick.

• Not an good indicator of the formation pressure.

FP = HPmud + HPkick + SICP

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Pressure at the Casing Shoe

• Pcsg = SICP + 0.052 x MW x Casing shoe TVD

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U Tube

Kick

Annulus sideDP side

SIDPP + HPmud =

SICP + HPmud + HPkick =

Fm Pressure

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Materials to Weight Up Mud

• Barite• Ilmenite• Fe oxide (Hematite)• Galena

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Materials to Weight Up Completion Fluids

• KCl• NaCl

• CaCl2• CaBr2

• ZnBr

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Barite

• The amount of barite necessary to increase the MW to the kill MW is:

Sx/100 bbl mud = 1490 x ((Kill MW – Old MW)/(35.8 – Kill MW) Or

100-lb sx of barite = (Mud vol x 14.7 x (KMW – OMW)) / (35 – KMW)

• The volume of increase caused by weighting up:

(100 x (Kill MW – MW)) / (35.8 – Kill MW) Or

Vol incr = sx of Barite / 14.7

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Shut-In Procedures

• Hard shut-in• Soft shut-in• Shut-in while tripping• Shut-in with diverter in use• Shut-in while running casing

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Hard Shut-in

• Assure beforehand the choke manifold line is open to preferred choke and choke is in closed position.

• After a kick is indicated, pick up the string and position tool joint above rotary table.

• Shut off pump.• Flow check.• If flow is verified, shut the well in by closing the BOP using

annular preventer.• Open the HCR valve (hydraulically controlled remote valve) to the

choke manifold.

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Hard Shut-in

• Close the choke if open.• Notify supervisor (company drilling supervisor,

toolpusher or rig manager).• Read and record SIDPP, SICP, pit gain, TVD and time.• Rotate the drillstring through the closed annular

preventer if feasible.• Prepare to implement kill procedures.

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Soft Shut-in

• Assure beforehand choke manifold line is open to preferred choke and choke in in open position.

• After kick is indicated, pick up string & position tool joint above rotary table.

• Shut off pump.• Flow check.• If flow is verified, open the HCR.• Close the BOP using the annular preventer.

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Soft Shut-in

• Close the choke if open.• Notify supervisor (company drilling supervisor,

toolpusher, rig manager). • Read and record SIDPP, SICP, pit gain, TVD and time.• Rotate the drillstring through the closed annular

preventer if feasible.• Prepare to implement kill procedures.

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Shut-in While Tripping• Set the slips below the tool joint.• Stab a full opening valve (TIW) and close it.• Open the HCR and close the BOPs and choke.• Pick up and stab the kelly/TDS or pump-in line.• Open the safety valve.• Notify the supervisors.• Read and record SIDPP, SICP, pit gain, TVD of the well, TVD of the

bit and time.• Prepare to implement kill procedures.

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Shut-in with Diverters in Use

• When a shallow kick occurs a full opening diverter valve is opened to divert the flow away from the rig.

• The low pressure annular is then closed.

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Shut-in While Running Casing

• Lower the casing until the swage and a valve can be stabbed.

• Close the casing rams or annular preventer.• Stab the swage and valve.• Notify the supervisors.• Read and record the pressures, TVDs, pit gain and time.• Prepare to implement kill procedures.

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Well Kill Procedures

• Kill equations• 3 Major Kill Procedures• Other Kill Procedures

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Initial Circulating Pressure (ICP)

• ICP = system pressure loss at kill rate + SIDPP

Note:• When we start to circulate, the DP will increase due to the friction loss and the pressured

drop across the bit.

• BHP = HSPDP + Circulating DPP – DP press loss

• In order to utilize the DP gauge we have to know the DP press loss. The DP press loss = SPP

• Circulating DPP = BHP – HSPDP + SPP

• Since SIDPP =BHP – HSPDP

• Circ DPP = SIDPP + SPP

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Final Circulating Pressure (FCP)

• FCP = System pressure loss x (Kill MW/Old MW)

• Note:• As the KMW is circulated through the bit the circ DP Press will

decrease until the KMW will reach the bit. At the bit the SIDPP will be zero. The circ DP pressure with the KMW at the bit is the FCP.

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ICP and FCP Relationship

• In a vertical well the circulating drillpipe pressure will decrease linearly from the ICP to the FCP.

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Major Kill Procedures

• Engineer’s or Wait and Weight Method• Driller’s or Two Circulation Method• Concurrent or Circulate and Weight Method

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Introduction To Kick Killing Procedures

• Introduction

The purpose of any well kill procedure is to maintain the BHP constant at a level equal to or slightly greater than the FP. Since the drill pipe pressure is a direct bottom hole pressure indicator, the drill pipe pressure can be manipulated in a systematic manner, and the well can be controlled.

• There are three well kill procedures in common usage. These are:

Wait and Weight Method – After the well is shut-in, the surface mud system is weighted up to the required kill mud weight. The kill mud is then pumped and the well is killed in one complete circulation. This method is also called the Engineer’s or the One Circulation Method.

Driller’s Method – After the well is shut-in and the readings are recorded, pumping is begun immediately. The influx is pumped from the wellbore without any prior weighting up of the mud. Once the influx has been pumped from the well, the well is shut-in, and the surface mud system is weighted up to the kill mud weight. The lighter mud is then displaced by the kill mud. This method is sometimes called the Two Circulation Method.

Concurrent Method – After the well is shut-in, pumping is begun immediately and the mud weight is raised while the kick is being circulated out. The use of this method may require several circulations before the well is fully killed. This method is also called the Circulate and Weight Method.

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Engineer’s Method: Procedure

1. Shut-in well and record SIDPP, SICP, pit gain2. Compute kill MW and compute pump sked. Build kill mud3. Hold casing press constant and bring pump to kill rate (DPP = ICP)4. Follow pump schedule when displacing DP. The choke opening is varied as

required to keep the drill pipe pressure regulated.5. Once DP filled, poss. to shut-in well, SIDPP = 06. Hold casing press constant using choke and bring pump to kill rate, (DPP = FCP)7. Hold at FCP until kill mud at surface8. Shut down pumps, shut-in well. Check for remaining pressure.9. If no more pressure, crack choke and FLC.10. If no flow, open BOP. The well is dead.

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Pressure Schedule For Drillpipe

• Calculate the number of strokes required to displace the drillpipe with the kill mud

• Calculate ICP and FCP• Plot the mud volume (bbls or strokes) along the horizontal

axis and the DP pressures along the vertical axis• The plot can be completed by plotting the ICP at 0 strokes

and connecting it to the FCP at the number of strokes required to displace the drill pipe.

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Pump Schedule: Problem 1

• Assume the following: – SIDPP = 500 psi– Kill rate pressure = 1000 psi– Original MW = 10 ppg– Kill MW = 11 ppg– Strokes to displace DP = 500 strokes

• Problem: Fill in the drill pipe pressure schedule.

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Pump Schedule: Problem 1

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Strokes Pumped DP Pressure

0

100

200

300

400

500

Pump Schedule: Solution

• ICP = Kill rate pressure + SIDPP – ICP = 1000 psi + 500 psi = 1500 psi at 0 strokes

• FCP = (Kill rate pressure x Kill MW) / Original MW – FCP = (1000 psi x 11 ppg) / 10 ppg = 1100 psi

after 500 strokes

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Pump Schedule: Solution

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Strokes Pumped DP Pressure

0 1500

100

200

300

400

500 1100

Pump Schedule: Solution

• Drill pipe decrease per stroke = (ICP – FCP) / Strokes to displace DP with kill mud– Drill pipe decrease per stroke = (1500 psi –

1100 psi) / 500 strokes = 0.8 psi /stroke

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Pump Schedule: Solution

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Strokes Pumped DP Pressure

0 1500

100 1420

200 1340

300 1260

400 1180

500 1100Note: This method eliminates any errors that may occur as a result of reading drill

pipe pressures from a graph incorrectly.

Pump Schedule: Solution

• ICP = Kill rate pressure + SIDPP = 1000 psi + 500 psi = 1500 psi at 0 strokes

• FCP = (Kill rate pressure x Kill MW) / Original MW = (1000 psi x 11 ppg) / 10 ppg = 1100 psi after 500 strokes

• Plot 1500 psi at 0 strokes and plot 1100 psi at 500 strokes. Connect the two points.40

DP Pressure Schedule

10001100120013001400150016001700180019002000

0 100 200 300 400 500 600

Strokes Pumped

Pre

ssu

re,

psi

Driller’s Method

• TWO complete circulations

– Circulate kick out of hole using old mud

– Circulate old mud out of hole using kill weight mud

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Driller’s Method: Procedure1. Shut-in well and record SIDPP, SICP, pit gain2. Compute kill MW3. Hold choke pressure constant and pump at kill rate4. Hold DP pressure steady at ICP until kick out of hole5. Shut-in well and build kill MW6. Hold casing pressure steady and pump at kill rate7. DP pressure is allowed to decline as per pump sked. Once DP full, observe FCP8. Keep pumping at kill rate and constant FCP until kill mud at surface.9. Shut down pumps, shut-in well. Check for remaining pressure.10. If no more pressure, crack choke and FLC.11. If no flow, open BOP. The well is dead.

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Concurrent Method: Procedure1. Shut-in well using preferred shut-in procedure and record the

SIDPP, SICP and the amount of pit gain2. Hold casing press constant and bring pump to kill rate (DPP = ICP)3. Follow schedule when displacing DP4. Once DP filled, shut-in well, SIDPP = 05. Hold casing press constant and bring pump to kill rate, (DPP =

FCP)6. Hold at FCP until kill mud at surface7. Shut down pumps, shut-in well, check if well is dead8. If not repeat steps 2 to 9.

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Major Kill Procedures: Conclusion

• The Wait and Weight Method using the proper kill weight results in the least amount of casing pressure and the least borehole stresses.

• The Concurrent Method allows lower casing pressure values than the Driller’s Method.

• Overkilling the well has no tangible benefit.

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Other Calculations

• Height of the Influx

• Identification of Influx

• Choke Line Friction (CLFP)

• MASCP

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Height Of Influx

• Pit level gain < ann. vol. around the DC:

Length of kick, ft = kick volume (bbls) / ((Hole ID2 – DCOD2) x 0.000971)

• Pit level gain > ann. vol. around the DC:

Length of kick, ft = Length of DC + ((kick volume – DC ann. vol.) / ((Hole ID2 – DPCOD2) x 0.000971))

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Identification Of Influx Density• Influx Density, ppg = MW, ppg – ((SICP-SIDPP)/(Height of influx, ft x

0.0519))

Note:• The influx may either be gas, oil, water or a combination of the three. The calculation is an approximation at best

because the hole may not be gauge and the pit gain may not be necessarily accurately noted.

• The formula for determining the gradient of the influx fluid is:

Influx gradient = Mud gradient in DP– ((SICP-SIDPP)/Height of influx)

Height of influx = bbls gained / annulus volume, bbls/ft

Influx density (ppg) = Influx gradient / 0.52

• As a general rule, an influx with an equivalent mud weight of 1 to 3 ppg is assumed to be gas, 3 to 5 ppg is assumed to be a mixture of gas and water or gas and oil, and 5 to 7 ppg is assumed to be either oil, water or an oil-water mixture.

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Identification Of Influx

As a general rule:• 1 to 3 ppg EMW is assumed to be gas• 3 to 5 ppg EMW is assumed to be a

mixture of gas and water or gas and oil• 5 to 7 ppg EMW is assumed to be either

oil, water or an oil-water mixture

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Influx Identification: Problem 1

• Identify the type of influx assuming the following:– TVD = 10000 ft– MW in DP = 12 ppg– Hole ID = 9.875 in– DP OD = 5 in– SIDPP = 520 psi– SICP = 650 psi– Pit Gain = 40 bbls

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Influx Identification: Solution

• Mud gradient = 12 ppg x .052 = 0.624 psi/ft

• Annulus volume, bbl/ft = ((9.875)2 – (5)2) / 1029 = 0.70 bbls/ft

• Length of influx, ft = 40 bbls / 0.70 bbls/ft = 571 ft

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Influx Identification: Solution• Gradient of influx, psi/ft:• = 0.624 psi/ft –((650 psi – 520 psi) / 571 ft) • = 0.624 psi/ft – (130 psi/571 ft) • = 0.624 psi/ft – 0.228 psi/ft = 0.396 psi/ft

• Influx density, ppg = 0.396 psi/ft / .052 = 7.61 ppg

• The influx would probably be oil or water. The comparatively high weight means that not much gas is associated within the influx.

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Choke Line Friction (CLFP)

• Used to determine the amount by which the casing pressure is to be adjusted to maintain BHP = FP when starting the pumps on a kill operation. We reduce the SICP by the amount of CLFP to make allowances for the back pressure imposed by the CLFP.

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Maximum Allowable Shut-in Casing Pressure

• Surface pressure acting ontop of the current hydrostatic pressure that will exceed the measured fracture pressure at the casing seat.

• MASCP = 0.0519 x (FGmin – MW) x Dwf

• Where,

MASCP = psi

FGmin = Fracture Gradient of weakest formation, ppg

MW = ppg

Dwf = TVD of weakest formation

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END

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