IWCF Level 4 Drilling flashcards
IWCF Level 4 Drilling · Build recall with a focused review session.
32 cards. Read the term and the definition here. The deck at the top of this page is optional.
- Hydrostatic pressure formula
- HP in psi equals 0.052 multiplied by mud weight in ppg multiplied by true vertical depth in feet. Always use TVD, never measured depth, because pressure depends only on vertical height of the fluid column.
- Mud gradient
- The pressure exerted per foot of vertical depth by a mud column, calculated as mud weight in ppg multiplied by 0.052, giving psi per foot. Used to compare mud weight directly with pore pressure and fracture gradients.
- Equivalent mud weight
- A pressure expressed as the mud weight that would create it at a given TVD: EMW in ppg equals pressure in psi divided by 0.052 times TVD in feet. Used to compare shut-in pressures with mud weight and fracture gradient.
- Kill mud weight
- The mud weight needed to balance formation pore pressure: current mud weight plus SIDPP divided by 0.052 times TVD. Round up to the next 0.1 ppg so the well stays slightly overbalanced.
- SIDPP
- Shut-in drill pipe pressure, read after the well is closed and pressures stabilize with the string open and unplugged. It reflects the difference between pore pressure at the bit and the mud hydrostatic column.
- SICP
- Shut-in casing pressure, recorded on the casing gauge after closure and stabilization. It equals pore pressure minus annulus hydrostatic plus any trapped pressure, and is generally higher than SIDPP because of annular friction and influx.
- Slow circulating rate
- A reduced pump rate, usually one quarter to one third of drilling rate, at which circulating pressures are measured. The recorded pressure at this rate is used to hold bottom-hole pressure constant during a kill.
- Initial circulating pressure
- ICP equals SIDPP plus the slow circulating rate pressure. It is the drill pipe pressure held at the start of a kill, when kill mud has not yet reached the bit and the original mud is still in the string.
- Final circulating pressure
- FCP equals kill mud weight divided by original mud weight, multiplied by the slow circulating rate pressure. It is held once kill mud reaches the bit and until the kill mud returns to surface.
- Strokes to bit
- The pump strokes needed to move fluid from the pump to the bit, calculated as drill string volume divided by pump output per stroke. It times the pressure schedule transition from ICP to FCP.
- Kick tolerance
- The maximum influx pressure the weakest exposed formation, usually the casing shoe, can tolerate before fracturing. It equals fracture gradient minus pore pressure gradient, multiplied by the shoe TVD.
- MAASP
- Maximum allowable annular surface pressure, calculated as fracture gradient minus current mud gradient, multiplied by the TVD of the casing shoe. It must be recalculated whenever the mud weight changes.
- Wait-and-weight method
- A kill method in which mud weight is increased to kill weight before circulating the influx out. The well is shut in while weighting up, and bottom-hole pressure is held constant once circulation begins.
- Driller's method
- A kill method that circulates the influx out using the original mud weight at the slow circulating rate, then circulates kill mud. Bottom-hole pressure is held constant throughout by adjusting the choke.
- Volumetric method
- A pressure control technique used when the bit is off bottom and the string is plugged. Mud is bled in measured steps to compensate for gas migration, keeping bottom-hole pressure constant without circulation.
- Lubricate and bleed
- A technique for trapped gas below a closed BOP: bleed a measured volume of mud while holding casing pressure, replacing gas with mud. It reduces surface pressure while keeping bottom-hole pressure constant.
- Soft shut-in
- A shut-in sequence: stop rotation, raise the string, stop pumps, close the BOP, then open the choke and record pressures. It minimizes pressure surges compared with a hard shut-in.
- Hard shut-in
- A shut-in sequence in which the BOP is closed with the choke already closed, trapping pressure immediately. It is faster but can produce higher surface pressures than a soft shut-in.
- Flow check
- A procedure to confirm a kick: stop pumps, wait several minutes, and observe the flow line. Continued flow with pumps off indicates formation influx and requires immediate shut-in.
- Kick indicators
- Signs of formation influx include pit gain, flow with pumps off, increased return rate, reduced pump pressure, connection gas, and a positive flow check. Any indicator requires a flow check and shut-in.
- Trip margin
- Extra mud weight added above pore pressure to offset swab pressure when pulling pipe. It helps prevent formation influx during trips and is removed or adjusted as conditions require.
- Swab pressure
- The reduction in bottom-hole pressure caused by pulling pipe out of the hole. Fast pipe speed, high mud viscosity, and small annular clearance increase swabbing and can induce a kick.
- Surge pressure
- The increase in bottom-hole pressure caused by running pipe into the hole. Excessive surge can fracture the formation and cause lost circulation, so running speed is controlled.
- Equivalent circulating density
- ECD equals hydrostatic pressure plus annular friction pressure, divided by 0.052 times TVD. It represents the effective mud weight the formation sees while circulating and must stay below fracture gradient.
- Formation integrity test
- A test that pressurizes the casing shoe to confirm it can withstand the planned mud weight. Results set the maximum allowable annular surface pressure and inform casing seat selection.
- Leak-off test
- A test in which the formation is pressurized until fluid begins to leak into it, giving the fracture initiation pressure. The result is used to calculate fracture gradient and MAASP.
- Bullheading
- Pumping fluid into the well to force the influx back into the formation, used when circulation is impossible. It requires knowledge of fracture pressure to avoid fracturing the formation.
- Stripping
- Moving pipe through a closed annular preventer while maintaining wellbore pressure. Mud volume is bled to compensate for pipe displacement so bottom-hole pressure stays constant.
- Annular preventer
- A BOP component with a flexible element that closes on any shape, including pipe, tools, or open hole. It allows stripping and rotation but has a lower pressure rating than ram preventers.
- Shear rams
- BOP rams designed to cut drill pipe and seal the wellbore. They are used when the string cannot be closed with pipe rams or when an emergency disconnect is required.
- Choke manifold
- A system of valves and adjustable or fixed chokes that routes returning fluid and controls casing pressure during a kill. It must be rated for maximum anticipated surface pressure and tested regularly.
- Accumulator
- A hydraulic power source that stores pressurized fluid to operate BOP functions. It must have enough usable volume to close all BOP functions and hold reserve pressure per API standards.