IWCF Level 3 DWC flashcards

32 cards. Read the term and the definition here. The deck at the top of this page is optional.

Hydrostatic pressure formula

Pressure exerted by a fluid column equals 0.052 multiplied by mud weight in ppg multiplied by true vertical depth in feet. Result is in psi.

True vertical depth

Vertical distance from the rotary table or datum to the point of interest. Used for all hydrostatic and formation pressure calculations instead of measured depth along the wellbore.

SIDPP

Shut-in drill pipe pressure. Stabilized pressure read on the drill pipe with the well shut in; it equals the amount by which formation pressure exceeds the hydrostatic pressure of the mud in the drill string.

SICP

Shut-in casing pressure. Stabilized pressure on the casing or annulus with the well shut in. It reflects formation pressure minus the hydrostatic pressure of mud plus any influx in the annulus.

Kill mud weight formula

Original mud weight in ppg plus SIDPP divided by 0.052 times true vertical depth. This is the minimum weight that balances formation pressure with no trip margin.

Initial circulating pressure

Slow circulating rate pressure plus shut-in drill pipe pressure. It is the drill pipe pressure needed at the start of a kill to hold bottomhole pressure constant while circulating the original mud.

Final circulating pressure

Slow circulating rate pressure multiplied by kill mud weight divided by original mud weight. It is the drill pipe pressure expected once kill mud reaches the bit.

Slow circulating rate pressure

Pump pressure measured at a defined low pump rate, typically 30 to 40 strokes per minute, with the bit off bottom and the well static. It represents system friction used in kill calculations.

MAASP

Maximum allowable annular surface pressure. Equals the difference between maximum allowable mud weight and current mud weight, multiplied by 0.052 and by the shoe true vertical depth.

Driller's method

Kill method where the influx is circulated out at the original mud weight while holding casing pressure constant, then the well is weighted up and circulated with kill mud.

Wait and weight method

Kill method where the mud is weighted up to kill weight first, then pumped while the influx is circulated out, following a drill pipe pressure schedule from initial to final circulating pressure.

Kick indicators while drilling

Flow from the well with pumps off, pit gain, increased return flow, rising shut-in pressures, reduced pump pressure at constant rate, and gas or saltwater shows in returns.

Pit gain significance

Increase in active pit volume indicating formation fluid entering the wellbore. It estimates influx size and is recorded at shut-in for kill calculations and well control decisions.

Bottomhole pressure during kill

Must be kept at or slightly above formation pressure at all times. Achieved by holding casing pressure constant or by following the calculated drill pipe pressure schedule.

Choke line friction

Pressure loss through the choke line when circulating. It adds to casing pressure readings and must be accounted for when holding bottomhole pressure constant on a floating rig.

Shut-in procedure steps

Stop rotation, stop pumps, position the string for shut-in, close the BOP, open the choke, then read and record SIDPP, SICP, pit gain and strokes.

Trip margin

Extra mud weight above balance to cover swab pressure and gas expansion during trips. Reduces the risk of taking a kick while pulling out of hole.

Swab pressure

Reduction in bottomhole pressure caused by pulling pipe out of the hole. Excessive pull speed can drop pressure below formation pressure and induce a kick.

Surge pressure

Increase in bottomhole pressure caused by running pipe into the hole. Can fracture the formation if the pipe is run too fast.

Kick tolerance

Maximum influx volume that can be circulated out without exceeding the fracture pressure at the weakest point, usually the casing shoe.

Pressure gradient units

Expressed in psi per foot. Normal formation pressure gradient is about 0.465 psi/ft, equivalent to fresh water; higher values indicate abnormal pressure.

Mud weight equivalent

Formation pressure converted to an equivalent mud weight in ppg using pressure divided by 0.052 times true vertical depth. Used to compare pressures and set mud weight.

Strokes to bit

Number of pump strokes needed to move mud from the surface to the bit. Determines when kill mud reaches the bit and when the drill pipe pressure schedule changes.

Drill pipe pressure schedule

Table or graph of drill pipe pressure versus pump strokes, decreasing from initial to final circulating pressure as kill mud travels down the string.

Gas expansion in annulus

Gas rises and expands as it moves up the well. Casing pressure must be bled to allow expansion while keeping bottomhole pressure constant.

Kick while tripping

Kick taken when pipe is out of hole, often from swabbing. Shut in and calculate kill weight using the reduced hydrostatic from the pipe not being on bottom.

BOP stack function

Blowout preventer equipment seals the wellbore and allows circulation through the choke. Annular and ram preventers provide the primary barrier during well control operations.

Choke manifold purpose

Allows controlled release of wellbore fluids to maintain casing pressure and bottomhole pressure during a kill. Adjustable and fixed chokes provide the control.

Formation fracture pressure

Pressure at which the formation breaks down and accepts fluid. Exceeding it at the shoe causes lost circulation and loss of the primary barrier.

Kill weight margin

Additional mud weight above the calculated kill weight, typically 0.2 to 0.5 ppg, to provide overbalance and allow for pressure variations during the kill.

Pump pressure at kill start

Initial circulating pressure is held while the influx is circulated to surface using the original mud weight in the driller's method.

Well control barrier

Primary barrier is the mud column; secondary barrier is the BOP and casing. Both must be maintained to prevent an uncontrolled flow of formation fluids.