IWCF Level 2 Drilling flashcards
IWCF Level 2 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 (psi) = 0.052 × mud weight in ppg × true vertical depth in feet. TVD must be used, not measured depth, because pressure depends only on vertical height of the fluid column.
- SIDPP
- Shut-in drill pipe pressure, read at surface after the well is closed and pressures stabilize. It represents the difference between formation pore pressure and the mud hydrostatic pressure in the drill string.
- SITP
- Shut-in tubing or casing pressure, read on the annulus side after closure. It is normally higher than SIDPP when the annulus contains a lighter influx, such as gas, above the heavier mud.
- Kill mud weight formula
- Kill mud weight (ppg) equals current mud weight plus SIDPP divided by (0.052 × TVD). This density balances formation pressure when circulated to the bit and up the annulus.
- Slow circulating rate pressure
- SCR is the pump pressure recorded at a low, fixed pump rate with the bit off bottom and the well circulating. It is the baseline used to build the kill sheet and calculate ICP and FCP.
- Initial circulating pressure
- ICP equals SIDPP plus the slow circulating rate pressure. It is the pressure held on the drill pipe at the start of the kill, with the original mud weight in the hole.
- Final circulating pressure
- FCP equals kill mud weight divided by old mud weight, multiplied by SCR. It is the drill pipe pressure expected once kill mud reaches the bit.
- MAASP
- Maximum allowable annular surface pressure equals (fracture pressure equivalent at shoe minus current mud weight) × 0.052 × shoe TVD. Exceeding it risks fracturing the formation at the casing shoe.
- Kick indicators
- Warning signs include flow with pumps off, pit gain, rising flow rate, pump pressure drop, gas or oil shows, and reduced rate of penetration. Any one requires investigation before continuing.
- Annular preventer function
- A rubber element that closes on any shape in the wellbore, including pipe, tools, or open hole. It allows stripping and rotating under pressure but has lower pressure rating than ram preventers.
- Blind shear rams
- Rams that close the open hole and can shear drill pipe when no pipe is present or when the string must be cut. They provide a hard barrier in an emergency.
- Choke manifold purpose
- A system of valves and adjustable chokes that controls flow from the well while keeping back pressure on the formation. It is used to circulate out a kick at controlled pressure.
- Wait and weight method
- A kill method where the well is shut in while kill mud is mixed, then circulated in one pass. It usually results in lower casing shoe pressures than the driller's method.
- Driller's method
- A kill method where the influx is circulated out first using the original mud weight, then kill mud is circulated. It is faster to start but produces higher shoe pressures.
- Shut-in procedure steps
- Stop rotation, lift string off bottom, stop pumps, close the BOP, then read and record SIDPP and SITP after stabilization. Record pit gain and time of closure.
- Trip margin
- Extra mud weight added above pore pressure to compensate for swabbing effects when pulling pipe. It reduces the chance of an influx entering during trips.
- Swabbing
- A reduction in bottomhole pressure caused by pulling pipe upward, which can allow formation fluid to enter the well. Fast pulls and thick mud increase the swabbing effect.
- Two-barrier principle
- At all times during drilling or intervention, at least two independent well barriers must be in place. A single barrier, such as one closed BOP, is never considered sufficient.
- Lubricator length rule
- The lubricator must be long enough to fully house the longest toolstring before the well is opened. Otherwise tools cannot be safely inserted or removed under pressure.
- Snubbing definition
- Moving pipe into or out of a well against pressure that would otherwise push the pipe out. It requires a snubbing unit with slips and jacks to control the pipe.
- Stripping definition
- Moving pipe through a closed BOP while well pressure is contained but the pipe can still be moved by rig or unit weight. It differs from snubbing in the force required.
- Coiled tubing fatigue
- Each bending cycle over the reel and guide arch consumes part of the string's fatigue life. The string is retired when remaining life reaches the operator's set limit.
- Bullheading definition
- Pumping fluid into the formation to displace wellbore fluids and stop a flow. It is used when circulation is impossible or when the formation can safely accept the fluid.
- BOP function test
- A test that verifies the BOP closes and opens correctly, typically done weekly. It checks operation, not pressure integrity, which requires a separate pressure test.
- BOP pressure test
- A test that pressurizes the closed BOP and stack to a specified value, commonly every 14 or 21 days depending on operator policy, and after any seal repair.
- Intervention kill fluid density
- Kill fluid density equals current density plus SITHP divided by (0.052 × TVD). SITHP is the shut-in tubing head pressure measured at surface.
- Hydraulic workover unit
- A unit using slips and a traveling snubbing jack to move pipe under pressure. Its BOP stack must be rated above the maximum anticipated surface pressure.
- Lubricator pressure test
- The lubricator and intervention stack are tested to the lower of MAASP or the rated working pressure of the weakest component in the assembly.
- Wireline BOP purpose
- A wireline BOP seals around the wire or cable while allowing it to move. It provides a barrier during wireline operations when the well must be closed.
- Well control barrier envelope
- The set of independent barriers, such as BOP, cement, casing, and kill fluid, that prevent uncontrolled flow. Loss of any one barrier requires immediate action.
- Kill line and choke line
- Lines on the BOP stack used to circulate kill mud in and flow out under pressure. They must be pressure tested and free of obstructions before a kill operation.
- Maximum anticipated surface pressure
- The highest pressure expected at surface during intervention, used to select equipment ratings. Equipment must be rated above this value with an adequate safety margin.