DRILLING P&P SURFACE LEVEL 3 EXAM

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1 / 51

During well operations, the drilling fluid becomes gas-cut. What actions should you take?

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

Shut in the well, notify the supervisor and record the well pressures.

Stop operations, flow check the well, and notify the supervisor.

Notify the supervisor and turn on the vacuum degasser.

2 / 51

When tripping out of the hole, swabbing is detected by comparing calculated volume with the
actual volume in the trip tank. How is swabbing confirmed?

When the fluid volume to fill the well is equal to the volume calculated on the trip sheet.

When the fluid volume to fill the well is more than the volume calculated on the trip sheet.

When the fluid volume to fill the well is less than the volume calculated on the trip sheet.

3 / 51

The flow sensor shows a total loss of returns. When picking up and monitoring the well, the fluid level drops out of sight in the annulus.

What immediate action should be taken?

Continue drilling ahead.

Pump at a reduced rate adding lost circulation material (LCM).

Fill the annulus with water (or lightest fluid available) and record the volume used.

Shut the well in and pump lost circulation material (LCM) down the kill line.

4 / 51

Fracture pressure is exceeded while drilling a well. What is most likely to happen?

The formation will break down when fractured, followed by mud losses and a loss of hydrostatic pressure if the hole cannot be kept full.

The formation will break down when fractured, followed by mud losses and an increase in hydrostatic pressure.

The formation will break down, but drilling can continue as you have an accurate value for fracture pressure.

There will be a kick as the formation is fractured, followed by an increase in mud tank level

5 / 51

A vertical well is shut in after there is a gas influx. The kill operation is delayed, and the influx starts to migrate. Because of this migration, both drillpipe pressure and casing pressure increase by 300 psi.

Well data:
Well depth:	10000 feet
Casing shoe depth:	6000 feet
Drilling fluid density:	11.7 ppg
Openhole/drillpipe capacity:	0.060 bbl/ft
Casing/drillpipe capacity:	0.065 bbl/ft

Note: Assume there is only drillpipe in the well.

Kick data:
Original shut in established drillpipe pressure:	800 psi
Original shut in established casing pressure:	1050 psi
Original kick volume:	130 bbl

How many barrels of drilling fluid should be bled from the well to arrive at the original bottomhole pressure, before gas migration?

1.36 bbl.

1.31 bbl.

2.16 bbl.

1.32 bbl.

6 / 51

While using the wait and weight method to kill the well that has a surface BOP stack, the pump rate is reduced while holding the casing pressure constant.

How will this affect bottomhole pressure (BHP)?

BHP will increase.

BHP will decrease.

BHP will stay the same.

7 / 51

After a positive flow check, the driller uses the third hard shut-in procedure to shut in the well.

What is the correct procedure?

Open the BOP side outlet hydraulic valve, shut the annular preventer, and monitor the shut-in pressures.

Space out the tool joint, close the BOP (annular or ram), open the BOP side outlet hydraulic valve, and monitor pressures.

Open the BOP side outlet hydraulic valve, shut the annular or pipe rams, close choke, and monitor shut-in pressures.

Shut the annular preventer, monitor shut-in pressures, and open the BOP side outlet hydraulic valve.

8 / 51

Which condition would produce the highest MAASP?

If the formation breakdown pressure is significantly higher than drilling fluid hydrostatic pressure.

If the diameter of the last casing shoe is large.

If the last casing shoe is near the surface.

If formation pressure is close to drilling fluid hydrostatic pressure.

9 / 51

When pulling out of the hole, how do swabbing pressures affect the bottom hole pressure (BHP)?

BHP will temporarily decrease.

BHP will temporarily increase.

BHP will remain the same.

10 / 51

A vertical well is drilled to a depth of 8000 ft.

Overbalance:	160 psi
Mud gradient:	0.73 psi/ft
Casing density:	0.157 bbl/ft
Drillpipe metal displacement:	0.008 bbl/ft

How many complete stands can the driller pull dry before the overbalance is lost? (one stand equals 90 ft).

46 stands.

45 stands.

47 stands.

48 stands.

11 / 51

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

Pump a low viscosity pill to reduce balling of bit and stabilisers.

Pull out the hole to change the bit..

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

Increase the yield point in the active system.

Minimise the time during a connection when the pumps are switched off.

12 / 51

A kill operation is ready to start, using the wait and weight method.

Kill fluid is ready to be pumped, but it takes 20 bbl to fill the surface lines.

What is the correct procedure to follow?

Re-set the stroke counter to zero when kill fluid reaches the drillpipe.

Add the 20 bbl (converted to pump strokes) to the total strokes to be pumped.

Subtract the 20 bbl (converted to pump strokes) from the total strokes to be pumped.

No action is required, there will be no effect on the drillpipe pressure schedule.

13 / 51

What well control problem can be caused by excessive over-pull when tripping out of hole?

Swabbing.

Surging.

A broken drillstring.

Stuck pipe in the well.

14 / 51

Calculate the formation strength at the casing shoe using the data below:

Well data
Casing shoe depth (TVD)	9780 ft
Drilling fluid density	12.3 ppg
MAASP	1885 psi

15 / 51

Using the trip sheet shown below, identify when the influx may have happened.

Note: The pipe will be pulled dry.

Displacement figures - Drillpipe capacity = 0.0178 bbl/ft; Drillpipe displacement = 0.0068 bbl/ft
Stands pulled	Length pulled (ft)	Total length (ft)	Calculated displacement (bbl)	Trip tank volume (bbl)
-	-	-	-	15
1-5	470	470	3.2	11.8
6-10	473	943	3.2	8.6
11-20	945	1888	6.4	2.2
15 bbl added to the trip tank				17.2
21-30	942	2830	6.4	10.8
31-40	944	3774	6.4	4.4

Between stands 31 to 40.

There has not been an influx, the trip is going as planned.

Between stands 11 to 20.

Between stands 1 to 5.

16 / 51

When starting a kill operation on a surface BOP installation, the casing pressure is kept constant while bringing the pump up to speed. The drillpipe gauge now reads 200 psi higher than the
calculated initial circulating pressure (ICP).

What is the correct action to take?

Allow the casing pressure to increase by 200 psi by closing the choke.

Open the choke and let the standpipe pressure drop to the calculated value (ICP).

There will now be 200 psi over-balance on the bottom, which is acceptable. No further action is required.

Continue to circulate with the new ICP and adjust the calculated drillpipe pressure schedule.

17 / 51

Which BOP may be used for the hard shut-in procedure (according to API RP 59)?

The annular BOP.

The ram BOP.

Either a ram type or annular BOP.

An IBOP.

18 / 51

What action is required if the driller identifies connection gas?

Shut in the well and inform the supervisor.

Reduce the fluid density.

Increase the fluid density.

Flow check the well and inform the supervisor.

19 / 51

During a well kill operation, using the driller's method, the casing pressure gauge reading suddenly increases by 150 psi.

After a short time, the operator sees a 150 psi pressure increase on the drillpipe pressure gauge.

What is the correct action to take?

Shut in the well and change to the spare standpipe.

Reduce the pump rate to decrease both pressures by 150 psi.

This is normal, continue with the operation.

Shut in the well and change to another choke.

20 / 51

Which statement describes the volumetric method?

It allows the influx to migrate to surface while maintaining constant casing shoe pressure.

It allows controlled migration of the influx to surface while maintaining constant bottomhole pressure (BHP).

It allows the controlled migration of the influx to surface while maintaining casing pressure at the initial stabilised shut-in pressure.

It allows the influx to migrate to surface while maintaining constant pressure in the influx.

21 / 51

Calculate the maximum allowable fluid density using the information below:

Well data
Casing shoe depth:	8000 ft true vertical depth (TVD)
Leak-off test (LOT) pressure at pump:	1500 psi
Fluid density at the time of the LOT:	10.4 ppg

22 / 51

What is the main purpose of BOP equipment?

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

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

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

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

23 / 51

While starting a well kill, the remote choke becomes stuck in the open position.

Which action is required?

Decrease the pump rate to allow time to open the manual choke.

Without stopping the pump, change over to the manual choke.

Increase the pump rate to increase the annular friction losses.

Stop the pump and close a valve upstream of the choke.

24 / 51

After pulling 1 O stands of pipe, a well takes less fluid than expected.

The driller completes a flow check and confirms that the well is not flowing.

What should the driller do next?

Because the well is not flowing, continue pulling pipe from the hole.

Establish if there has been an influx by running back to bottom and circulating bottoms up.

Pull another 1 O stands and flow check.

Shut in the well immediately and check for pressures.

25 / 51

When performing a leak-off test (LOT), which parameters must be accurately measured and recorded?

Fluid volume in open hole, density of the fluid used, and the true vertical depth (TVD).

Fluid volume pumped, density of the fluid used, and true vertical depth (TVD).

Pumping time until the leak-off, and the measured depth (MD).

Fluid volume in the casing, and measured depth (MD).

26 / 51

In which situation would secondary well control be at risk?

If the driller does not call the supervisor after closing the BOP.

If the trip tank level remains constant after the well is shut in.

If a pipe ram fails its regular pressure test.

If the blind ram is closed during a slip and cut operation.

27 / 51

A well is shut in with bit 10 stands (930 ft) off bottom. What is the bit to shoe strokes if a pump capacity of 0.12 bbl/stroke is used to circulate the well?

Well data:
Well depth:	9750 ft MD (8560 ft TVD)
Casing shoe:	8076 ft MD (7076 ft TVD)
Bottomhole asembly (SHA) length:	744 ft
Openhole (OH)/BHA capacity:	0.102 bbl/ft
OH/drillpipe (DP) capacity:	0.132 bbl/ft

609 strokes.

471 strokes.

818 strokes.

632 strokes.

28 / 51

Calculate the hydrostatic pressure in a 12000 ft vertical well if the fluid gradient is 0.78 psi/ft.

29 / 51

How can the driller prevent swabbing? Choose two answers.

Pump out of the hole.

Pull the drillpipe slowly.

Pump a slug.

Pull the drillpipe fast.

Increase the viscosity of the drilling fluid.

30 / 51

What is one positive indicator that the well is kicking?

An increase in cuttings size.

An increase in gas-cut drilling fluid.

An increase in flow returns.

An increase in torque.

31 / 51

During a trip, the driller suspects there is swabbed gas in the well. After a negative flow (the well is not flowing), what action is required?

Run back to bottom and circulate the hole clean.

Shut the well in.

Increase the speed of pulling each stand.

Increase the fluid density or trip margin.

32 / 51

What is the main role of the driller in preventing well control incidents?

Taking actions to prevent abnormal pressures.

Taking actions to always keep the hole full.

Taking actions to prevent gas cut mud.

Taking actions to prevent lost circulation.

33 / 51

Which are positive indicators of a kick while drilling? Choose two answers.

An increase in flow rate with constant pump stroke rate.

A decrease in trip gas levels.

An increase in pit volume.

A decrease in flow rate with constant pump stroke rate.

A decrease in pit volume.

34 / 51

What can you do to reduce the risk of surging when running casing?

Reduce the time between connections.

Reduce the trip tank pump speed.

Reduce the casing running speed.

Reduce the casing fill time.

35 / 51

While drilling ahead, a well kicks and is shut in. The shut-in drillpipe pressure (SIDPP) and shut-in casing pressure (SICP) begin to increase and then suddenly the SICP drops, followed by a sudden drop in SIDPP.

What may have happened?

The bottomhole assembly has packed off.

A weak formation has broken down.

The drillstring has washed out.

Gas has started to migrate up the well bore.

36 / 51

Which statement about hydrate prevention is correct?

Increasing the pressure at the choke helps to prevent hydrate formation.

Reducing the temperature below the freezing point of water helps to prevent hydrate formation.

Injecting distilled water into the flow stream helps to prevent hydrate formation.

Injecting glycol into the flow stream helps to prevent hydrates formation.

37 / 51

After tripping in hole, the driller circulates bottoms-up before drilling ahead. Gas cutting is then seen at the shakers. What is the cause of this gas cutting?

Recirculated air from surface.

Trip gas.

Connection gas.

Background gas.

38 / 51

During a kill operation with a surface BOP, which action is required to maintain constant bottomhole pressure when starting circulation? Ignore annular pressure loss (APL).

The pumps must be brought up to kill rate while reducing the casing pressure by a safety margin.

The pumps must be brought up to kill rate while holding the casing pressure constant.

The drillpipe pressure should be kept constant while bringing the pumps up to kill rate.

The pumps must be brought up to kill rate while increasing the drillpipe pressure by a safety margin above the original shut-in drill pipe pressure (SIDPP).

39 / 51

What could cause bottomhole pressure (BHP) to decrease when running casing?

Drilling fluid returns overflowing from the trip tank.

An increase in annular pressure loss (APL) due to slower casing running speeds.

A decrease in hydrostatic pressure due to losses caused by surging.

Increased displacement volumes.

40 / 51

What is one risk of using self-filling floats when running casing?

By running casing more quickly, you reduce the ability to monitor returns.

If the self-filling float fails, it can completely plug the casing string and annulus.

Fluid in the annulus is less likely to maintain hydrostatic head when u-tubing.

If the float fails to convert it may result in uncontrolled flow into the casing string after the well is shut in.

41 / 51

Calculate the MAASP with the following information:

Well data:
Hole depth (MD)	11500 ft
Hole depth (TVD)	10200 ft
Casing shoe depth (MD)	8200 ft
Casing shoe depth (TVD)	7400 ft
Drilling fluid density	10 ppg
Formation strength gradient	0.707 psi/ft

42 / 51

Which factors increase the chances of swabbing?

Choose two answers.

Large open hole/bottomhole assembly (BHA) capacity.

A long bottomhole assembly (BHA).

Low viscosity in the drilling fluid.

Pulling out of the hole too fast.

Low gel strength in the drilling fluid.

43 / 51

Please use the blank Surface kill sheets and well data to answer the following 9 questions

Level 3 & 4 Surface Kill Sheet Section - Group 1

Well Data
Hole Size	8-1/2 inch
Hole Depth	12336 feet. TVD/MD
Casing	9-5/8 casing set at 9875 feet TVD/MD.
Drill Pipe	5 inch, Capacity 0.0178 bbl/ft.
Heavy Weight Pipe	5 inch, 489 feet long, capacity 0.0088 bbl/ft.
Drill Collars	6-1/4 inch, 902 feet long, capacity 0.006 bbl/ft
Mud density	14.1 ppg
Capacities
Drill collars in open hole	0.0322 bbl/ft
Drill pipe/HWDP in open hole	0.0473 bbl/ft.
Drill pipe in casing	0.0493 bbl/ft.
Pumps	Displacement = 0.102 bbl/Stroke
Slow Circulating Rate	650 psi at 30 spm
Fracture mud density at the casing shoe 16.6 ppg

The well has been shut in after a kick.

Kick Data:
Shut in Drill Pipe pressure	530 psi
Shut in Casing Pressure	720 psi
Pit gain	10 bbl

The well will be killed using the Driller's Method at 30 spm

Q43: How many strokes are required to pump kill mud from surface to bit?

44 / 51

How many strokes are required to pump from the bit to casing shoe?

45 / 51

How many strokes are required to pump from the bit to surface?

46 / 51

What is the kill mud density?

47 / 51

What is the initial circulating pressure?

48 / 51

What is the final circulating pressure?

49 / 51

What is the MAASP at the time the well was shut in?

50 / 51

What is MAASP after circulation of the kill mud?

51 / 51

What is the time for one complete circulation?

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