Monitoring Systems

Monitoring systems measure, display and record what the rig and the well are doing. The group covers hookload and torque instrumentation, standpipe and choke pressure and return flow sensors, pit volume and trip tank systems, chart and electronic drilling recorders, and the alarm and emergency shutdown systems that act on those signals. Each used sensor needs calibrating before service, whatever its last certificate says.

Scope of the group

Sub-Category	Measures or does	Main use on the rig
Drilling instrumentation	Hookload, weight on bit, torque, RPM, block position	Steering the drilling process
Pressure and flow monitoring	Standpipe, casing and choke pressure, flow out	Hydraulics, washouts, kick detection
Tank and volume monitoring	Pit levels, total active volume, trip tank volume	Gains, losses and hole fill on trips
Parameter recorders	Time-stamped record of the above	Well record, incident review, remote monitoring
Alarm and shutdown systems	Alarms and automatic trips	Emergency shutdown, fire and gas, process shutdown

How the sub-Categories differ

The first three measure. Recorders keep the evidence, and alarm and shutdown systems act on it. That split also decides how strict the paperwork is. A pit level sensor feeding a display needs calibration and an Ex certificate. The same sensor feeding a shutdown function inherits the safety integrity requirements of that function, including proof testing and version control.

Pit volume and return flow are the primary surface signs of a kick, so tank and flow sensors carry well control weight beyond their price. Weight and torque readings protect the drill string and the hoisting system. Treat sensors in all three measurement groups as well control or structural equipment, not consumables.

Standards across the group

IEC 60079 governs instruments in classified areas. The drill floor, shaker house and pit rooms are usually Zone 1 or Zone 2, so check the zone, gas group and temperature class on each marking.
Intrinsically safe loops need a matching barrier or isolator, and IEC 60079-14 requires documentation that proves each combination is safe.
IEC 61511 governs instrumented functions that act as safety functions, including the sensors in them.
NORSOK D-001 sets drilling facility requirements, including drilling instrumentation, on the Norwegian shelf, and some operators specify it elsewhere.
On classed units, DNV-OS-D202 and the corresponding ABS rules cover alarm, monitoring and safety systems.
Calibration should be traceable to national standards, ideally through a laboratory accredited to ISO/IEC 17025.

Integration questions across the group

Signal type and range against the display or data system, such as 4 to 20 mA, HART, Modbus, a proprietary digital bus or a hydraulic line.
Who owns the data system. Some electronic monitoring is supplied as a service, with hardware that belongs to the provider.
Supply voltage, cable entries and the barrier type for intrinsically safe devices.
Motion. On floating rigs, heave and roll move pit levels and hookload, so the system needs filtering or compensation.

Records that make used instruments credible

A calibration certificate per sensor, with the reference used, the points tested and the as-found and as-left readings.
Ex certificates, and for intrinsically safe devices the entity parameters needed for the loop calculation.
For anything in a safety function, the reliability data or proven-in-use evidence, and the proof test history.
Software versions and licences for totalizers, displays and recorders.
Removal records showing whether the unit came out working or as a fault.

As-found readings matter most. A sensor that was far out of tolerance when removed may have been overloaded, and that can reveal a hidden fault even after a clean recalibration.

Sourcing used monitoring equipment

Instruments drift, and transport knocks shift zero and span. Ask for the last calibration certificate as a record of condition, then plan to recalibrate on your rig. Unused surplus sensors avoid diaphragm and seal wear, but elastomers and fill fluids still age in storage, so check manufacture dates. Matched sets from one supplier save integration work on a reactivation. Naventr passes on the certificates the Seller holds so you can review them before asking for an inspection.

FAQ

Frequently asked questions

Do used drilling sensors need recalibration?

Yes, every used sensor needs calibration against a traceable reference before it goes into service. Drift, transport shocks and aged seals all shift readings, and well control and hoisting decisions depend on them. Keep the Seller's last certificate as a record of condition only.

What is the difference between a drilling recorder and a pit volume totalizer?

A drilling recorder logs parameters against time, while a pit volume totalizer measures and alarms on mud volume. The totalizer adds the active pit levels into one volume and alarms on gains or losses. A recorder may store that volume as one of its channels.

Can I mix sensors from different instrumentation suppliers?

Often you can, if signal type, range, connector and Ex protection match. Many sensors give a 4 to 20 mA output that any display can scale. Hydraulic weight systems and proprietary digital sensors are less interchangeable, so check with the system supplier.

What hazardous-area certification do rig instruments need?

Instruments in classified areas need ATEX or IECEx certification for their zone, gas group and temperature class. Intrinsically safe devices also need a matching barrier and loop documentation under IEC 60079-14. Compare every marking with the rig's hazardous area drawing.

Does a sensor in a shutdown function need anything extra?

Yes, it inherits the requirements of the safety function it serves. Under IEC 61511 that means a device with suitable reliability data or proven-in-use history, defined proof testing, and change control over the replacement model and version.

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