Well Control Methods and Procedures

Question 1

Objective of Kill Method

Answer 1

Circulate out any invading fluid (liquid or gas) and circulate a satisfactory weight of kill mud into the well, without allowing further influx into the hole

Question 2

Constant Bottom-Hole Pressure Kill Methods

Answer 2

Driller’s Method, Wait and Weight Method (Engineer’s Method), Concurrent Method

Question 3

Driller’s Method

Answer 3

Split into 2 circulations. During the first, the kick fluid is circulated without changing the mud weight; once the influx is out, the mud is weighted up and pumped around the well on the second circulation

Question 4

Wait and Weight

Answer 4

Kill mud is prepared before starting the kill, and the kick fluid is circulated out while this mud is circulated into the well

Question 5

Concurrent Method

Answer 5

Kill mud is introduced in stages while circulating.

Question 6

Three S Procedure (Drilling)

Answer 6

Space out, Shut down pumps, shut-in

Question 7

Shut-in

Answer 7

Close uppermost applicable BOP when shutting in

Question 8

Three S Procedure (Tripping)

Answer 8

Stab FOSV, Space out, Shut-in

Question 9

Total Volume to Weight-Up

Answer 9

Reduce pit volume before weighting up. It takes less time, it requires less barite, and pits may overflow without reducing volume

Question 10

Barite Required

Answer 10

Volume to Weight up x (15 x Increase in Mud Weight) / (35 - New Mud Weight)

Question 11

Time for Gas at Surface

Answer 11

Usually seen after pumping 1/2 to 2/3 calculated bototms up strokes

Question 12

Establishing Circulation

Answer 12

Ensure crew knows responsibilities, eliminate all ignition sources, secure vent lines, line up manifold, and zero stroke counter

Question 13

DP Pressure Drop / Stroke

Answer 13

(ICP - FCP) / Total DP Strokes, 100 stroke increment is standard

Question 14

Volumetric Method

Answer 14

Used when unable to circulate (Unoperative pumps, bit plugged, drill pipe above influx, or when pipe is out of hole). A method used to hold CBHP, not kill the well.

Question 15

Principles of Volumetric Method

Answer 15

Boyle’s Law, Hydrostatic Pressure, and Volume and Height

Question 16

Boyle’s Law

Answer 16

P1V1 = P2V2, Pressure of a gas is directly related to its volume (neglecting temperature effects)

Question 17

Volumetric Mud Increment Calculation

Answer 17

Pressure Increment (100 psi) x ACF / (MW x 0.052)

Question 18

Purpose of Volumetric Method

Answer 18

Permit controlled expansion of the gas bubble as it migrates up the hole.

Question 19

Volumetric Pressure Increment

Answer 19

The amount of pressure to be used as a working pressure range while performing the Volumetric Control Method.

Question 20

Volumetric Safety Factor

Answer 20

An increase in the bottomhole pressure which is allowed to occur naturally as gas migrates up the annulus with the well shut in. An appropriate value for the safety factor is 50 - 200 psi.

Question 21

Volumetric Mud Increment

Answer 21

The volume of mud which is to be bled from the annulus in order to reduce the annular hydrostatic pressure by the amount of the PI.

Question 22

Volumetric Procedure

Answer 22

1. Perform Calculations 2. Allow casing pressure to increase to establish safety factor plus PI 3. Hold casing pressure constant until the mud increment is bled off 4. Wait for the casing pressure to increase as the gas bubble migrates 5. Hold casing pressure constant by bleeding mud from the annulus 6. Alternate holding casing pressure constant and letting gas bubble rise

Question 23

Gas Rate of Rise (ft/hr)

Answer 23

Change in SICP / (MW x 0.052 x Change in Time)

Question 24

Volumetric for Subsea

Answer 24

Use ACF at mudline. When KL and CL diverge, begin using ACF of CL.

Question 25

End of Volumetric Method

Answer 25

When the SICP is stable and not rising. Some gas may be bled off before the SICP stabilizes.

Question 26

Lubricate and Bleed

Answer 26

Surface pressure is replaced with hydrostatic pressure by pumping mud into the well on top of the gas. The gas and mud are allowed to change places in the hole and a certain amount of the surface pressure is then bled off.

Question 27

Lubricate and Bleed Procedure

Answer 27

1. Perform Calculations 2. Lubricate by slowly pumping a given volume into the well 3. Wait for the gas to migrate back to the surface 4. Bleed gas from the well until the surface pressure is reduced by an amount equal to the hydrostatic pressure of th emud pumped in 5. Repeat steps 2 through4 until all of hte gas has been bled off or a desired surface pressure has been reached

Question 28

Bullheading

Answer 28

A technique that may be used in certain circumstances during drilling operations to pump an influx back into the formation.

Question 29

When to Bullhead (Drilling)

Answer 29

When a very large influx has been taken, when conventional methods may cause excessive surface pressures, when displacement of the influx would result in an excessive gas volume at surface (MGS limitations), if the influx contains an unacceptable level of H2S, When stripping back to bottom is not feasible, when there is no pipe in the hole, or to reduce surface operations

Question 30

Factors that Determine Feasibility of Bullheading

Answer 30

The characteristic of the openhole, the rated pressure of the well control equipment and the casing, drill pipe andcasing pressure limits, the type of influx and the relative permeability of the formation, the position of the influx on the hole, the quality of the filter cake at the permeable formation, the consequences of fracturing the openhole, and the possibility of formation damage

Question 31

Bullheading Procedure

Answer 31

1. Calculate surface pressures that would cause fracture 2. Prepare a chart using strokes vs. pumping pressure if heavier mud is used 3. If gas is at surface, used lube and bleed first 4. Bring the pumps up to speed slowly to overcome well pressure 5. Attempt to pump fast enough to exceed gas migration rate 6. As the produced fluids are forced back into the formation, the added hydrostatic should lower pump pressure 7. Stop the pump, shut-in and monitor

Question 32

What to do after taking a kick off bottom?

Answer 32

1. Kill the well off bottom (not recommended) 2. Use volumetric well control if you have migrating gas 3. Strip back to bottom 4. Strip using volumetric well control if you have migrating gas 5. Snub the drill pipe back in the well

Question 33

Stripping

Answer 33

Tripping pipe through the BOPs when the drill string weight is greater than the net upward force created from the wellbore pressures

Question 34

Snubbing

Answer 34

Forcing pipe through the BOPs when the drill string weight is not sufficient to overcome the net upward force created by wellbore pressures

Question 35

Initial Shut-in Considerations (Stripping)

Answer 35

Is the annular in good condition, rig crews should be aware of the responibilities, an IBOP is required for stripping, the annular element can be changed with pipe in the hole by inserting a split element, ram combination stripping is not recommended, surface pressure determines whether annular stripping is possible (due to rating and increased pressure increases wear), field test show good results at 800 psi but unpredictable at 800 psi, reduce the annular pressure to allow drill pipe to be stripped easier, a a surge dampener is usefull to allow tool joints to pass through the annular without increasing annular pressure

Question 36

Ways to reduce annular pressure to allow stripping

Answer 36

Circulate out the influx if it is above the circulation point, bullhead, or lubricate and bleed if at BOP

Question 37

Volume Accounting (Stripping)

Answer 37

Bleed off volume equal to the closed end steel displacment

Question 38

Constant Surface Pressure (Stripping)

Answer 38

Maintaining a constant surface pressure by bleeding fluid through the choke as pipe is run (Most preferred)

Question 39

Influs Penetration (Stripping)

Answer 39

When the drill string penetrates the influx, the height increases. As the height of the influx increases, hydrostatic pressure decreases and the casing pressure must increase.

Question 40

Stripping Procedure (Without Volumetric)

Answer 40

1. Calculations: bit depth vs. kick depth, pressure increase due to influx penetration, net upward force vs. downward force, determine appropriate safety factor, and calculate theoreticla bleed volume per stand 2. Stab and make up the IBOP on top of te FOSV 3. Regulate annular closing pressure to permit stripping (A small leak is desirable) 4. Strip into the well until you establish the desired safety factor 5. Continue by stripping to the desired depthwhile bleeding of fhte calculated fluid volumeper stand

Question 41

Stripping Procedure (With Volumetric)

Answer 41

1. Calculations: net upwward force vs. downward force, theoreticla bleed volume per stand, determine safety factor, choose PI and MI, bit depth and kick depth, calculate increase in pressure while penetrating bubble 2. Stab and make up IBOP on top of FOSV 3. Regulate annular stripping pressure to permit stripping (A small leak is desirable) 4. Strip into the well until you establish the desired safety factor 5. Continue stripping into the well keeping casing pressure constant 6. When the difference between total fluid bled and pipe displacement equals the MI, strip in while increasing pressure to the next PI step 7. Repeat steps 5 and 6 once the PI has been reached 8. Upon penetrating the bubble: Allow casing pressure to increase by predetermined ammount and adjust step 6 for new MI 9. Repeat steps 5 and 6 until at desired epth

Question 42

Practical Stripping Considerations

Answer 42

Stripping with volumetric control is complex, eliminate the bubble penetration calculation by adding a safety factor equal to the pressure increase, calculate the MI using the capacity factor around the drill pipe, do not fill the pipe completely to keep track of volumes better, when stripping with volumetric only one step may be achieved before reaching bottom,

Question 43

Rotating Pipe During Well Control Operations

Answer 43

If rotating pipe is necessary, the pipe should be reciprocated as well. Several incidents have occurred where pipe being rotated has been severed due to steel components that support rubber annular BOP components

Question 44

Glycol

Answer 44

An inhibiting agent that lowers the temperature at which hydrates would be expected to form

Question 45

Methanol

Answer 45

Used to dissolve existing hydrate formations