Post Shut-In Pressure Stabilization & Data Recording

Record a trend, not a single number

After containment, monitor the well for unplanned flow, pressure and leakage. Record SIDPP, SICP, influx estimate, fluid density, depth, operation and the time of each reading. The valve and gauge routes must be known. A pressure shown on a console may be trapped above an internal valve or isolated from the annulus. A stabilised display is useful only if it represents the intended communicating pressure.

Pressure initially changes as the well and formation approach balance after shut-in. Permeability, fluid compressibility, influx, temperature, equipment response and instrument location all affect the trend. There is no universal two-minute, five-minute or half-hour stabilisation rule. Report continuing increases promptly, particularly as an applicable limit is approached. Waiting for a flat line must not replace active pressure management.

Interpret SIDPP under valid assumptions

With the bit at bottom, known clean mud inside the string and reliable pressure communication, formation-pressure estimate equals string hydrostatic pressure plus valid stabilised SIDPP. At 10,000 ft TVD with 10.0 ppg mud, string head is 5,200 psi. A valid SIDPP of 500 psi gives 5,700 psi estimated formation pressure. The same number is not reliable if a float isolates the gauge, the bit is off bottom or influx has entered the string.

A float can hold an unknown pressure above it, including zero or a nonzero trapped value. The approved method for obtaining the required reference uses controlled pumping and annular-pressure management with the equipment limits considered. Follow that procedure and distinguish any seat-opening or flow-friction contribution from the static value. Do not substitute SICP directly for SIDPP without accounting for the different fluid column.

Explain SIDPP and SICP differences

A lighter influx in a vertical annulus commonly gives SICP greater than SIDPP because the annular hydrostatic head is lower. In a horizontal interval, a substantial influx can replace little vertical head, so the difference may be small. Other explanations include multiple fluid densities, cuttings loading, bit position, influx in the string, blocked annulus, float behaviour and gauge error. The difference is not an exclusive fluid-type detector.

For a uniform vertical training model, if clean string head is 5,200 psi and annular head is 4,900 psi, both at the same 5,700 psi bottom pressure, SIDPP is 500 psi and SICP is 800 psi. The 300 psi difference is the difference in hydrostatic heads. Changing gauge location or adding an intervening line changes the surface readings that represent the same downhole pressure.

Trapped pressure is a diagnosis, not a licence to bleed

Pump pressure may be trapped during closure, and isolated volumes can retain pressure. Thermal changes or gas migration can also produce a rise, but their pressure-maintenance implications differ from simply releasing an artificial excess. An unusually high reading alone does not prove that pressure can be discarded. Uncontrolled annular bleeding can reduce bottomhole support and allow more influx.

Any diagnostic bleed is conducted by the approved procedure under the supervisor's direction, using a measured small volume, a valid reference and specified stopping criteria. There is no universal quarter- or half-barrel increment. Observe the pressure recovery and volume response, but a pressure drop that holds briefly does not by itself prove a benign cause. In low-permeability conditions the return toward formation balance can be slow. Preserve the required support and barriers throughout the test.

Migration control and unavailable references

If migration is confirmed and reliable SIDPP indicates bottom pressure, an approved measured annular bleed can restore the original valid reference. Track exactly how much fluid is released and where it goes. Do not target zero pressure when the mud column alone is underbalanced. If circulation or reliable bottom communication is unavailable, the supervisor may use a volumetric method with calculated pressure-volume steps.

External leaks and unexpected flow after closure require the designated alternative barrier. Gauge failure requires independent comparison and, if reliable control is lost, controlled shutdown or other safe action under the plan. The operator should distinguish a well-pressure problem from a sensing-path problem while continuing to monitor the complete envelope.

Make the handover reviewable

Give the supervisor the timeline, valid and uncertain readings, gain estimate, fluid density, bit position, float status, closed elements and any bleed or pump volume. Preserve the original values used to complete the kill sheet. If the values change, record why rather than overwriting the history. A precise statement of uncertainty is useful: “The drillpipe gauge is isolated by the float; casing pressure is rising; no bleed has been made.” That allows a controlled method to be selected without treating an invalid pressure as fact.

Pressure-reference checklist