Gauge Failure and BOP Leak First Actions

Compare a prediction with more than one observation

A kill sheet gives expected pressure trends at a known pump rate and fluid position. It does not make every deviation a downhole fault. A gauge may lose sensitivity, stick, drift, have a blocked sensing line or be connected to an isolated volume. The driller compares the critical gauges, returns, pits and pump rate before attributing the change. The comparison should happen within the approved first-response plan; uncertainty must not lead to uncontrolled pumping or choke movement.

A frozen drillpipe gauge can be particularly misleading because the choke operator may keep changing the choke while watching a reading that cannot respond. A casing gauge can also be isolated from the well by a valve or blockage. Know the pressure-tap locations, not just the labels on the console. In a subsea return system, a surface choke gauge and a gauge near the BOP can legitimately differ because of hydrostatic head and friction between them.

Scale and calibration affect usefulness

Accuracy may be stated as a percentage of full scale. A training gauge specified at ±1% of a 10,000 psi full scale has a possible ±100 psi error under that specification. A 500 psi reading therefore carries a large relative uncertainty. A suitable lower-range gauge can improve resolution if it is rated, protected and connected appropriately. Never connect an under-rated instrument to a higher-pressure path merely to obtain a more readable scale.

For example, a high-range gauge reads 500 psi while a calibrated appropriately rated low-range gauge reads 430 psi. The difference may be within the first gauge's stated uncertainty. It is not automatically evidence that the well pressure is oscillating by 70 psi. Record the calibration and locations and use the designated instrument. If gauges disagree beyond their allowed uncertainty, treat the reading as unresolved and follow the approved response.

First actions for a malfunctioning gauge

Recognise a lack of response to a known, controlled change, compare with an independent gauge and verify the selected sensing route. Notify the supervisor. If reliable pressure control is lost, make a controlled shutdown while maintaining bottomhole pressure using the available approved indications and procedure. Keep cumulative strokes and volumes. Do not continue a kill by estimating a pressure from the last valid reading while the fluid profile changes.

A sensing line may contain trapped pressure even when the main system is depressurised. Isolate and verify its state before maintenance. Do not loosen a live gauge connection or use a blocked line as evidence that the well has zero pressure. An independent reading must come from a known communicating pressure path; two displays connected to the same failed sensor are not independent confirmation.

Find equipment leaks by the path they create

Leaks can appear at a BOP element, bonnet, connector, side valve, hose or manifold. They can also be internal, with pressure appearing in a volume that should remain isolated. Check the non-pressured side during tests and the relevant monitored routes in service. A hydraulic control leak can prevent successful closure even when there is no external well-fluid leak. Distinguish the well-pressure envelope from the hydraulic power system.

If unplanned flow or pressure continues after shut-in, verify the intended function and activate the preplanned alternative barrier. Maintain the internal string barrier and appropriate choke isolation. Report the leak location and trends. Keep personnel away from pressurised jets and do not attempt bolt tightening, gasket replacement or hose work while the affected system remains pressurised. The immediate task is to secure the well; diagnosis and repair follow a controlled isolation plan.

Control-system indications are supporting evidence

A panel light can indicate a command or valve position rather than actual ram travel. Hydraulic pressure and fluid-volume response can indicate movement, but they do not alone prove a pressure seal. Combine function feedback with monitored well flow, pressure behaviour and the appropriate verification. If a function does not operate, possible causes include a leaking power hose, failed manipulator valve, regulator fault or low reservoir level. An approved alternative panel or control route may be available.

For subsea equipment, distinguish signal-line failure from power-fluid failure. A pod or shuttle malfunction can affect one route while another remains usable. Changing pods or using an ROV intervention requires the system's procedure and responsible coordination. Do not assume that every emergency system performs the same sequence or can seal the item presently across the stack.

Preserve information for the supervisor

Record the operation, predicted and actual pressures, pump rate, gauge ranges and taps, pit/return trend, valve configuration and observed leakage. If a backup barrier is used, record which element and whether its seal was verified. A useful message is specific: “The drillpipe display is unchanged despite the controlled rate change; the independent standpipe gauge responds; returns are stable; we are following the shutdown instruction.” Such evidence distinguishes an instrument fault from a possible well event and supports the next safe action.

Different kinds of evidence