Summary:
- Turnaround shutdowns are the critical window for valve testing, inspection and refurbishment — poor planning leads to costly schedule overruns and post-restart failures.
- Seat leakage testing, hydrostatic shell tests and actuator stroke checks are the core inspection activities, governed by API 598, API 6D and plant-specific procedures.
- A structured valve criticality matrix, pre-TAR condition monitoring data and a clear decision tree (repair, refurbish or replace) are essential tools for efficient turnaround valve management.
Why Turnarounds Are Make-or-Break for Valve Reliability
In continuous process plants — refineries, petrochemical complexes, power stations, offshore platforms — valves spend most of their lives in service. You cannot freely isolate, test or strip a valve while the plant is running. The turnaround (TAR), also called a shutdown, outage or planned maintenance stop, is the single window of opportunity to inspect what you cannot normally reach, test what you cannot normally isolate, and fix what has been slowly degrading under pressure and temperature for months or years.
Get turnaround valve management right and you achieve a reliable restart, reduced in-service leak frequency and a longer run-length before the next shutdown. Get it wrong — poor condition assessment, wrong parts on site, inadequate testing — and you face post-restart valve failures, emergency isolations and the very expensive scenario of opening the plant back up after an unplanned re-shutdown.
This guide covers everything a valve engineer needs to know about planning, executing and closing out valve inspection and testing activities during a plant turnaround shutdown.
Building the Valve TAR Scope: Criticality-Based Selection
Not every valve on a plant can or should be inspected at every turnaround. A large refinery may have 15,000–40,000 valves; a petrochemical unit might have 3,000–8,000. Inspecting all of them every shutdown is neither feasible nor necessary. The foundation of good TAR valve management is a criticality matrix that objectively scores each valve against defined risk factors.
Criticality scoring typically considers: safety consequence of failure (HAZOP/LOPA identified critical functions), environmental consequence (fugitive emissions compliance, SIL-rated ESD valves), operational consequence (production loss, product quality impact), historical failure rate and in-service condition monitoring data (ultrasonic seat leak detection, stem packing emissions monitoring), and time-in-service since last inspection against recommended inspection interval.
High criticality valves — SIL-rated emergency shutdown valves, safety relief valves, isolation valves on hazardous services, control valves on critical loops — form the mandatory inspection scope. These must be inspected every TAR regardless of apparent condition. Medium criticality valves are inspected on a risk-based interval (every second or third TAR). Low criticality valves in non-hazardous services are inspected only on condition — if monitoring data, visual inspection or operational history flags a concern.
A well-maintained valve register in your CMMS (Computerised Maintenance Management System) — SAP PM, IBM Maximo, Oracle EAM — should hold the criticality score, last inspection date, inspection interval, and outstanding findings for every valve. Building your TAR scope from this data, rather than from tribal knowledge and habits, is the difference between systematic asset management and organised guesswork.
Pre-TAR Valve Condition Monitoring
The information you collect before the shutdown directly determines the quality of your TAR scope. Condition monitoring techniques that can be applied to in-service valves include several important methods.
Acoustic leak detection uses sensitive ultrasonic instruments placed on valve bodies to detect the characteristic high-frequency noise of fluid passing through a leaking seat. This is a standard technique for assessing seat condition on in-service isolation valves without taking them out of service. A valve flagged by acoustic monitoring as seat-leaking goes straight onto the mandatory inspection scope.
Partial stroke testing (PST) for ESD valves involves moving the valve a small fraction of its full stroke (typically 10–15%) to verify that the actuator, positioner and valve mechanism are functional, without fully isolating the process. PST data over multiple test cycles can reveal actuator stiffness trends, increasing breakaway torque or friction, which indicate deteriorating packing, seat wear or actuator degradation. Any ESD valve failing PST or showing adverse trends is prioritised for TAR inspection and functional testing.
Fugitive emission monitoring under EN ISO 15848 or EPA Method 21 quantifies stem seal leakage on in-service valves. Valves exceeding permissible emission thresholds must be repacked at the TAR. Tracking emissions data from previous shutdowns allows trending and early identification of packing systems that are degrading faster than expected.
Thermal imaging can identify heat distribution anomalies in steam trap stations, insulated valve bodies where external temperature patterns indicate internal leakage or blockage, and actuator enclosures where heat generation indicates electrical faults or excessive friction.
Core Valve Testing Standards for TAR Inspection
The three testing standards that govern the vast majority of TAR valve testing are API 598, API 6D and ISO 5208 — with plant-specific procedures layered on top for safety-critical applications.
API 598 (Valve Inspection and Testing) is the primary standard for industrial valves across the refining and petrochemical sector. It defines shell (hydrostatic) test pressure (1.5× maximum allowable pressure at ambient temperature), seat (leakage) test pressure (1.1× maximum allowable pressure), and allowable leakage rates for different leakage classes. For metal-seated valves, API 598 Table 5 defines allowable liquid leakage in drops per minute and gas leakage in mm³/s based on valve size. Soft-seated valves must achieve zero leakage. TAR field testing often uses low-pressure air tests (typically 5–7 bar) for seat leakage rather than hydrostatic tests where process fluid reinstatement is difficult, but the test must be properly documented as a low-pressure pneumatic test and any acceptance criteria variance must be formally approved.
API 6D (Pipeline and Pigging Valves) applies to ball valves, gate valves and check valves on pipeline and trunk line services. It specifies both seat testing (metal-to-metal and soft-seated) and double block and bleed testing requirements for double-block valves. For pipeline isolation valves, API 6D seat test acceptance criteria are typically stricter than API 598, particularly for large bore valves on gas services.
ISO 5208 (Industrial Valves — Pressure Testing of Metallic Valves) provides five rate classes (Rate A through Rate E) for seat leakage testing, from zero permissible leakage (Rate A, equivalent to ANSI/FCI 70-2 Class VI) down to Rate E (high-permitted leakage, for throttling service metal-seated valves). Many European operators and EPC contractors specify ISO 5208 test classes rather than API 598 criteria.
For SIL-rated ESD valves, IEC 61511 requires functional testing at a frequency determined by the Safety Instrumented Function’s Proof Test Interval (PTI). The turnaround is the natural opportunity to perform the full proof test — full-stroke functional test, timing measurement, and seat leakage test — and record the results formally in the SIF dossier to demonstrate that the SIL is being maintained.
The Field Testing Sequence: Step by Step
Once the plant is safely isolated, depressurised, purged and handed over to maintenance under a formal permit-to-work, the valve inspection sequence typically follows this order for each valve in scope.
External inspection comes first. Before any disassembly, visually inspect the valve body, bonnet and flanges for corrosion, erosion, mechanical damage, cracks, pitting and external leakage residue (staining, mineral deposits, product traces). Measure body wall thickness at representative points using ultrasonic thickness gauges where corrosion is suspected. Flange face condition — gasket contact surface integrity — is checked for scoring, pitting or corrosion that will prevent a good gasket seal on reinstatement.
Seat leakage test (in situ, if possible). For valves that can be tested in situ using the plant isolation and vent connections, seat leakage is the first test performed after pressurising with air or nitrogen. For a gate or ball valve, close the valve, apply test pressure to one side, open the downstream vent and measure leakage. For a double-block-and-bleed valve, test each seat independently. Record measured leakage against the applicable standard acceptance criteria.
Disassembly (if required). Valves that fail seat testing, are on mandatory strip-and-inspect scope, or require actuator removal for inspection are disassembled. Careful disassembly procedure — noting orientation of components, applying corrosion penetrant to corroded fasteners, using correct flange spreader tools — prevents damage that creates new defects during the TAR. All removed components are tagged, cleaned and laid out for inspection.
Internal inspection. Gate valve wedges and seats are inspected for wire drawing (erosive groove cutting from throttling or leakage), seat galling, wedge cracking and corrosion. Ball valve balls are inspected for surface finish damage, pitting, scratches and seat ring condition. Plug valves: plug and body taper surfaces. Globe valve discs and seats: erosion, seat wire drawing. Check valve discs, hinges, springs and seat faces. All soft seats, PTFE bearings, O-rings and graphite packings are automatically replaced as a matter of course during TAR disassembly — never reuse elastomeric or polymeric sealing components if the valve has been stripped.
Repair decision. For each inspected component, the decision is: reuse as-is (no significant defect found), refurbish (seat lapping/grinding, body repair welding, re-coating), or replace (component beyond repair, valve beyond economic repair — whole valve replacement). This decision is made by the valve engineer or inspector against defined acceptance criteria, not by habit or optimism.
Reassembly and shell test. After repair or replacement of components, the valve is reassembled (correct torque on all fasteners, correct packing installation procedure — staggered graphite ring joints, correct gland compression), then a shell (hydrostatic or pneumatic) test is performed to verify body integrity and packing seal. The shell test pressure per API 598 is 1.5× pressure rating.
Final seat leakage test. After successful shell test, the seat leakage test is repeated to confirm the repaired or new seats are sealing within the required leakage class. This is the acceptance test before the valve is cleared for reinstatement.
Actuator and control system test. For actuated valves, actuator function is checked: stroke time, torque/thrust output, limit switch calibration, solenoid valve function, positioner response, handwheel engagement (if fitted). Any ESD valve undergoes full-stroke functional testing with timing recorded against the required stroke time specification.
Packing and Gasket Replacement During TAR
Packing and gasket replacement is one of the most consistent value-adding activities during a TAR. The cost of packing and gasket materials is trivial compared to the cost of an in-service stem leak or flange leak that requires emergency response.
For valves on regulated emission services (where fugitive emissions are monitored and reported), packing replacement at every TAR is typically mandatory. The new packing must be installed correctly — rings cut to the right length with a 45° butt joint, installed with staggered joints between rings, gland follower torqued to the manufacturer’s specification, then re-torqued after initial pressurisation. Graphite ring packing is the dominant choice for high-temperature, high-pressure and fugitive emission-critical applications. PTFE chevron packing for cryogenic and ambient-temperature services.
Flange gaskets on process piping are routinely replaced during TAR at flanges that have been broken. Spiral wound gaskets — the standard choice for refinery and petrochemical flanges — must be replaced with the correct metal winding material and filler (316SS/PTFE for process services, CS/graphite for steam), correct pressure class (ASME B16.20) and correct centering ring. RTJ (Ring Type Joint) gaskets are replaced with new soft iron or low-alloy steel rings at the correct octagonal or oval cross-section. Gasket material must be compatible with the process fluid and within temperature ratings — never substitute one type for another without engineering sign-off.
Control Valve TAR Activities
Control valves have a specific set of TAR activities beyond basic isolation valve testing. The trim (plug/disc and seat ring) is inspected for erosion, cavitation damage and wire drawing. Severe cavitation damage — pitting and cratering on the downstream side of the trim — indicates that the valve has been operating with excessive pressure drop or in a cavitating regime, and trim selection should be reviewed.
Stem and stem packing condition is assessed. High-cycle control valves accumulate significant packing wear. Packing is replaced as standard during TAR. Actuator spring condition (compression spring fatigue, corrosion), diaphragm integrity and positioner calibration are all verified. The positioner is stroked through its full range and the input/output relationship verified against the calibration certificate. Any smart positioner diagnostic data (travel histogram, signature curve, valve health index) is downloaded and reviewed before disassembly.
After reassembly, the control valve is bench-tested: stepped input signal test (0%, 25%, 50%, 75%, 100% input), stroke time measurement, and seat leakage test in accordance with IEC 60534-4 and the applicable leakage class specified in the valve data sheet.
Safety Relief Valve Testing and Recertification
Safety relief valves (SRVs) and pressure safety valves (PSVs) are regulated devices. Their TAR activities are governed by national pressure vessel codes (ASME PCC-3, API 576, PED in Europe) and require certified testing by a competent inspector or valve repair shop authorised under the relevant national authority.
SRVs are typically removed from the plant, sent to a specialist valve repair shop, and bench-tested on a calibrated test stand. The pop (opening) pressure is adjusted to within ±3% of the set pressure. Seat tightness is verified (cold differential test pressure). The valve is recertified, resealed and returned with a calibration certificate. The shop test record becomes part of the plant’s SRV dossier, required for regulatory inspection and insurance purposes.
On-line testing using pop testing tools (where the valve can be briefly opened against the process pressure to confirm set point) is used at some facilities between TARs to verify SRV function without removing the valve from service, but full bench testing and recertification at each TAR remains the standard for most regulated facilities.
TAR Valve Management — Logistics and Documentation
The operational aspects of TAR valve management — parts procurement, workshop logistics, documentation — are as important as the technical inspection activities. A valve that has been properly inspected and repaired but cannot be reinstated because the replacement seat ring is the wrong size, or the inspection record has not been signed off, is a failure of a different kind.
Parts procurement must be completed before shutdown begins. Long lead items — specialist trim sets for severe service control valves, exotic alloy seat rings, large bore gate valve wedges — can have lead times of 8–20 weeks. TAR valve scope must be confirmed and parts ordered at least 3–6 months before the shutdown date. On-site spare parts holding for high-criticality valves (complete overhaul kits, replacement actuators) allows rapid response if inspection reveals worse-than-expected condition.
Documentation requirements for each inspected valve include: pre-inspection condition assessment, test results (with actual measured values, not just pass/fail), details of all components replaced, post-repair test results, inspector sign-off and engineering acceptance. All records must be retained in the CMMS against the valve asset number and available for regulatory inspection. For SIL-rated ESD valves, the proof test record is a mandatory element of the functional safety management system.
Repair vs Replace Decision Making
The repair vs replace decision is one of the most important and frequently poorly made decisions in valve TAR management. The bias in many organisations is to repair because it appears cheaper. This is often a false economy.
A valve should be replaced rather than repaired when the body wall thickness has fallen below the minimum calculated value, when seat damage is so severe that re-lapping or seat insert replacement cannot restore the required leakage class, when the valve design is obsolete and spare parts are no longer available, when the metallurgy is unsuitable for the current or future process conditions (a common situation as feedstocks change in refineries), or when the cumulative cost of repair exceeds 50–60% of new valve replacement cost.
A valve should be repaired when the body is sound, the damage is confined to replaceable trim components, genuine OEM or approved equivalent spare parts are available, and the repair can be completed and tested within the TAR window. Repair is almost always the right decision for large bore, high-alloy or bespoke valves where replacement lead time or cost is prohibitive — provided the body integrity is confirmed sound.
Post-TAR Valve Performance Review
The best turnaround organisations do not simply complete the TAR scope and move on. They perform a structured post-TAR review approximately 3–6 months after restart to assess the quality of the TAR valve work. Key metrics include: number of valve-related failures or leaks in the post-restart period (the figure of merit for TAR execution quality), comparison of pre-TAR and post-TAR acoustic leakage scan data to confirm seat quality improvement, and any process upsets or control loop detuning that can be attributed to control valve condition.
Lessons learned from every TAR — scope gaps (valves that should have been included but were not), parts shortages, test failures on newly repaired valves, missed documentation — are captured and fed back into the planning process for the next shutdown. The best plants improve their TAR valve performance systematically over successive shutdowns, achieving longer run-lengths, fewer unplanned interventions and lower total valve maintenance cost per year.
Key Takeaways for Valve Engineers
Turnaround valve management is a discipline that rewards preparation and penalises improvisation. Build your scope from objective criticality data, not habit. Gather condition monitoring data before the shutdown. Have the right parts, the right people and the right procedures ready before the plant stops. Test to the applicable standard. Document everything. Make repair vs replace decisions on engineering grounds, not just cost instinct. And use post-TAR performance data to drive continuous improvement. Valves that are properly managed through turnarounds run reliably, don’t leak and don’t surprise you — and that is precisely what a process plant needs.