How Often Should Wellhead Equipment Be Inspected and Maintained?

API 6A and industry best practice recommend a tiered inspection approach:

Daily/Monthly (Operator Level) :
- Visual inspection for leaks, corrosion, and physical damage during every wellsite visit
- Check annulus pressure gauges — rising pressure indicates a possible seal leak
- Verify valve positions (open/closed) match operational status

Quarterly (Routine Inspection) :
- Functional test all gate valves (open/close cycles)
- Check flange bolt torque on accessible connections
- Inspect side outlet valves and fittings for external corrosion
- Verify that pressure gauges are calibrated and functioning

Annual (Comprehensive Inspection) :
- Pressure test critical sealing components (casing hanger seals, tubing hanger seals)
- Non-destructive examination (NDE) of critical load-bearing areas using ultrasonic testing (UT) or magnetic particle inspection (MT)
- Replace valve packing and stem seals showing signs of wear
- Full documentation review — update wellhead integrity records

Post-Event (Triggered Inspection) :
- After any well control incident, pressure excursion beyond rated limits, or seismic event
- After workover or recompletion operations that disturb the wellhead

Based on JLD Energy's field experience, these components fail most frequently:

1. Valve stem packing (most common) : Packing dries out, wears, or extrudes under pressure cycling. Symptoms: visible leak around valve stem, gas smell near valve.

2. Flange gaskets: Ring gaskets (RTJ) can corrode or lose preload. Symptoms: pressure drop, gas detection at flange face.

3. Casing hanger seals: Elastomeric seals degrade over time, especially in high-temperature wells or wells with H₂S. Symptoms: sustained casing pressure (SCP) in the annulus.

4. Side outlet valves: Often neglected because they're not part of the main flow path. Corrosion and seizing are common. Test them quarterly.

5. Bolting: External corrosion on flange bolts is easy to spot but often ignored. Loose or corroded bolts compromise the entire wellhead pressure integrity.

Pressure testing verifies seal integrity after installation, maintenance, or a well control event:

Shell test: Pressurize the entire wellhead cavity (with valves closed) to the rated working pressure. Hold for a minimum of 15 minutes. No visible leakage and less than 5% pressure drop per API 6A.

Seat test: Test each valve seat individually by pressurizing one side while the valve is closed, with the opposite side open to atmosphere. Verify zero leakage across the seat.

Annulus test: Pressure up the casing annulus through the side outlet to verify casing hanger seal integrity. Monitor for 30 minutes.

Important: Never exceed the lowest-rated component. If your casing head is 5,000 PSI but a side outlet valve is 3,000 PSI, the test pressure must not exceed 3,000 PSI.

JLD Energy provides detailed pressure test procedures with every wellhead equipment delivery.

For API compliance and regulatory audits, maintain these records:

- Wellhead equipment register: Serial numbers, pressure ratings, material classes, installation dates for every component
- Inspection logs: Date, inspector name, findings, and corrective actions for each inspection
- Pressure test records: Test date, test pressure, duration, and pass/fail result
- Maintenance work orders: What was replaced or repaired, why, and by whom
- NDE reports: For annual or post-event NDE inspections
- Photographic evidence: Before and after photos of seal replacements, corrosion findings, and completed repairs

A digital wellhead integrity management system makes this manageable for multi-well operations. JLD Energy can provide template inspection checklists and documentation formats.

This decision tree helps determine the right course of action:

Repair (cost-effective if these conditions are met) :
- Component is less than 10 years old
- Damage is limited to replaceable parts (packing, gasket, seal)
- Body and pressure-containing parts pass NDE inspection
- Repair can be completed without removing the wellhead from service

Replace (necessary when) :
- Visible cracks, pitting deeper than 1/8 inch, or significant wall loss (more than 12.5% of original thickness per API 6A)
- Component has exceeded its design life (typically 15–25 years depending on service)
- Material degradation from H₂S or chloride stress corrosion cracking is detected
- Repair cost exceeds 60% of new equipment cost

When in doubt, JLD Energy's engineers can perform an on-site assessment and provide a replacement-or-repair recommendation within 48 hours.