Wellhead Monitoring: Pressure, Temperature, Flow

Why Wellhead Monitoring Matters

The wellhead is the primary point of measurement and control for every producing oil or gas well. Casing pressure, tubing pressure, flowline pressure, temperature, and flow rate are the vital signs that indicate well health, reservoir performance, and equipment condition. Without continuous monitoring, problems like tubing leaks, casing failures, scale buildup, hydrate formation, and pump malfunctions go undetected until they cause significant production loss or safety incidents.

In the traditional operating model, a field pumper visits each well once or twice daily, reads mechanical pressure gauges, checks tank levels, and records observations on a gauge sheet. This model has several limitations: problems that develop between visits go undetected for 12-24 hours, gauge readings are subject to human error, and the cost of driving routes in large fields consumes significant labor and vehicle expenses. Continuous electronic monitoring addresses all of these limitations.

Pressure Monitoring

Casing Pressure

Casing pressure is one of the most informative wellhead measurements. It indicates reservoir pressure in gas wells and gas-lifted oil wells, provides early warning of casing integrity failures (sustained casing pressure), reveals the performance of downhole artificial lift equipment, and supports regulatory compliance with casing pressure reporting requirements. Electronic pressure transmitters installed on the casing valve provide continuous casing pressure readings at 1-minute intervals or faster, transmitted to SCADA for trending, alarming, and analysis.

Tubing Pressure

Tubing pressure, measured at the wellhead on the production side, reflects the flowing pressure of the well. Changes in tubing pressure indicate changes in production rate, liquid loading events in gas wells, artificial lift performance changes, and wellbore restrictions from scale, paraffin, or sand. Trending tubing pressure against production rate yields the inflow performance relationship that is fundamental to production optimization.

Flowline Pressure

Flowline pressure measured downstream of the wellhead choke or at the separator inlet reveals the backpressure imposed on the well by the surface gathering system. Excessive flowline pressure reduces well production by increasing backpressure. SCADA monitoring of flowline pressure across a gathering system enables operators to identify restrictions, optimize separator operating pressures, and size flowlines appropriately for current production rates.

Temperature Monitoring

Wellhead temperature measurement provides diagnostic information about downhole conditions. Key temperature monitoring applications include:

• Hydrate prediction: In gas wells and wet gas flowlines, temperature below the hydrate formation curve at a given pressure indicates hydrate risk. Continuous temperature monitoring triggers automated methanol injection before hydrate blockages form.
• Paraffin management: Crude oil temperature at the wellhead and along flowlines determines the onset of paraffin deposition. When temperatures approach the wax appearance temperature (WAT), operators can increase chemical treatment or apply heat.
• Well performance: Changes in flowing wellhead temperature over time indicate changes in producing interval, water cut, or gas-liquid ratio that may require operational response.
• Equipment protection: Temperature monitoring on artificial lift equipment (ESP motor, rod pump stuffing box) provides early warning of overheating conditions.

Flow Measurement

Continuous flow measurement at the wellhead enables real-time production monitoring, automated well testing, and immediate detection of production changes. Flow measurement technologies suitable for wellhead installation include:

• Coriolis meters: Provide direct mass flow measurement of oil with 0.1% accuracy. Installed between the wellhead and the production header for continuous per-well metering.
• Orifice meters: Standard technology for gas well measurement per AGA-3. Differential pressure, static pressure, and temperature inputs to an RTU-based flow computer calculate gas volume in real-time.
• Vortex meters: Suitable for gas and steam measurement with no moving parts. Lower accuracy than orifice meters but lower maintenance requirements.
• Multiphase meters: Measure oil, gas, and water simultaneously without separation. Eliminate the need for test separators but at higher cost ($100,000-$300,000 per unit).

SCADA Integration

Electronic transmitters at the wellhead connect to an RTU (Remote Terminal Unit) that aggregates measurements, performs local calculations (flow computer functions, alarm checks), and transmits data to the central SCADA system. Modern RTUs support multiple communication protocols including Modbus, DNP3, and OPC-UA, and can communicate via licensed radio, cellular LTE, or satellite.

Key SCADA configuration for wellhead monitoring includes scan rate settings (typically 10-60 seconds for pressures, 1-second for flow measurement), alarm thresholds for high and low values on each parameter, rate-of-change alarms to detect sudden pressure drops or production changes, and historical trending at 1-minute resolution for engineering analysis.

Alarm Management

Effective alarm management is critical for wellhead monitoring. Too many alarms cause alarm fatigue, while too few miss important events. NFM Consulting follows ISA-18.2 alarm management principles:

• Alarm rationalization: Each alarm must have a defined cause, consequence, and required operator response
• Priority classification: Critical alarms (safety, environmental) escalate immediately; high priority (production impact) within 1 hour; medium priority (equipment degradation) within 8 hours
• Suppression logic: Shelve alarms during known conditions (well shut in for workover, tank truck on location) to reduce nuisance alarms
• Performance metrics: Target less than 6 alarms per operator per hour during normal operations

Value Proposition

Continuous wellhead monitoring delivers measurable value. Operators typically report 4-8 hours faster response to well upsets compared to once-daily pumper rounds, 20-40% reduction in truck rolls for routine gauge readings, 2-5% production increase from faster identification and resolution of production restrictions, compliance with Railroad Commission of Texas monitoring requirements, and improved safety through automated H2S and high-pressure alarms. For a 200-well operation, continuous wellhead monitoring reduces operating costs by $500,000-$1,000,000 annually while improving production and safety outcomes.