What does a wellhead inspection cover?

A wellhead inspection covers the full surface assembly from casing head to Christmas tree. This includes visual condition of all flanges, ring gaskets, stud bolts and nuts, operation of every valve (fully open to fully closed), pressure gauge readings and calibration status, choke condition, BOP connection points (if applicable), external corrosion assessment, cathodic protection status, wellhead cellar condition and function testing of safety systems such as surface safety valves (SSV) and emergency shutdown (ESD) valves. The inspection is aligned with API 6A requirements for wellhead and tree equipment.

How often should a wellhead be inspected?

A basic visual check (leak detection, pressure readings, valve position) should be performed during every routine well visit. A comprehensive inspection covering valve operation, flange bolting, corrosion assessment and safety system function tests should be performed at least every six months for production wells and before and after drilling or workover campaigns. Safety device function tests (SSV, ESD) are typically quarterly. The exact interval should be justified by a risk-based assessment as part of the operator integrity management plan and comply with state petroleum regulations or NOPSEMA requirements.

What is API 6A and why does it apply to wellhead inspections?

API Specification 6A is the American Petroleum Institute standard that defines design, material, manufacturing, testing and marking requirements for wellhead and Christmas tree equipment. It classifies equipment by pressure rating (2,000 to 20,000 psi), material class (AA through HH) and temperature rating (K through Y). While API 6A is an American standard, it is widely adopted by Australian operators and is referenced in most operator management systems and integrity management plans. Inspecting wellheads against API 6A criteria ensures that components remain within their rated service envelope and that any deterioration is detected before it compromises pressure containment.

What Australian regulations apply to wellhead equipment?

For offshore petroleum operations in Australian Commonwealth waters, NOPSEMA administers the safety case regime under the Offshore Petroleum and Greenhouse Gas Storage Act 2006. Operators must demonstrate that risks from well equipment are reduced to as low as reasonably practicable (ALARP). For onshore wells, state and territory petroleum legislation applies, such as the Petroleum and Gas (Production and Safety) Act 2004 (Queensland), the Petroleum Act 1998 (Victoria) or the Petroleum and Geothermal Energy Act 2000 (South Australia). All regimes require a written scheme of examination for pressure-containing equipment, with inspection intervals justified by risk assessment.

What should I do if I find a wellhead valve that will not fully close?

A valve that does not achieve full closure is a potential well control risk and must be reported immediately. Record the valve location (e.g. master valve, wing valve, swab valve), the symptom (stiff, partial travel, leaking through) and any relevant pressure readings. Notify the well operations supervisor and the integrity management team. Depending on the valve function and well status, the well may need to be shut in or have redundant barriers confirmed while a repair plan is developed. Do not attempt to force a stuck valve, as this may damage the seat or stem.

How do I check cathodic protection on a wellhead?

Cathodic protection (CP) on a wellhead is typically provided by sacrificial anodes (zinc or magnesium) or an impressed current system. For a basic inspection, confirm that sacrificial anodes are present and not fully consumed, check that CP test point cables are intact and not corroded, and if a portable reference electrode and voltmeter are available, measure the pipe-to-soil potential at the nearest test point. An adequate reading is typically more negative than minus 850 mV (Cu/CuSO4 reference). Record the reading and date. If the CP system is an impressed current type, confirm the rectifier is energised and the output current and voltage are within the target range.

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Free wellhead inspection checklist aligned to API 6A (PDF-ready). Covers valve integrity, flange bolting, pressure ratings, corrosion and BOP checks.

Jarrod Milford

Commercial Director

Updated 3 May 2026

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What is a wellhead inspection checklist?

A wellhead inspection checklist is a structured form used to verify the mechanical integrity, pressure containment and operational readiness of wellhead equipment on oil and gas production or drilling sites. The wellhead is the surface termination of a well bore and includes the casing head, tubing head, Christmas tree valves, flanges, seals and associated fittings. Because wellheads operate under high pressure and often in corrosive environments, routine inspection is critical to preventing uncontrolled releases, leaks and equipment failures. This checklist is aligned with API Specification 6A (Wellhead and Tree Equipment), which defines the design, material, testing and marking requirements for wellhead components. It covers visual inspection of all flanges, ring gaskets, stud bolts and nuts, valve operation and seat testing, pressure gauge verification, corrosion monitoring, cathodic protection status, BOP (blowout preventer) connection points, wellhead cellar condition and safety system function tests. In Australia, wellhead equipment also falls under state petroleum regulations and the Safety Case regime administered by NOPSEMA (National Offshore Petroleum Safety and Environmental Management Authority) for offshore operations or state regulators for onshore wells. A standardised inspection checklist ensures that every wellhead receives consistent scrutiny, that findings are recorded for regulatory reporting and that defects are tracked through to corrective action, supporting both API 6A compliance and local safety case requirements.

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Benefits of using this wellhead inspection checklist

Pressure integrity assurance: systematic valve, flange and seal checks detect leaks and degradation before they escalate to uncontrolled releases or well control events.
API 6A alignment: the checklist maps directly to API 6A inspection and maintenance requirements, supporting compliance with industry best practice and operator standards.
Corrosion management: regular visual and measurement-based corrosion checks help maintain wall thickness above minimum allowable values and extend equipment service life.
Regulatory compliance: documented wellhead inspections support safety case obligations under NOPSEMA (offshore) or state petroleum regulations (onshore) and satisfy audit requirements.
Defect tracking: recording defects with severity and corrective actions creates a traceable maintenance history for each wellhead, supporting integrity management systems.
Reduced unplanned downtime: catching valve faults, gasket deterioration or bolting issues early prevents emergency shutdowns and production losses.

Benefits of digitising forms in MapTrack

When you digitise wellhead checklists in MapTrack, you get:

Field users can easily scan a QR code to complete a form on mobile. Unlimited users.
Automatically get alerts when faults are identified.
Link every form digitally as a PDF to the relevant asset, location or person.
Receive a digital PDF copy with every submission to your email.
Ability to share forms digitally.
Build conditional logic (show or hide questions based on answers).
Take pictures or attach photos. Not possible with a paper-based form.
Electronic signatures.
Edit forms later without reprinting.
Restrict permissions (who can view, complete or approve).
Build forms with AI (describe what you need and MapTrack suggests the form).
Trigger work orders automatically when a fault is logged during an inspection.
Track service intervals by hours, kilometres or calendar date in one place.
Attach supplier invoices and parts receipts to each maintenance record.

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What to include in a wellhead inspection checklist

This wellhead inspection checklist covers 10 key areas:

Well identification: well name or number, field name, pad or platform location, wellhead asset ID, date, inspector name and competency reference.
Casing head and tubing head: visual condition, corrosion, erosion, mechanical damage, casing hanger lockdown screws torqued, casing annulus pressure readings.
Flanges and ring gaskets: flange faces clean and undamaged, ring gasket type and material correct per API 6A, no visible leaks at flange joints, stud bolts and nuts present, correctly torqued and not corroded.
Christmas tree valves: each valve operates fully open and fully closed, handwheels or actuators functional, valve position indicators correct, no external leaks, bonnet bolts secure.
Pressure gauges: tubing pressure, casing pressure and annulus pressure gauges readable, calibration in-date, isolation valves functional.
Choke and flow control: choke bean or adjustable choke condition, no erosion at choke body, flow path aligned to production requirements.
BOP connection points (if applicable): BOP flange condition, stud holes aligned, ring groove undamaged, flange protectors in place when BOP not installed.
Corrosion and cathodic protection: external corrosion rating (none / surface / pitting / severe), cathodic protection system status (sacrificial anodes or impressed current), CP test point readings if accessible.
Wellhead cellar: cellar clean and drained, no standing fluids, cellar walls structurally sound, no hydrocarbon accumulation.
Safety systems: surface safety valve (SSV) function test, emergency shutdown (ESD) valve response, fire loop or fusible plug condition, SCADA communication confirmed.

How to use this wellhead inspection checklist

Review the well file and previous inspection records before arriving at the wellhead.: Check the well schematic, API 6A equipment ratings (pressure class, material class, temperature rating), previous inspection findings and any outstanding corrective actions. Confirm the well is in a safe state for inspection: production may need to be shut in or reduced depending on the scope of checks.
Record well identification details and current pressure readings at the top of the checklist.: Capture the well name, field, pad or platform location, wellhead asset ID, date, inspector name and competency reference number. Read and record tubing pressure, casing pressure and each annulus pressure before commencing physical checks.
Perform a visual walk-around of the entire wellhead assembly from casing head to Christmas tree.: Check for external corrosion, mechanical damage, leaks (hydrocarbon staining, drips, gas bubbles in standing water), missing bolts, loose fittings and damaged valve handwheels. Inspect the wellhead cellar for standing fluids, hydrocarbon accumulation and structural condition.
Inspect flanges, ring gaskets and bolting in detail, then operate each valve through its full cycle.: Verify each flanged connection has the correct ring gasket type and material per API 6A. Check stud bolts for corrosion, correct length and proper nut engagement. Operate each Christmas tree valve from fully open to fully closed and back, confirming smooth operation and correct position indicator alignment. Note any valves that are stiff, leaking or that do not fully close.
Test safety systems, record corrosion measurements and complete the sign-off.: Function-test the surface safety valve and ESD valve per the site safety case procedure. Record external corrosion observations and any ultrasonic thickness readings if taken. Check cathodic protection status. Complete all checklist items, mark pass, fail or not applicable, record defect details and corrective actions, and sign off. Submit the completed checklist to the integrity management system.

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How often should you complete this checklist?

Wellhead inspections should follow a tiered schedule based on risk and regulatory requirements. A basic visual inspection (leak checks, pressure readings, valve position confirmation) should be performed during every routine well visit, which may be daily, weekly or monthly depending on the field operating philosophy. A comprehensive wellhead inspection covering all checklist items, including valve operation, flange bolting checks and corrosion assessment, should be performed at least every six months for production wellheads and before and after every drilling or workover campaign. Safety system function tests (SSV, ESD) are typically required quarterly or as specified in the facility safety case. Australian state petroleum regulations and NOPSEMA guidance generally require operators to maintain a written scheme of examination and inspection for pressure-containing equipment, with intervals justified by a risk-based assessment. Always refer to the operator integrity management plan, API 6A and any applicable state or Commonwealth legislation.

Frequently asked questions

What does a wellhead inspection cover?: A wellhead inspection covers the full surface assembly from casing head to Christmas tree. This includes visual condition of all flanges, ring gaskets, stud bolts and nuts, operation of every valve (fully open to fully closed), pressure gauge readings and calibration status, choke condition, BOP connection points (if applicable), external corrosion assessment, cathodic protection status, wellhead cellar condition and function testing of safety systems such as surface safety valves (SSV) and emergency shutdown (ESD) valves. The inspection is aligned with API 6A requirements for wellhead and tree equipment.
How often should a wellhead be inspected?: A basic visual check (leak detection, pressure readings, valve position) should be performed during every routine well visit. A comprehensive inspection covering valve operation, flange bolting, corrosion assessment and safety system function tests should be performed at least every six months for production wells and before and after drilling or workover campaigns. Safety device function tests (SSV, ESD) are typically quarterly. The exact interval should be justified by a risk-based assessment as part of the operator integrity management plan and comply with state petroleum regulations or NOPSEMA requirements.
What is API 6A and why does it apply to wellhead inspections?: API Specification 6A is the American Petroleum Institute standard that defines design, material, manufacturing, testing and marking requirements for wellhead and Christmas tree equipment. It classifies equipment by pressure rating (2,000 to 20,000 psi), material class (AA through HH) and temperature rating (K through Y). While API 6A is an American standard, it is widely adopted by Australian operators and is referenced in most operator management systems and integrity management plans. Inspecting wellheads against API 6A criteria ensures that components remain within their rated service envelope and that any deterioration is detected before it compromises pressure containment.
What Australian regulations apply to wellhead equipment?: For offshore petroleum operations in Australian Commonwealth waters, NOPSEMA administers the safety case regime under the Offshore Petroleum and Greenhouse Gas Storage Act 2006. Operators must demonstrate that risks from well equipment are reduced to as low as reasonably practicable (ALARP). For onshore wells, state and territory petroleum legislation applies, such as the Petroleum and Gas (Production and Safety) Act 2004 (Queensland), the Petroleum Act 1998 (Victoria) or the Petroleum and Geothermal Energy Act 2000 (South Australia). All regimes require a written scheme of examination for pressure-containing equipment, with inspection intervals justified by risk assessment.
What should I do if I find a wellhead valve that will not fully close?: A valve that does not achieve full closure is a potential well control risk and must be reported immediately. Record the valve location (e.g. master valve, wing valve, swab valve), the symptom (stiff, partial travel, leaking through) and any relevant pressure readings. Notify the well operations supervisor and the integrity management team. Depending on the valve function and well status, the well may need to be shut in or have redundant barriers confirmed while a repair plan is developed. Do not attempt to force a stuck valve, as this may damage the seat or stem.
How do I check cathodic protection on a wellhead?: Cathodic protection (CP) on a wellhead is typically provided by sacrificial anodes (zinc or magnesium) or an impressed current system. For a basic inspection, confirm that sacrificial anodes are present and not fully consumed, check that CP test point cables are intact and not corroded, and if a portable reference electrode and voltmeter are available, measure the pipe-to-soil potential at the nearest test point. An adequate reading is typically more negative than minus 850 mV (Cu/CuSO4 reference). Record the reading and date. If the CP system is an impressed current type, confirm the rectifier is energised and the output current and voltage are within the target range.

Applicable regulatory standards

This template aligns with the following regulations and standards:

API Specification 6A - Wellhead and Tree Equipment (design, material, testing and marking requirements)
API Recommended Practice 14B - Design, Installation, Repair and Operation of Subsurface Safety Valve Systems
NOPSEMA Safety Case Guidelines (offshore petroleum operations in Australian Commonwealth waters)
Relevant state Petroleum Acts and Regulations (e.g. Petroleum and Gas (Production and Safety) Act 2004, QLD; Petroleum Act 1998, VIC)
WHS Regulations 2011, Chapter 5 - Plant and Structures

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