IWCF WIPC Level 2 cheat sheet

Primary well control during completion: kill-weight fluid column plus a closed BOP stack; the completion string itself is not a barrier until tested and verified.

Two-barrier policy: at least two independent, tested barriers between the reservoir and atmosphere at all times; a single barrier is permitted only for short, risk-assessed operations.

Hydrostatic pressure (psi) = 0.052 x fluid density (ppg) x true vertical depth (ft); use TVD, never measured depth, for pressure calculations.

Kill-weight mud (ppg) = current mud weight + (SIDPP psi / (0.052 x TVD ft)); SIDPP read from the drill pipe or completion string with the well shut in.

Bullheading, lubricate-and-bleed, and circulation are the three conventional well-control responses; select based on whether formation fluid can be safely displaced and whether the string is plugged.

Before perforating, confirm the well is overbalanced or the completion is isolated; underbalanced perforating requires a tested downhole barrier and a documented risk assessment.

Flow testing or well cleanup must be through a tested flow line and choke manifold rated above the maximum anticipated surface pressure.

Handover between crews requires a documented barrier status, well schematic, and current well parameters; verbal handover alone is not acceptable.

Tubing hanger: lands and seals the completion string in the wellhead; primary load path for string weight and secondary barrier for annulus pressure.

Production packer: isolates the tubing-casing annulus; set by mechanical, hydraulic, or wireline means; verify setting with pressure test before displacing the well.

Subsurface safety valve (SSSV): fail-safe closed, typically flapper type; held open by hydraulic control line pressure; must be tested at prescribed intervals.

Gas lift valves: unloading and operating valves; check valve prevents reverse flow; spacing based on unloading gradient and injection gas pressure.

Tubing movement: thermal expansion and ballooning change length; packer and seal assembly must accommodate movement without unseating or overstressing.

Elastomer seals: rated for temperature, pressure, and produced fluids; swelling in CO2 or H2S service can lock seal assemblies; confirm material compatibility.

Completion accessories: flow couplings, blast joints, and landing nipples are placed at predicted erosion or intervention points; no-go nipples limit plug passage.

Coiled tubing is a continuous string; fatigue life is tracked in cycles and remaining life is a hard limit, not a guideline.

Reel and gooseneck induce bending cycles; each trip over the gooseneck adds fatigue; record every run and update the fatigue model.

CT string is not a primary barrier; well control relies on BOP stack, stripper, and kill fluid; verify BOP function test before starting.

Stripper element seals around the moving CT; monitor for leaks and replace when worn; a leaking stripper is a well-control hazard.

Maximum pick-up and slack-off loads change with depth and friction; use a tubing force model and do not exceed the string's yield or connector rating.

Circulation through CT has high friction pressure; pump pressure limits are set by the CT working pressure and the bottomhole assembly rating.

Depth control: CT depth is measured at surface; account for stretch, thermal expansion, and helical buckling when correlating to wireline or casing depths.

Slickline uses a single solid wire for mechanical work; braided line carries electrical conductors for powered tools.

Wireline is not a barrier; well control depends on the stuffing box, grease injection, and BOP stack; pressure control equipment must be rated for maximum anticipated surface pressure.

Toolstring weight and wire strength determine safe pulling; overpull can part the wire; use a weak point rated below wire strength.

Depth correlation: wire stretch and toolstring length must be corrected; a depth discrepancy can place a plug or perforator in the wrong location.

Grease injection pressure must exceed well pressure to maintain a seal; monitor grease flow and return; loss of grease is a warning sign.

Explosive actuated tools: radio silence and a documented arming procedure are mandatory; detonators are kept separate until at the wellsite.

Fishing: record the toolstring configuration and depth; use a wirefinder or impression block before running a fishing tool.

Snubbing moves pipe into or out of a live well when well pressure would push the pipe out; pipe-heavy and snub forces are calculated from well pressure and pipe weight.

Snub force (lb) = well pressure (psi) x pipe cross-sectional area (in2) minus pipe weight in air; positive value means snubbing, negative means pipe-heavy.

BOP stack for snubbing includes annular, pipe rams, blind rams, and a stripping preventer; function test before starting.

Stripping or snubbing through the annular or stripping preventer wears the element; monitor and replace as needed.

Buckling: snubbing pipe in compression can buckle; use centralizers and keep compressive load below the critical buckling load.

Kill fluid and well pressure must be monitored continuously; a sudden pressure change indicates a barrier or formation issue.

Emergency shutdown: close the blind rams and stop pumping; know the sequence and practice it.

Subsea BOP stack: annular, variable rams, pipe rams, and blind/shear rams; shear rams must be capable of cutting the pipe in the hole.

Two independent barriers: subsea tree and BOP stack provide barriers; test and verify before proceeding.

Hydrate formation: at low temperature and high pressure, gas and water form hydrates; prevent with methanol or glycol injection and by controlling pressure and temperature.

Riser margin: the riser contains drilling fluid; loss of riser integrity reduces hydrostatic pressure and can cause a kick; monitor riser pressure and volume.

Emergency disconnect: the lower marine riser package can disconnect from the BOP; sequence must be known and tested.

Subsea tree valves: fail-safe closed; actuated by hydraulic pressure; verify function and response time.

Depth and pressure ratings: all subsea equipment must be rated for the water depth and maximum anticipated pressure at the mudline.