IWCF Level 4 Drilling cheat sheet

Primary well control: the hydrostatic pressure of the drilling fluid column balances or slightly exceeds formation pore pressure; formation pressure = hydrostatic pressure + any applied surface pressure.

Hydrostatic pressure formula: HP (psi) = 0.052 × mud weight (ppg) × true vertical depth (ft). Use TVD, never measured depth, for pressure calculations.

Mud gradient (psi/ft) = mud weight (ppg) × 0.052; equivalent mud weight (ppg) = pressure (psi) ÷ (0.052 × TVD ft).

Kill mud weight (ppg) = current mud weight + (SIDPP psi ÷ (0.052 × TVD ft)); SIDPP read with the well shut in and stabilized gives pore pressure at the bit.

SICP minus SIDPP approximates the annular friction (and any trapped pressure) at shut-in; with a non-return float, SIDPP must be read through the drill string using the slow circulating rate.

Slow Circulating Rate (SCR) / kill rate pressure is recorded at a low pump rate (typically 1/4 to 1/3 of drilling rate) and is used to hold bottom-hole pressure constant while circulating out a kick.

Initial Circulating Pressure (ICP) = SIDPP + SCR pressure; Final Circulating Pressure (FCP) = kill mud weight ÷ original mud weight × SCR pressure.

Kick indicators: pit gain, flow with pumps off, increase in return flow rate, reduction in pump pressure, gas/connection gas increase, and a positive flow check; shut in and record pressures before acting.

Kick tolerance (psi) = (fracture gradient − pore pressure gradient) × TVD of the shoe; it is the maximum influx pressure the weakest exposed formation can tolerate before fracturing.

Wait-and-weight vs. driller's method: both hold bottom-hole pressure constant; wait-and-weight raises mud weight first, driller's method circulates the influx out on the original mud then weights up.

Driller's method steps: circulate out the kick at SCR holding ICP, then circulate kill mud at FCP, keeping casing shoe pressure below fracture gradient throughout.

Volumetric method: when the bit is off bottom and the string is plugged, bleed mud in controlled steps to keep bottom-hole pressure constant as gas migrates; each bleed volume corresponds to a pressure increment.

Lubricate-and-bleed: used when gas is trapped below a closed BOP; bleed a measured volume of mud while maintaining casing pressure, replacing gas with mud to reduce surface pressure.

Shut-in procedure (soft shut-in): stop rotation, raise string, stop pumps, close BOP, then open choke and record SIDPP/SICP; hard shut-in closes the BOP with the choke already closed.

Kill sheet records: SIDPP, SICP, SCR, ICP, FCP, slow pump rate (strokes/min), and strokes to bit; strokes to bit = drill string volume ÷ pump output per stroke.

Kick circulation schedule: maintain constant bottom-hole pressure by adjusting choke; as kill mud fills the string, casing pressure follows the calculated schedule; when kill mud reaches the bit, ICP transitions to FCP.

BOP stack components: annular preventer for stripping and closing on any shape; ram preventers (pipe, blind, shear) for hard closure; choke manifold and kill line for circulation; inside BOP for string closure.

Well control barrier principle: two independent barriers (e.g., mud column plus BOP/wellhead) must be in place; primary barrier is the hydrostatic column, secondary is the mechanical BOP system.

Kick causes: insufficient mud weight, lost circulation lowering the column, swabbing on trips (pulling pipe too fast or with a balled bit), and failure to fill the hole on trips.

Trip margin (overbalance) is added to mud weight to offset swab and surge pressures; fill the hole on every stand pulled to keep the hydrostatic column intact.

Maximum allowable annular surface pressure (MAASP) = (fracture gradient − current mud gradient) × TVD of the casing shoe; recalculate whenever mud weight changes.

Gas expansion follows Boyle's law: as gas migrates up and pressure falls, volume expands; never allow gas to expand uncontrolled at surface - hold back pressure with the choke.

Choke line friction and annular friction must be included in pressure calculations; SCR reflects total system friction at the kill rate.

Formation integrity test (FIT) / leak-off test (LOT) establishes the maximum mud weight the shoe can hold; MAASP derives from this test result.

When circulating a kick, keep pump rate constant; pump pressure changes reflect changing friction, so adjust the choke to hold the calculated casing or drill pipe pressure schedule.

Influx type: gas expands significantly with pressure drop and requires careful choke control; water or oil influxes are less expansive but still must be circulated out with constant bottom-hole pressure.

Record and report: kick volume, shut-in pressures, kill method used, and final mud weight; these are required for IWCF well control documentation and post-well review.

Pressure balance at the bit during kill: bottom-hole pressure = hydrostatic pressure in the annulus + casing pressure (with pumps off); during circulation, add annular friction.

Pump output per stroke (bbl/stroke) = pump displacement; strokes to bit = (drill string internal volume + surface line volume) ÷ pump output per stroke.

Kill mud weight rounding: round up to the nearest 0.1 ppg to ensure overbalance; never round down.

If SIDPP and SICP do not stabilize, check for trapped pressure, plugged bit, or float; bleed pressure carefully and re-read before calculating kill weight.

Annular preventer pressure ratings and closing times must be known; test BOPs to the rated pressure before drilling out the shoe.

Shear rams are used to cut drill pipe and seal the well when the string cannot be closed with pipe rams; blind rams close on open hole.

Kick detection while drilling: monitor pit level, flow-out vs. flow-in, pump pressure, and gas readings; a flow check with pumps off confirms a kick.

Well control drills: pit drills and BOP drills are required at specified intervals; crew must know shut-in procedure and alarm signals.

Equivalent circulating density (ECD, ppg) = (hydrostatic pressure + annular friction pressure) ÷ (0.052 × TVD ft); high ECD can fracture the formation and cause lost circulation.

Surge and swab pressures depend on pipe speed, mud rheology, and annular clearance; pulling pipe too fast reduces bottom-hole pressure and can induce a kick.

Kill line and choke line must be pressure-tested and clear of obstructions before use; a plugged choke line prevents pressure control.

When the bit is off bottom, use the volumetric method or lubricate-and-bleed; do not attempt to circulate a kick with the bit off bottom unless necessary, and use low pump rates.

Stripping: moving pipe through a closed annular preventer while maintaining wellbore pressure; monitor and bleed mud volume to compensate for pipe displacement.

Well control matrix: if SIDPP and SICP are both low, suspect lost circulation; if both high, suspect a kick; if SIDPP high and SICP low, suspect a plugged bit or float.

Final circulating pressure must be held until kill mud reaches surface; then the well is static with kill mud and the BOP can be opened after a flow check.

Post-kick: verify kill mud weight, test BOPs if required, and record all pressures and volumes for the well control report.

Hydrostatic pressure in psi = 0.052 × ppg × TVD ft; for SI units, HP (bar) = 0.0981 × mud density (kg/m³) × TVD (m) ÷ 1000.

Mud weight conversion: 1 ppg = 0.1198 psi/ft gradient; 1 psi/ft = 8.34 ppg.

Formation pressure gradient (ppg equivalent) = pore pressure (psi) ÷ (0.052 × TVD ft); compare with mud weight to assess overbalance.

Kick volume at surface = pit gain; use it to estimate influx size and to plan the kill; large gains require immediate shut-in and pressure recording.

Choke operator must hold casing pressure on the schedule; drill pipe pressure is the primary control when the bit is on bottom and the string is not plugged.

If the drill string is plugged, control is by casing pressure and the volumetric method; SIDPP cannot be read, so use SICP and known mud weight.

BOP test pressure: low-pressure test (typically 250-300 psi) then high-pressure test to rated working pressure; record and document results.

Well control certification (IWCF Level 4) requires demonstrated competence in shut-in, kill sheet preparation, and kill circulation for surface and subsea BOP stacks.

Subsea well control: choke line friction and riser margin must be included; MAASP is referenced to the casing shoe and adjusted for water depth and riser.

Riser margin is added to mud weight when drilling from a floating rig to compensate for loss of riser hydrostatic if the riser is disconnected.

Kill mud weight for subsea wells uses the same SIDPP ÷ (0.052 × TVD) formula, but TVD is measured from the rotary table or from the wellhead as specified in the kill sheet.

Shut-in on a floating rig: close annular or pipe rams, then read SIDPP and SICP after stabilization; account for choke line friction in ICP.

BOP stack for subsea: annular, pipe rams, blind/shear rams, and a lower marine riser package (LMRP); testing includes function tests and pressure tests.

Kick tolerance is reduced in deepwater because fracture gradient at the shoe is lower relative to pore pressure; small influxes can fracture the formation.

Well control drills and weekly BOP function tests are required; crew must know the emergency disconnect sequence and its effect on wellbore pressure.

Documentation: kill sheet, pressure test records, and kick reports are retained; IWCF assessment includes written and practical well control scenarios.

Primary well control relies on mud weight; secondary well control relies on BOP and choke manifold; tertiary (bullheading) is a last resort to pump the influx back into the formation.

Bullheading: pump fluid into the well to force the influx back into the formation; used when circulation is impossible; requires knowledge of formation fracture pressure.

Relief well and dynamic kill are advanced options for blowout control; they require coordination and are outside routine well control.

Kick detection while tripping: fill the hole with mud of the correct volume for each stand pulled; a short fill indicates a kick or lost circulation.

Flow check procedure: stop pumps, wait for flow to cease (typically 5-15 minutes), observe flow line; continued flow indicates a kick and requires shut-in.

Shut-in pressures should be recorded within the shortest practical time; delay allows gas migration and increases surface pressure.

Kill sheet verification: check SIDPP, SICP, SCR, ICP, FCP, strokes to bit, and mud weight calculations before starting the kill.

After the kill, circulate one full bottoms-up to verify no influx remains, then flow check and resume operations with the new mud weight.

Well control equipment: BOP stack, choke manifold, kill line, choke line, accumulator, and pressure gauges; each must be rated for the maximum anticipated surface pressure.

Accumulator capacity must be sufficient to close all BOP functions and have reserve; precharge pressure and usable volume are specified by API standards.

Choke types: fixed choke (orifice) and adjustable choke; adjustable chokes allow fine control of casing pressure during a kill.

Pressure gauges: drill pipe pressure gauge, casing pressure gauge, and pump pressure gauge; calibrate and verify before use.

Kick alarm and shutdown: automatic systems detect flow and pit gain; crew response follows the well control procedure and muster alarm.

Well control training standards (IWCF) cover principles, procedures, and equipment for surface and subsea operations at Levels 1-4; Level 4 is the supervisor/wellsite leader level.

Assessment includes a written examination and practical scenarios; candidates must demonstrate shut-in, kill sheet, and kill circulation competence.

Record-keeping: daily drilling reports, BOP test records, and kick reports are part of well control documentation and audit requirements.

Pressure units: 1 bar = 14.5038 psi; 1 psi = 0.06895 bar; 1 MPa = 145.038 psi; convert consistently in kill sheet calculations.

Mud weight units: ppg, kg/m³, and SG; 1 SG = 8.345 ppg = 1000 kg/m³; use the same unit system throughout.

TVD vs. MD: TVD is vertical depth used for pressure; MD is along-hole depth used for volumes and strokes; never mix them in pressure formulas.

Annular volume (bbl) = annular capacity (bbl/ft) × length (ft); annular capacity depends on hole and pipe diameters and is taken from tables or calculated.

Pump output per stroke is measured by pumping into a calibrated tank; strokes to bit = string volume ÷ output per stroke.

Kill mud weight must be circulated to the bit before FCP is applied; the pressure schedule transitions from ICP to FCP as kill mud fills the string.

Casing pressure during kill is adjusted to hold bottom-hole pressure constant; drill pipe pressure is held on the schedule when the string is open and unplugged.

If the choke plugs, switch to the standby choke, restore pressure, and continue; never open the choke fully to clear it while the well is flowing.

Well control scenarios: kick while drilling, kick while tripping, kick while off bottom, and kick with the bit plugged; each has a specific procedure and pressure control method.

Kick while tripping: stop, close BOP, record pressures; if the bit is off bottom, use volumetric or lubricate-and-bleed until the bit can be run back to bottom.

Kick while off bottom: do not attempt to circulate unless the bit is near bottom; use volumetric method to control migration, then run in hole to kill.

Plugged bit: SIDPP cannot be read; control by casing pressure and volumetric method; do not attempt to clear the bit while the well is shut in without pressure control.

Well control while drilling with a motor or MWD: account for pressure losses and tool limitations; low pump rates may be required for the kill.

Kick tolerance is a planning tool; if the influx pressure exceeds kick tolerance, the shoe may fracture and the well must be killed before the influx reaches the shoe.

Emergency response: muster alarm, shut-in, notify supervisor, and prepare kill sheet; communication and role assignment are part of the drill.

Post-incident review: identify root cause (mud weight, swab, lost circulation, equipment failure) and implement corrective actions.

Formation pressure estimation: pore pressure from offset wells, seismic, and drilling indicators (dc exponent, gas, flow); mud weight is selected to provide overbalance.

Fracture gradient estimation: from leak-off tests, formation integrity tests, and offset data; used to set casing seats and MAASP.

Casing design: each casing string must withstand the maximum anticipated pressure; shoe depth is selected where fracture gradient exceeds mud weight.

Kick tolerance calculation example: (0.75 psi/ft − 0.5 psi/ft) × 5000 ft = 1250 psi; this is the maximum influx pressure the shoe can tolerate.

MAASP example: (0.75 psi/ft − 0.5 psi/ft) × 5000 ft = 1250 psi; recalculate when mud weight changes.

Kill mud weight example: SIDPP 500 psi, TVD 10,000 ft, current mud 10 ppg; kill weight = 10 + 500 ÷ (0.052 × 10,000) = 10 + 0.96 = 10.96 ppg, round to 11.0 ppg.

ICP example: SIDPP 500 psi + SCR 400 psi = 900 psi; FCP = (11.0 ÷ 10.0) × 400 = 440 psi.

Strokes to bit example: string volume 120 bbl ÷ 0.1 bbl/stroke = 1200 strokes; use to time the kill mud arrival at the bit.

Well control barriers: primary (mud), secondary (BOP), tertiary (bullheading/relief well); two independent barriers must be verified before operations.

BOP stack testing: function test weekly, pressure test before drilling out shoe and at specified intervals; test to rated pressure with low-pressure test first.

Annular preventer: closes on any shape, used for stripping and rotating; pressure rating lower than ram preventers.

Ram preventers: pipe rams close on specific pipe size; blind rams close on open hole; shear rams cut pipe and seal.

Choke manifold: routes flow through adjustable or fixed chokes; must be rated for maximum anticipated surface pressure and tested.

Kill line: connects pump to wellbore below BOP; used to pump kill mud; must be clear and pressure-tested.

Inside BOP: installed in the drill string to close it; used when the string is open and cannot be closed with rams.

Well control drills: pit drills, BOP drills, and kick drills are required at specified intervals; crew must know alarm signals and procedures.

Kick circulation: hold bottom-hole pressure constant by adjusting choke; as kill mud fills the string, casing pressure follows the schedule; when kill mud reaches the bit, ICP transitions to FCP.

Pressure schedule: drill pipe pressure decreases linearly from ICP to FCP as kill mud fills the string; casing pressure is adjusted to maintain bottom-hole pressure.

Choke operator must monitor both drill pipe and casing pressure; drill pipe pressure is primary when the string is open; casing pressure is primary when the string is plugged.

Kill mud displacement: after kill mud reaches the bit, hold FCP until kill mud returns to surface; then the well is static with kill mud.

Flow check after kill: stop pumps, observe flow; if no flow, open BOP and resume operations with kill mud weight.

Kick report: record SIDPP, SICP, pit gain, kill method, kill mud weight, and final pressures; required for IWCF documentation.

Well control certification: IWCF Level 4 covers supervisory well control; assessment includes written exam and practical scenarios.

Continuous improvement: review kick reports and drills to identify gaps and improve procedures.

Hydrostatic pressure in the annulus = 0.052 × mud weight × TVD; bottom-hole pressure = hydrostatic + casing pressure (pumps off).

During circulation, bottom-hole pressure = hydrostatic + annular friction + casing pressure; annular friction is estimated from SCR.

SIDPP reflects pore pressure at the bit when the string is open and unplugged; SICP reflects pore pressure plus annular friction and any trapped pressure.

Kick volume = pit gain; use it to estimate influx size and to plan the kill; large gains require immediate shut-in.

Kill mud weight must be circulated to the bit before FCP is applied; the pressure schedule transitions from ICP to FCP as kill mud fills the string.

If the drill string is plugged, control is by casing pressure and the volumetric method; SIDPP cannot be read, so use SICP and known mud weight.

BOP test pressure: low-pressure test (typically 250-300 psi) then high-pressure test to rated working pressure; record and document results.

Well control certification (IWCF Level 4) requires demonstrated competence in shut-in, kill sheet preparation, and kill circulation for surface and subsea BOP stacks.

Subsea well control: choke line friction and riser margin must be included; MAASP is referenced to the casing shoe and adjusted for water depth and riser.

Riser margin is added to mud weight when drilling from a floating rig to compensate for loss of riser hydrostatic if the riser is disconnected.

Kill mud weight for subsea wells uses the same SIDPP ÷ (0.052 × TVD) formula, but TVD is measured from the rotary table or from the wellhead as specified in the kill sheet.

Shut-in on a floating rig: close annular or pipe rams, then read SIDPP and SICP after stabilization; account for choke line friction in ICP.

BOP stack for subsea: annular, pipe rams, blind/shear rams, and a lower marine riser package (LMRP); testing includes function tests and pressure tests.

Kick tolerance is reduced in deepwater because fracture gradient at the shoe is lower relative to pore pressure; small influxes can fracture the formation.

Well control drills and weekly BOP function tests are required; crew must know the emergency disconnect sequence and its effect on wellbore pressure.

Documentation: kill sheet, pressure test records, and kick reports are retained; IWCF assessment includes written and practical well control scenarios.

Primary well control relies on mud weight; secondary well control relies on BOP and choke manifold; tertiary (bullheading) is a last resort to pump the influx back into the formation.

Bullheading: pump fluid into the well to force the influx back into the formation; used when circulation is impossible; requires knowledge of formation fracture pressure.

Relief well and dynamic kill are advanced options for blowout control; they require coordination and are outside routine well control.

Kick detection while tripping: fill the hole with mud of the correct volume for each stand pulled; a short fill indicates a kick or lost circulation.

Flow check procedure: stop pumps, wait for flow to cease (typically 5-15 minutes), observe flow line; continued flow indicates a kick and requires shut-in.

Shut-in pressures should be recorded within the shortest practical time; delay allows gas migration and increases surface pressure.

Kill sheet verification: check SIDPP, SICP, SCR, ICP, FCP, strokes to bit, and mud weight calculations before starting the kill.

After the kill, circulate one full bottoms-up to verify no influx remains, then flow check and resume operations with the new mud weight.

Well control equipment: BOP stack, choke manifold, kill line, choke line, accumulator, and pressure gauges; each must be rated for the maximum anticipated surface pressure.

Accumulator capacity must be sufficient to close all BOP functions and have reserve; precharge pressure and usable volume are specified by API standards.

Choke types: fixed choke (orifice) and adjustable choke; adjustable chokes allow fine control of casing pressure during a kill.

Pressure gauges: drill pipe pressure gauge, casing pressure gauge, and pump pressure gauge; calibrate and verify before use.

Kick alarm and shutdown: automatic systems detect flow and pit gain; crew response follows the well control procedure and muster alarm.

Well control training standards (IWCF) cover principles, procedures, and equipment for surface and subsea operations at Levels 1-4; Level 4 is the supervisor/wellsite leader level.

Assessment includes a written examination and practical scenarios; candidates must demonstrate shut-in, kill sheet, and kill circulation competence.

Record-keeping: daily drilling reports, BOP test records, and kick reports are part of well control documentation and audit requirements.

Pressure units: 1 bar = 14.5038 psi; 1 psi = 0.06895 bar; 1 MPa = 145.038 psi; convert consistently in kill sheet calculations.

Mud weight units: ppg, kg/m³, and SG; 1 SG = 8.345 ppg = 1000 kg/m³; use the same unit system throughout.

TVD vs. MD: TVD is vertical depth used for pressure; MD is along-hole depth used for volumes and strokes; never mix them in pressure formulas.

Annular volume (bbl) = annular capacity (bbl/ft) × length (ft); annular capacity depends on hole and pipe diameters and is taken from tables or calculated.

Pump output per stroke is measured by pumping into a calibrated tank; strokes to bit = string volume ÷ output per stroke.

Kill mud weight must be circulated to the bit before FCP is applied; the pressure schedule transitions from ICP to FCP as kill mud fills the string.

Casing pressure during kill is adjusted to hold bottom-hole pressure constant; drill pipe pressure is held on the schedule when the string is open and unplugged.

If the choke plugs, switch to the standby choke, restore pressure, and continue; never open the choke fully to clear it while the well is flowing.

Well control scenarios: kick while drilling, kick while tripping, kick while off bottom, and kick with the bit plugged; each has a specific procedure and pressure control method.

Kick while tripping: stop, close BOP, record pressures; if the bit is off bottom, use volumetric or lubricate-and-bleed until the bit can be run back to bottom.

Kick while off bottom: do not attempt to circulate unless the bit is near bottom; use volumetric method to control migration, then run in hole to kill.

Plugged bit: SIDPP cannot be read; control by casing pressure and volumetric method; do not attempt to clear the bit while the well is shut in without pressure control.

Well control while drilling with a motor or MWD: account for pressure losses and tool limitations; low pump rates may be required for the kill.

Kick tolerance is a planning tool; if the influx pressure exceeds kick tolerance, the shoe may fracture and the well must be killed before the influx reaches the shoe.

Emergency response: muster alarm, shut-in, notify supervisor, and prepare kill sheet; communication and role assignment are part of the drill.

Post-incident review: identify root cause (mud weight, swab, lost circulation, equipment failure) and implement corrective actions.

Formation pressure estimation: pore pressure from offset wells, seismic, and drilling indicators (dc exponent, gas, flow); mud weight is selected to provide overbalance.

Fracture gradient estimation: from leak-off tests, formation integrity tests, and offset data; used to set casing seats and MAASP.

Casing design: each casing string must withstand the maximum anticipated pressure; shoe depth is selected where fracture gradient exceeds mud weight.

Kick tolerance calculation example: (0.75 psi/ft − 0.5 psi/ft) × 5000 ft = 1250 psi; this is the maximum influx pressure the shoe can tolerate.

MAASP example: (0.75 psi/ft − 0.5 psi/ft) × 5000 ft = 1250 psi; recalculate when mud weight changes.

Kill mud weight example: SIDPP 500 psi, TVD 10,000 ft, current mud 10 ppg; kill weight = 10 + 500 ÷ (0.052 × 10,000) = 10 + 0.96 = 10.96 ppg, round to 11.0 ppg.

ICP example: SIDPP 500 psi + SCR 400 psi = 900 psi; FCP = (11.0 ÷ 10.0) × 400 = 440 psi.

Strokes to bit example: string volume 120 bbl ÷ 0.1 bbl/stroke = 1200 strokes; use to time the kill mud arrival at the bit.

Well control barriers: primary (mud), secondary (BOP), tertiary (bullheading/relief well); two independent barriers must be verified before operations.

BOP stack testing: function test weekly, pressure test before drilling out shoe and at specified intervals; test to rated pressure with low-pressure test first.

Annular preventer: closes on any shape, used for stripping and rotating; pressure rating lower than ram preventers.

Ram preventers: pipe rams close on specific pipe size; blind rams close on open hole; shear rams cut pipe and seal.

Choke manifold: routes flow through adjustable or fixed chokes; must be rated for maximum anticipated surface pressure and tested.

Kill line: connects pump to wellbore below BOP; used to pump kill mud; must be clear and pressure-tested.

Inside BOP: installed in the drill string to close it; used when the string is open and cannot be closed with rams.

Well control drills: pit drills, BOP drills, and kick drills are required at specified intervals; crew must know alarm signals and procedures.

Kick circulation: hold bottom-hole pressure constant by adjusting choke; as kill mud fills the string, casing pressure follows the schedule; when kill mud reaches the bit, ICP transitions to FCP.

Pressure schedule: drill pipe pressure decreases linearly from ICP to FCP as kill mud fills the string; casing pressure is adjusted to maintain bottom-hole pressure.

Choke operator must monitor both drill pipe and casing pressure; drill pipe pressure is primary when the string is open; casing pressure is primary when the string is plugged.

Kill mud displacement: after kill mud reaches the bit, hold FCP until kill mud returns to surface; then the well is static with kill mud.

Flow check after kill: stop pumps, observe flow; if no flow, open BOP and resume operations with kill mud weight.

Kick report: record SIDPP, SICP, pit gain, kill method, kill mud weight, and final pressures; required for IWCF documentation.

Well control certification: IWCF Level 4 covers supervisory well control; assessment includes written exam and practical scenarios.

Continuous improvement: review kick reports and drills to identify gaps and improve procedures.

Hydrostatic pressure in the annulus = 0.052 × mud weight × TVD; bottom-hole pressure = hydrostatic + casing pressure (pumps off).

During circulation, bottom-hole pressure = hydrostatic + annular friction + casing pressure; annular friction is estimated from SCR.

SIDPP reflects pore pressure at the bit when the string is open and unplugged; SICP reflects pore pressure plus annular friction and any trapped pressure.

Kick volume = pit gain; use it to estimate influx size and to plan the kill; large gains require immediate shut-in.

Kill mud weight must be circulated to the bit before FCP is applied; the pressure schedule transitions from ICP to FCP as kill mud fills the string.

If the drill string is plugged, control is by casing pressure and the volumetric method; SIDPP cannot be read, so use SICP and known mud weight.

BOP test pressure: low-pressure test (typically 250-300 psi) then high-pressure test to rated working pressure; record and document results.

Well control certification (IWCF Level 4) requires demonstrated competence in shut-in, kill sheet preparation, and kill circulation for surface and subsea BOP stacks.

Subsea well control: choke line friction and riser margin must be included; MAASP is referenced to the casing shoe and adjusted for water depth and riser.

Riser margin is added to mud weight when drilling from a floating rig to compensate for loss of riser hydrostatic if the riser is disconnected.

Kill mud weight for subsea wells uses the same SIDPP ÷ (0.052 × TVD) formula, but TVD is measured from the rotary table or from the wellhead as specified in the kill sheet.

Shut-in on a floating rig: close annular or pipe rams, then read SIDPP and SICP after stabilization; account for choke line friction in ICP.

BOP stack for subsea: annular, pipe rams, blind/shear rams, and a lower marine riser package (LMRP); testing includes function tests and pressure tests.

Kick tolerance is reduced in deepwater because fracture gradient at the shoe is lower relative to pore pressure; small influxes can fracture the formation.

Well control drills and weekly BOP function tests are required; crew must know the emergency disconnect sequence and its effect on wellbore pressure.

Documentation: kill sheet, pressure test records, and kick reports are retained; IWCF assessment includes written and practical well control scenarios.

Primary well control relies on mud weight; secondary well control relies on BOP and choke manifold; tertiary (bullheading) is a last resort to pump the influx back into the formation.

Bullheading: pump fluid into the well to force the influx back into the formation; used when circulation is impossible; requires knowledge of formation fracture pressure.

Relief well and dynamic kill are advanced options for blowout control; they require coordination and are outside routine well control.

Kick detection while tripping: fill the hole with mud of the correct volume for each stand pulled; a short fill indicates a kick or lost circulation.

Flow check procedure: stop pumps, wait for flow to cease (typically 5-15 minutes), observe flow line; continued flow indicates a kick and requires shut-in.

Shut-in pressures should be recorded within the shortest practical time; delay allows gas migration and increases surface pressure.

Kill sheet verification: check SIDPP, SICP, SCR, ICP, FCP, strokes to bit, and mud weight calculations before starting the kill.

After the kill, circulate one full bottoms-up to verify no influx remains, then flow check and resume operations with the new mud weight.

Well control equipment: BOP stack, choke manifold, kill line, choke line, accumulator, and pressure gauges; each must be rated for the maximum anticipated surface pressure.

Accumulator capacity must be sufficient to close all BOP functions and have reserve; precharge pressure and usable volume are specified by API standards.

Choke types: fixed choke (orifice) and adjustable choke; adjustable chokes allow fine control of casing pressure during a kill.

Pressure gauges: drill pipe pressure gauge, casing pressure gauge, and pump pressure gauge; calibrate and verify before use.

Kick alarm and shutdown: automatic systems detect flow and pit gain; crew response follows the well control procedure and muster alarm.

Well control training standards (IWCF) cover principles, procedures, and equipment for surface and subsea operations at Levels 1-4; Level 4 is the supervisor/wellsite leader level.

Assessment includes a written examination and practical scenarios; candidates must demonstrate shut-in, kill sheet, and kill circulation competence.

Record-keeping: daily drilling reports, BOP test records, and kick reports are part of well control documentation and audit requirements.

Pressure units: 1 bar = 14.5038 psi; 1 psi = 0.06895 bar; 1 MPa = 145.038 psi; convert consistently in kill sheet calculations.

Mud weight units: ppg, kg/m³, and SG; 1 SG = 8.345 ppg = 1000 kg/m³; use the same unit system throughout.

TVD vs. MD: TVD is vertical depth used for pressure; MD is along-hole depth used for volumes and strokes; never mix them in pressure formulas.

Annular volume (bbl) = annular capacity (bbl/ft) × length (ft); annular capacity depends on hole and pipe diameters and is taken from tables or calculated.

Pump output per stroke is measured by pumping into a calibrated tank; strokes to bit = string volume ÷ output per stroke.

Kill mud weight must be circulated to the bit before FCP is applied; the pressure schedule transitions from ICP to FCP as kill mud fills the string.

Casing pressure during kill is adjusted to hold bottom-hole pressure constant; drill pipe pressure is held on the schedule when the string is open and unplugged.

If the choke plugs, switch to the standby choke, restore pressure, and continue; never open the choke fully to clear it while the well is flowing.

Well control scenarios: kick while drilling, kick while tripping, kick while off bottom, and kick with the bit plugged; each has a specific procedure and pressure control method.

Kick while tripping: stop, close BOP, record pressures; if the bit is off bottom, use volumetric or lubricate-and-bleed until the bit can be run back to bottom.

Kick while off bottom: do not attempt to circulate unless the bit is near bottom; use volumetric method to control migration, then run in hole to kill.

Plugged bit: SIDPP cannot be read; control by casing pressure and volumetric method; do not attempt to clear the bit while the well is shut in without pressure control.

Well control while drilling with a motor or MWD: account for pressure losses and tool limitations; low pump rates may be required for the kill.

Kick tolerance is a planning tool; if the influx pressure exceeds kick tolerance, the shoe may fracture and the well must be killed before the influx reaches the shoe.

Emergency response: muster alarm, shut-in, notify supervisor, and prepare kill sheet; communication and role assignment are part of the drill.

Post-incident review: identify root cause (mud weight, swab, lost circulation, equipment failure) and implement corrective actions.

Formation pressure estimation: pore pressure from offset wells, seismic, and drilling indicators (dc exponent, gas, flow); mud weight is selected to provide overbalance.

Fracture gradient estimation: from leak-off tests, formation integrity tests, and offset data; used to set casing seats and MAASP.

Casing design: each casing string must withstand the maximum anticipated pressure; shoe depth is selected where fracture gradient exceeds mud weight.

Kick tolerance calculation example: (0.75 psi/ft − 0.5 psi/ft) × 5000 ft = 1250 psi; this is the maximum influx pressure the shoe can tolerate.

MAASP example: (0.75 psi/ft − 0.5 psi/ft) × 5000 ft = 1250 psi; recalculate when mud weight changes.

Kill mud weight example: SIDPP 500 psi, TVD 10,000 ft, current mud 10 ppg; kill weight = 10 + 500 ÷ (0.052 × 10,000) = 10 + 0.96 = 10.96 ppg, round to 11.0 ppg.

ICP example: SIDPP 500 psi + SCR 400 psi = 900 psi; FCP = (11.0 ÷ 10.0) × 400 = 440 psi.

Strokes to bit example: string volume 120 bbl ÷ 0.1 bbl/stroke = 1200 strokes; use to time the kill mud arrival at the bit.

Well control barriers: primary (mud), secondary (BOP), tertiary (bullheading/relief well); two independent barriers must be verified before operations.

BOP stack testing: function test weekly, pressure test before drilling out shoe and at specified intervals; test to rated pressure with low-pressure test first.

Annular preventer: closes on any shape, used for stripping and rotating; pressure rating lower than ram preventers.

Ram preventers: pipe rams close on specific pipe size; blind rams close on open hole; shear rams cut pipe and seal.

Choke manifold: routes flow through adjustable or fixed chokes; must be rated for maximum anticipated surface pressure and tested.

Kill line: connects pump to wellbore below BOP; used to pump kill mud; must be clear and pressure-tested.

Inside BOP: installed in the drill string to close it; used when the string is open and cannot be closed with rams.

Well control drills: pit drills, BOP drills, and kick drills are required at specified intervals; crew must know alarm signals and procedures.

Kick circulation: hold bottom-hole pressure constant by adjusting choke; as kill mud fills the string, casing pressure follows the schedule; when kill mud reaches the bit, ICP transitions to FCP.

Pressure schedule: drill pipe pressure decreases linearly from ICP to FCP as kill mud fills the string; casing pressure is adjusted to maintain bottom-hole pressure.

Choke operator must monitor both drill pipe and casing pressure; drill pipe pressure is primary when the string is open; casing pressure is primary when the string is plugged.

Kill mud displacement: after kill mud reaches the bit, hold FCP until kill mud returns to surface; then the well is static with kill mud.

Flow check after kill: stop pumps, observe flow; if no flow, open BOP and resume operations with kill mud weight.

Kick report: record SIDPP, SICP, pit gain, kill method, kill mud weight, and final pressures; required for IWCF documentation.

Well control certification: IWCF Level 4 covers supervisory well control; assessment includes written exam and practical scenarios.

Continuous improvement: review kick reports and drills to identify gaps and improve procedures.

Hydrostatic pressure in the annulus = 0.052 × mud weight × TVD; bottom-hole pressure = hydrostatic + casing pressure (pumps off).

During circulation, bottom-hole pressure = hydrostatic + annular friction + casing pressure; annular friction is estimated from SCR.

SIDPP reflects pore pressure at the bit when the string is open and unplugged; SICP reflects pore pressure plus annular friction and any trapped pressure.

Kick volume = pit gain; use it to estimate influx size and to plan the kill; large gains require immediate shut-in.

Kill mud weight must be circulated to the bit before FCP is applied; the pressure schedule transitions from ICP to FCP as kill mud fills the string.

If the drill string is plugged, control is by casing pressure and the volumetric method; SIDPP cannot be read, so use SICP and known mud weight.

BOP test pressure: low-pressure test (typically 250-300 psi) then high-pressure test to rated working pressure; record and document results.

Well control certification (IWCF Level 4) requires demonstrated competence in shut-in, kill sheet preparation, and kill circulation for surface and subsea BOP stacks.

Subsea well control: choke line friction and riser margin must be included; MAASP is referenced to the casing shoe and adjusted for water depth and riser.

Riser margin is added to mud weight when drilling from a floating rig to compensate for loss of riser hydrostatic if the riser is disconnected.

Kill mud weight for subsea wells uses the same SIDPP ÷ (0.052 × TVD) formula, but TVD is measured from the rotary table or from the wellhead as specified in the kill sheet.

Shut-in on a floating rig: close annular or pipe rams, then read SIDPP and SICP after stabilization; account for choke line friction in ICP.

BOP stack for subsea: annular, pipe rams, blind/shear rams, and a lower marine riser package (LMRP); testing includes function tests and pressure tests.

Kick tolerance is reduced in deepwater because fracture gradient at the shoe is lower relative to pore pressure; small influxes can fracture the formation.

Well control drills and weekly BOP function tests are required; crew must know the emergency disconnect sequence and its effect on wellbore pressure.

Documentation: kill sheet, pressure test records, and kick reports are retained; IWCF assessment includes written and practical well control scenarios.

Primary well control relies on mud weight; secondary well control relies on BOP and choke manifold; tertiary (bullheading) is a last resort to pump the influx back into the formation.

Bullheading: pump fluid into the well to force the influx back into the formation; used when circulation is impossible; requires knowledge of formation fracture pressure.

Relief well and dynamic kill are advanced options for blowout control; they require coordination and are outside routine well control.

Kick detection while tripping: fill the hole with mud of the correct volume for each stand pulled; a short fill indicates a kick or lost circulation.

Flow check procedure: stop pumps, wait for flow to cease (typically 5-15 minutes), observe flow line; continued flow indicates a kick and requires shut-in.

Shut-in pressures should be recorded within the shortest practical time; delay allows gas migration and increases surface pressure.

Kill sheet verification: check SIDPP, SICP, SCR, ICP, FCP, strokes to bit, and mud weight calculations before starting the kill.

After the kill, circulate one full bottoms-up to verify no influx remains, then flow check and resume operations with the new mud weight.

Well control equipment: BOP stack, choke manifold, kill line, choke line, accumulator, and pressure gauges; each must be rated for the maximum anticipated surface pressure.

Accumulator capacity must be sufficient to close all BOP functions and have reserve; precharge pressure and usable volume are specified by API standards.

Choke types: fixed choke (orifice) and adjustable choke; adjustable chokes allow fine control of casing pressure during a kill.

Pressure gauges: drill pipe pressure gauge, casing pressure gauge, and pump pressure gauge; calibrate and verify before use.

Kick alarm and shutdown: automatic systems detect flow and pit gain; crew response follows the well control procedure and muster alarm.

Well control training standards (IWCF) cover principles, procedures, and equipment for surface and subsea operations at Levels 1-4; Level 4 is the supervisor/wellsite leader level.

Assessment includes a written examination and practical scenarios; candidates must demonstrate shut-in, kill sheet, and kill circulation competence.

Record-keeping: daily drilling reports, BOP test records, and kick reports are part of well control documentation and audit requirements.

Pressure units: 1 bar = 14.5038 psi; 1 psi = 0.06895 bar; 1 MPa = 145.038 psi; convert consistently in kill sheet calculations.

Mud weight units: ppg, kg/m³, and SG; 1 SG = 8.345 ppg = 1000 kg/m³; use the same unit system throughout.

TVD vs. MD: TVD is vertical depth used for pressure; MD is along-hole depth used for volumes and strokes; never mix them in pressure formulas.

Annular volume (bbl) = annular capacity (bbl/ft) × length (ft); annular capacity depends on hole and pipe diameters and is taken from tables or calculated.

Pump output per stroke is measured by pumping into a calibrated tank; strokes to bit = string volume ÷ output per stroke.

Kill mud weight must be circulated to the bit before FCP is applied; the pressure schedule transitions from ICP to FCP as kill mud fills the string.

Casing pressure during kill is adjusted to hold bottom-hole pressure constant; drill pipe pressure is held on the schedule when the string is open and unplugged.

If the choke plugs, switch to the standby choke, restore pressure, and continue; never open the choke fully to clear it while the well is flowing.