LNG Export Terminal, Gas Processing, Oil Refinery, Petrochemical & Offshore Platform HVAC Duct Guide — Australian Engineering Reference

Why LNG, gas, refining and petrochemical HVAC is its own engineering discipline

Australian LNG export is the largest single industrial HVAC category by gas value in the country. Australia is the third largest LNG exporter in the world after the United States and Qatar, with ten operating liquefaction trains across Western Australia, the Northern Territory and Queensland that together produce more than 80 million tonnes per annum of LNG for export to Japan, Korea, Taiwan and the Southeast Asian markets. Behind those liquefaction trains sit the upstream gas processing plants, the acid gas removal columns, the dehydration units, the mercury removal beds, the sulphur recovery units and the cryogenic cold boxes — each of which is a building envelope that requires ventilation, hazardous-area zoning, fire-rated separation and pressure cascade design that has nothing in common with the HVAC scope of a commercial office tower or even a chemical formulation plant.

HVAC ductwork inside an LNG export terminal, a gas processing plant, an oil refinery, a petrochemical cracker or an offshore platform is not a comfort-cooling commodity. It is a safety-critical layer of protection between fugitive hydrocarbon emission and the people who operate the plant, between sour-gas leakage and the control room operator, between sulphur recovery off-gas and the maintenance technician, between cryogenic spill vapour and the trucker on the loading rack. The duct material has to survive simultaneous coastal chloride attack (ISO 9223 C5-M in every Australian LNG location, all of which are coastal), hydrocarbon vapour exposure, H2S fugitive emission in sour-gas service, and elevated temperature near the flare radiant zone. The fans, motors and dampers have to be IECEx or ATEX rated to the zone classification, spark-resistant under AMCA 99, and supplied with traceable documentation that goes into the operator’s Major Hazard Facility Safety Case or — for offshore — the OPGGS Act facility Safety Case.

This guide is written for the engineers, project managers, safety leads and procurement specialists who plan, build, operate or refurbish hydrocarbon-process facilities in Australia — Woodside on the North West Shelf and at Pluto, Chevron at Wheatstone and Gorgon, Shell at Prelude FLNG and on Curtis Island at Queensland Curtis LNG, INPEX at Ichthys, Santos at Darwin LNG and the Gladstone Santos LNG and Moomba complexes, ConocoPhillips and Origin at Australia Pacific LNG, ExxonMobil and Santos in the Bass Strait, Viva Energy at the Geelong refinery, Ampol at the Lytton refinery, the petrochemical legacy at Botany and Altona (Qenos closed 2024) and the proposed lower-carbon projects across the Pilbara and the Top End. It is also written for the EPC contractor base that builds these facilities — Worley, Bechtel Australia, Fluor Australia, McDermott, KBR, Saipem, Monadelphous, John Holland and Civmec — and for the fabrication shops that supply duct to those contractors.

The recurring failure mode we see in the Australian hydrocarbon market is the same one we see in the chemical sector — somebody specifies galvanised duct where 316L stainless was required, and inside two summers on the Pilbara coast the zinc is consumed by combined salt and hydrocarbon attack, the underlying carbon steel rusts through and fugitive emission breaches the building Safety Case. The cost of getting the metallurgy wrong is not a service call — it is a notifiable event under the OPGGS Act or the state Major Hazard Facility regulations.

The Australian LNG export industry — the largest single HVAC category by gas value

Before specifying ductwork an engineer needs a clear picture of the asset base. Australia operates ten LNG liquefaction trains across three regions, with several FLNG and FPU facilities offshore. The following is a working map of the major LNG export terminals operating in Australia in 2026.

North West Shelf (NWS) — Karratha, Western Australia

The North West Shelf venture, operated by Woodside Energy with joint-venture partners BP, Chevron, Shell, Mitsubishi, Mitsui and BHP, is the oldest LNG export operation in Australia. The Karratha Gas Plant on the Burrup Peninsula has five LNG trains with a combined nameplate capacity of approximately 16.9 million tonnes per annum, alongside domestic gas, condensate and LPG production. The HVAC scope across the Karratha site includes liquefaction train cold boxes, boil-off gas compressor enclosures, amine regeneration buildings, sulphur recovery units, dehydration buildings, mercury removal sheds, the LNG storage tank instrument room, the loading jetty control building, the central control room complex, the substations and the workshop and maintenance buildings. Every exposed duct is 316L stainless because of the combined Pilbara salt-aerosol and hydrocarbon environment.

Pluto LNG — Karratha, Western Australia

Pluto LNG, operated by Woodside Energy, sits adjacent to the Karratha Gas Plant and has been progressively expanded with the Pluto Train 2 development. The HVAC envelope is similar to the NWS scope but with the addition of more recent design conventions — tighter pressurisation tolerances on control rooms, more comprehensive H2S and hydrocarbon detection integration, and a more conservative AMCA 99 spark-resistant fan specification across all Zone 2 envelopes.

Wheatstone LNG — Onslow, Western Australia

Wheatstone LNG, operated by Chevron with partners including Kuwait Foreign Petroleum Exploration, Woodside and the Japanese KUFPEC-Mitsubishi-Mitsui consortium, has two LNG trains and a domestic gas plant at Ashburton North near Onslow. The site is the centrepiece of the Wheatstone Hub that processes gas from the Wheatstone, Iago and Julimar fields. The HVAC scope includes all of the standard LNG building envelope plus a substantial domestic gas plant module that supplies regional Western Australia with sweet pipeline gas.

Gorgon LNG — Barrow Island, Western Australia

Gorgon LNG, operated by Chevron with Shell and ExxonMobil as joint-venture partners, is built on Barrow Island, a Class A nature reserve, with three LNG trains and a domestic gas plant. The Gorgon, Jansz-Io and Greater Gorgon gas fields feed the site through the longest subsea trunkline network in Australia. Gorgon is technically more complex than the other Australian sites because of the carbon capture and storage (CCS) project that re-injects approximately 4 million tonnes per annum of CO2 into the Dupuy formation beneath Barrow Island — the CO2 compression buildings sit alongside the LNG trains and add a CO2-asphyxiation hazardous category to the standard hydrocarbon and H2S envelope. The HVAC scope for the CCS buildings includes CO2 detection (an asphyxiation hazard distinct from hydrocarbon LEL), emergency ventilation at 30 ACH on CO2 detection above the asphyxiation threshold, and 316L stainless duct throughout because of the high humidity (CO2 in moist air forms carbonic acid which attacks zinc).

Prelude FLNG — offshore Western Australia

Prelude FLNG, operated by Shell with INPEX, Korea Gas (KOGAS) and CPC Taiwan, is the world's first floating LNG facility. The 488 metre long FLNG facility is moored over the Prelude gas field about 475 kilometres north-northeast of Broome. The HVAC scope on an FLNG is the same as a fixed offshore platform plus the full LNG liquefaction train envelope — every building is exposed to a salt-laden marine atmosphere, every duct runs along the topsides through extensive Zone 1 and Zone 2 envelopes, and the accommodation module is fire-walled with A-60 rated barriers per IMO SOLAS. Duct material is 316L stainless throughout with fully welded longitudinal and circumferential seams.

Ichthys LNG — Darwin, Northern Territory

Ichthys LNG, operated by INPEX with TotalEnergies as the major joint-venture partner, has two LNG trains at Bladin Point near Darwin, fed by the Ichthys field 850 kilometres offshore through one of the longest subsea pipelines in the world. The offshore production envelope includes the Ichthys CPF (central processing facility) and the Ichthys FPSO. Onshore at Bladin Point the LNG train scope is the standard LNG envelope plus a substantial condensate splitter that adds an additional flammable-liquid handling envelope under AS 1940.

Darwin LNG — Wickham Point, Northern Territory

Darwin LNG, operated by Santos with joint-venture partners including SK E&S, INPEX, ENI, Tokyo Gas and Tokyo Electric, has a single LNG train at Wickham Point in Darwin Harbour. The site was originally fed by the Bayu-Undan field in the Timor Sea, with a transition to Barossa gas under the Barossa development. The HVAC envelope is a single-train scope but with the same Top End humidity and salt loading as Ichthys, driving 316L stainless throughout.

Queensland Curtis LNG (QCLNG) — Gladstone, Queensland

QCLNG, operated by Shell with Tokyo Gas as a joint-venture partner, was the first coal seam gas to LNG project in the world. The site is on Curtis Island in Gladstone Harbour with two LNG trains fed by coal seam gas from the Surat Basin through one of the longest pipeline networks in Australia. Coal seam gas is sweeter than the Western Australian offshore gas (lower H2S, lower CO2) but it carries higher water content and condensate variability, which drives a more demanding dehydration train. The HVAC scope is the standard LNG envelope plus the coal seam gas water-treatment buildings that handle produced water from the upstream gas fields.

Australia Pacific LNG (APLNG) — Gladstone, Queensland

APLNG, operated by ConocoPhillips with Origin Energy as joint-venture partner, is the second coal seam gas to LNG project on Curtis Island. The site has two LNG trains with combined capacity of approximately 9 million tonnes per annum. The HVAC scope is analogous to QCLNG.

Gladstone LNG (GLNG) — Gladstone, Queensland

GLNG, operated by Santos with PETRONAS, TotalEnergies and KOGAS as joint-venture partners, is the third coal seam gas to LNG project on Curtis Island. The site has two LNG trains with combined capacity of approximately 7.8 million tonnes per annum.

The Australian natural gas processing footprint

Upstream of the LNG export terminals sit a number of gas processing plants that condition raw gas before it enters the liquefaction train. The major Australian gas processing sites include the Karratha Gas Plant (Woodside, the largest), the Wheatstone Hub (Chevron), Wickham Point (Santos, Darwin), Moomba (Santos, the Cooper Basin processing hub in South Australia), and the Gladstone gas plants that feed the Curtis Island LNG operations. Each is a complex of acid gas removal columns, dehydration trains, mercury removal beds, sulphur recovery units, dewpointing units, fractionation columns and product custody-transfer infrastructure. The HVAC scope inside each of these process buildings is dictated by the chemistry of the upstream gas — sour gas from offshore Western Australia carries H2S and CO2; coal seam gas from Queensland is sweeter but wetter; the Cooper Basin gas at Moomba is a complex mix of sweet, sour and condensate-rich streams that drives a wide spectrum of duct metallurgy decisions across the plant.

The Australian oil refinery footprint — only two left

Australia operated four oil refineries until the early 2020s. BP closed its Kwinana refinery in Western Australia in 2021 and converted the site to an import terminal. ExxonMobil closed its Altona refinery in Victoria the same year and converted Altona to an import terminal. That left two operating refineries — Viva Energy at Geelong in Victoria and Ampol Lytton in Brisbane.

Viva Energy Geelong refinery — Victoria

The Viva Energy Geelong refinery, formerly Shell Geelong, is one of the last two operating petroleum refineries in Australia. The site processes approximately 120,000 barrels per day of crude oil into petrol, diesel, jet fuel, LPG, bitumen and a portfolio of refined products that supply Victorian and southern New South Wales markets. The refinery includes atmospheric and vacuum distillation columns, a fluid catalytic cracker (FCC), a hydrocracker, a catalytic reformer, an alkylation unit (sulphuric acid catalyst), a hydrogen plant (steam methane reformer), a sulphur recovery unit, tank farms and a marine berth on Corio Bay. The HVAC scope across the site includes process unit pumphouses (Zone 2 throughout), control rooms (pressurised non-hazardous), substations (pressurised), motor control centres (pressurised), the laboratory and on-line analyser shelters, the workshop and maintenance buildings, and the admin and amenity buildings (non-hazardous, segregated). Duct material is 316L stainless throughout the process islands and galvanised in segregated non-hazardous areas. The site sits in a coastal salt-aerosol environment that drives 316L on exterior duct even in non-hazardous areas.

Ampol Lytton refinery — Brisbane, Queensland

The Ampol Lytton refinery in Brisbane is the second of the two remaining Australian refineries. The site processes approximately 109,000 barrels per day with a unit slate similar to Geelong — atmospheric and vacuum distillation, FCC, hydrocracker, reformer, alkylation, hydrogen plant, sulphur recovery, tank farm and marine berth. The Lytton refinery is on the Brisbane River near the mouth and is exposed to similar coastal chloride loading. The HVAC scope is analogous to Geelong with the addition of a number of operator-specific units and the historical legacy of the Caltex Lytton operating practices.

The Australian petrochemical footprint

The Australian petrochemical industry has contracted significantly over the past decade. The major remaining operations and the historical legacy include:

• Qenos (closed 2024). Qenos operated the Botany NSW ethylene cracker and the Altona VIC polyethylene plant as the only Australian primary polyethylene producer. The operation was closed in 2024 ending domestic ethylene cracking and primary PE manufacture. The site remains as a brownfield with potential redevelopment.
• Orica Yarwun and Botany. Orica operates explosives, ammonium nitrate and chemicals at Yarwun in Gladstone QLD and Botany in NSW — covered separately in the specialty chemicals, petrochemical, agrochemical and industrial gas HVAC duct guide.
• Incitec Pivot. Phosphate Hill, Gibson Island and Moranbah — fertiliser and ammonium nitrate. Covered in the specialty chemicals guide.
• CSBP Kwinana. Wesfarmers chemicals operation — ammonia, ammonium nitrate, sodium cyanide. Covered in the specialty chemicals guide.
• Yara Pilbara Fertilisers. Karratha WA — ammonia and ammonium nitrate. Covered in the specialty chemicals guide.
• Australian Vinyls. Botany NSW — PVC and chlor-alkali heritage.

The Australian offshore production footprint

Australia operates a significant offshore production fleet that feeds the LNG export terminals and the domestic gas market.

Bass Strait — Victoria

The Bass Strait fields off the south coast of Victoria are operated by ExxonMobil with Santos as a joint-venture partner, in the Gippsland Basin. The fields produce gas, condensate and crude oil that feeds the Longford Gas Plant, the Esso Long Island Point and the Altona import terminal. The offshore production envelope includes fixed platforms and subsea tiebacks; HVAC scope on the platforms is for accommodation modules, control rooms, equipment shelters, helideck-side utilities and the standard hydrocarbon process exposure on every topside walkway.

North West Shelf platforms

The North West Shelf includes a fleet of fixed platforms and FPSO/FPU facilities feeding the Karratha Gas Plant. The Goodwyn Alpha, North Rankin Alpha and North Rankin Bravo platforms are the major facilities; the Okha FPSO and other production vessels operate in the area.

Greater Gorgon and Jansz-Io — Western Australia

The Greater Gorgon field complex and the Jansz-Io subsea development feed the Gorgon LNG site on Barrow Island. The Reef Triton platform is one of the larger fixed installations in the area, with extensive subsea tiebacks.

Ichthys offshore FPU and FPSO

The Ichthys development includes the Ichthys Explorer FPU (Central Processing Facility) and the Ichthys Venturer FPSO that together process raw gas and condensate from the Ichthys field before pipeline transport to Bladin Point near Darwin.

Prelude FLNG

The Prelude FLNG facility, covered above under the LNG section, is the world’s first floating LNG facility and combines an FPSO-style production envelope with a full LNG liquefaction train on a single moored hull.

Bayu-Undan (transition to Barossa)

The Bayu-Undan field in the Timor Sea, operated by Santos, fed the Darwin LNG plant for most of its operating life. The field has been transitioning out of production as the Barossa development comes online to take over feed gas supply to Darwin LNG.

Why galvanised duct fails inside two Pilbara summers

Almost every newcomer to Australian LNG HVAC starts with the wrong assumption — that galvanised steel duct, which works perfectly well in commercial buildings, schools, hospitals and warehouses, can be patched into an LNG plant or a refinery by being thicker or by being painted. It cannot, and the reason is the combined chloride-and-hydrocarbon environment of every Australian hydrocarbon production location.

Galvanised steel is carbon steel coated with a layer of zinc — typically Z275 (275 g/m² zinc-coated both sides) for HVAC duct stock. Zinc is sacrificial — it corrodes preferentially to protect the underlying steel because zinc is anodic to iron in the galvanic series. In a benign indoor air environment the zinc oxidises slowly to form a protective passive layer that arrests further corrosion. In a coastal salt-laden hydrocarbon-vapour environment the passive layer is consumed by chloride pitting plus organic-vapour disruption, and once it is gone the bare zinc corrodes at full speed until it is gone too. The exposed carbon steel then rusts uncontrollably.

The Australian Pilbara coast at Karratha, Onslow and Barrow Island is classified as ISO 9223 corrosivity category C5-M (Industrial Marine) — the second-most aggressive category in the global ISO standard, exceeded only by the dedicated CX tropical-marine offshore designation. The Darwin Top End coast and the Gladstone Curtis Island coast both sit in C5-M as well. The combined effect of:

• chloride aerosols from sea spray (the dominant pitting mechanism for zinc),
• high humidity (driving wet-time well above the 5,500 hour annual threshold for severe corrosion),
• elevated temperature (every 10°C increase approximately doubles corrosion rate),
• fugitive hydrocarbon vapours that disrupt zinc passive layer formation,
• occasional fugitive H2S and SO2 from sour gas and sulphur recovery operations,

is to consume a Z275 zinc coating in 12 to 24 months at any Australian LNG location. Once the zinc is gone the carbon steel underneath perforates within another 18 to 36 months. The total service life of galvanised duct at any Australian LNG site is approximately three to five years, against the 25 to 40 year design life of the plant. The fix is to specify 316L stainless throughout from day one and never let a galvanised section past the drawing review.

Stainless 316L — the LNG and offshore HVAC default

The default material for HVAC ductwork in Australian LNG, gas processing, refining, petrochemical and offshore service is austenitic stainless steel grade 316L. The L stands for low-carbon (≤0.03 percent carbon) — the low-carbon variant resists sensitisation and intergranular corrosion in the heat-affected zone after welding, which matters because every joint in a TIG-welded sour-service duct is a welded joint. Standard 316 with 0.08 percent carbon is acceptable for short ducts that do not require welding-grade corrosion resistance, but for full-shop-fabricated welded systems 316L is the sensible default.

The relevant 316L chemistry is approximately 17 percent chromium, 12 percent nickel and 2.5 percent molybdenum, with the rest iron. The chromium forms the passive chromium-oxide layer that protects the underlying alloy; the nickel stabilises the austenitic phase; the molybdenum gives the alloy its resistance to chloride pitting — the dominant failure mechanism of the cheaper 304 stainless in coastal and chloride-rich environments. Every Australian LNG, gas processing, refining and offshore site is coastal, and the chloride loading from sea spray alone is enough to drive a switch from 304 to 316L. Once 316L is on the drawing, it survives almost everything the Australian hydrocarbon environment can throw at it short of strong halogen acids at temperature and severe sour-gas service at high H2S concentrations.

For SBKJ-fabricated 316L duct the standard configuration is full-thickness 316L sheet stock (1.2 mm minimum for low-pressure extract, 1.6 mm or 2.0 mm for process-extract and any duct downstream of a fan), longitudinal seams TIG-welded with 316L filler metal on the SB-ZF1500 automatic stitchwelder, transverse joints either TIG-welded butt joints or 316L flanged joints with chemically compatible gaskets (EPDM, Viton or PTFE depending on chemistry). Internally the duct is passivated after welding with a citric or nitric pickle to restore the chromium-oxide layer in the heat-affected zone. The result is a duct that lasts 25 to 40 years in service — matching the plant design life.

Inconel 625 and Monel — the severe sour-service upgrade

316L is not the answer for severe sour service. The two scenarios where it fails in an Australian gas plant or refinery are wet H2S at high partial pressure and high-temperature acid attack. Wet H2S above approximately 100 ppm partial pressure can cause sulphide stress cracking in even the low-carbon stainless grades; in those environments the upgrade specification is to a nickel-base alloy — Inconel 625, Inconel 825, Monel 400 or Hastelloy C-276 depending on the specific chemistry. ISO 15156 NACE MR0175 is the international standard that governs material selection for sour service and is referenced throughout Australian gas-industry specifications.

The relevant scenarios on Australian LNG, gas processing and refining sites are:

• Amine acid gas removal (AGR) — Inconel 625 cladding on hot rich-amine extract. The rich-amine stream leaving the absorber column is loaded with H2S and CO2 and the regenerator overhead carries hot wet acid gas. Localised duct sections near these points are clad with Inconel 625 to resist sulphide stress cracking.
• Sulphur recovery unit (SRU) — Inconel 625 on hot tail-gas paths. The Claus process furnace tail gas carries SO2, residual H2S, sulphur vapour and water at elevated temperature. Localised duct sections are clad with Inconel 625 or specialised refractory-lined steel.
• Acid gas injection (AGI) — Monel or specialty alloy. Where H2S-rich acid gas is recompressed and re-injected to the formation as an alternative to sulphur recovery, the recompression building handles a fugitive-emission risk that warrants Monel or specialty cladding on the localised extract.
• HF alkylation enclosure (refinery — historical). Hydrofluoric acid alkylation has been used at some Australian refineries historically; the building extract requires Monel or specialised alloy because of HF aggressiveness toward stainless steel.
• Hot sulphuric acid alkylation (refinery — current). Sulphuric acid alkylation is more common in modern Australian refining. The local extract over the acid settler runs in stainless steel for cold acid and Inconel 625 for any hot path.

The procurement reality is that Inconel and Monel cost roughly five to eight times the equivalent 316L on a per-tonne basis, and the welding requires specialist procedures that are outside the standard SBKJ scope. The right approach is to map the duct network bay-by-bay and use 316L for general service with localised Inconel or Monel cladding at the severe sour-service nodes — supplied by specialist alloy fabricators that work alongside the SBKJ-equipped 316L shop. SBKJ does not fabricate Inconel or Monel directly; the SBAL-V, SB-ZF1500 and SBPC1500 are configured for 316L and the high-end alloys are sub-contracted to specialist suppliers.

AS/NZS 60079 — the hazardous-area framework

The AS/NZS 60079 series is the Australian implementation of the international IEC 60079 hazardous-area standards. It is the governing technical standard for every electrical and ventilation specification inside an explosive-atmosphere envelope.

AS/NZS 60079.10.1 — Classification of areas, explosive gas atmospheres

AS/NZS 60079.10.1 classifies areas where flammable gas or vapour may be present. The classification produces zones — Zone 0 where an explosive atmosphere is continuously present, Zone 1 where it is likely to be present in normal operation, and Zone 2 where it is unlikely and only present briefly. For an LNG, gas processing or refining site the classification yields:

• Zone 0 — inside the LNG storage tank vapour space, inside the column overheads and the inside of any closed pipe. Not a ventilation envelope.
• Zone 1 — LNG truck loading rack vapour zone (within 3 m of the loading arm), marine berth manifold area, flare knock-out drum vicinity, boil-off gas compressor enclosure, amine regenerator overhead area, sulphur recovery unit overheads, dehydration unit overheads, helideck fuelling envelope on offshore platforms.
• Zone 2 — the perimeter of process units, pump bays, valve manifold areas, the interior of process buildings where ventilation maintains continuous dilution, the area immediately outside Zone 1 envelopes.

HVAC fans, motors and dampers inside any of these zones must be IECEx-certified to match the zone. Ductwork is passive sheet metal and not certified as a product but must be electrically continuous and bonded to the site earth.

AS/NZS 60079.14 — Electrical installations design, selection and erection

AS/NZS 60079.14 governs the design, selection and erection of electrical installations in hazardous areas. For HVAC scope this is the standard that says the fan terminal box, the motor terminal box, the damper actuator and every cable gland must be selected to match the Equipment Protection Level (EPL) for the zone. The IECEx Ex marking on the fan and motor nameplates must trace back to a current IECEx certificate of conformity issued by a recognised certification body.

AS/NZS 60079.17 — Electrical installations inspection and maintenance

AS/NZS 60079.17 governs the inspection and maintenance of hazardous-area electrical installations. For HVAC this drives the maintenance schedule for fan and motor inspection, damper actuator inspection, gas detector calibration, the integrity check of duct earthing continuity and the cable-gland tightness check. The plant operator schedules these inspections at intervals defined by the standard (typically annual close inspection and triennial detailed inspection) and the maintenance records become part of the operating documentation.

AS/NZS 60079.19 — Equipment repair, overhaul and reclamation

AS/NZS 60079.19 governs the repair and overhaul of hazardous-area electrical equipment. Where a fan motor or damper actuator is removed for service the repair must be conducted to the standard, with the certification status preserved through the repair cycle.

AS/NZS 60079.31 — Equipment dust ignition protection by enclosure

AS/NZS 60079.31 covers the Ex t protection technique for equipment in dust hazardous areas. For LNG and gas processing the dust scope is limited — the main dust hazard categories are solid sulphur in the SRU storage area and the rare hydrocarbon-soot envelope around flare stacks. For petrochemical and refining the dust scope is broader, with FCC catalyst handling, sulphur prilling and additive blending all driving Zone 22 envelopes.

NFPA 59A — the LNG-specific standard

NFPA 59A (Standard for the Production, Storage, and Handling of Liquefied Natural Gas) is the American standard most widely referenced in LNG project Safety Cases globally and in Australia. The Australian regulatory framework does not directly adopt NFPA 59A but Australian LNG project Safety Cases reference it as a benchmark practice, especially for separation distances, building siting and ventilation around LNG storage tanks. The standard prescribes:

• Separation distances between LNG tanks and adjacent buildings, sized to limit thermal radiation and vapour cloud dispersion in a credible release event.
• Vapour barrier and impoundment design around LNG tanks.
• Ventilation rates for indoor LNG transfer and dispensing facilities — typically 6 to 12 ACH on normal operation stepping to 30 ACH on hydrocarbon detection.
• Gas detection coverage in LNG buildings — both methane (catalytic-bead or infrared for LEL) and oxygen depletion (for the asphyxiation hazard of nitrogen purge or natural gas displacement).

NFPA 50A and NFPA 50B are historical standards for LNG storage; NFPA 55 covers compressed gases and cryogenic fluids storage and handling more broadly and is referenced for LNG fuel-dispensing facilities (LNG-powered trucks and ships).

API 520, 521, 650 and the pressure-relief interface

API 520 (Sizing, Selection, and Installation of Pressure-Relieving Devices) and API 521 (Pressure-relieving and Depressuring Systems) govern the flare and vent header design of process plants. The HVAC interface to these standards is that relief streams discharged at low level under fault conditions can flood the HVAC intake of an adjacent control room, substation or amenity building. API RP 752 (Management of Hazards Associated with Location of Process Plant Permanent Buildings) is the umbrella standard for building siting in petrochemical and refining plants — it constrains where HVAC fresh-air intakes can be located. Intakes must be placed so that a credible flammable-vapour cloud cannot be drawn into the building, which usually means high-level intakes on the side furthest from the process area and overpressure dampers wired through the gas-detection system.

API 650 (Welded Tanks for Oil Storage) governs the atmospheric storage tank design and is referenced for the tank farm scope. The HVAC interface is that floating roof tanks and external floating roof tanks have a vapour recovery system that ties back to the flare or vapour return header — the area immediately around a tank is Zone 2 by AS/NZS 60079.10.1 and the access-hatch local extract is 316L stainless.

API 1104 and ASME B31 — the piping interface

API 1104 (Welding of Pipelines and Related Facilities) and ASME B31.3 (Process Piping) and B31.8 (Gas Transmission and Distribution Piping Systems) govern the process piping welding. These standards do not apply to ductwork — Australian ductwork follows AS 4254 and AS/NZS 1554.6 for welding — but they are referenced in this guide because the HVAC duct fabricator must understand the piping interface. The pipe penetrations through building walls are sealed with AS 1530.4 fire-rated penetrations; the pipe support and the duct support cannot share the same structural steel without explicit engineering review for vibration and thermal expansion.

API 14, RP 14C and RP 14J — the offshore standards

API 14 (Specification for Offshore Platforms), API RP 14C (Recommended Practice for Analysis, Design, Installation, and Testing of Safety Systems for Offshore Production Platforms) and API RP 14J (Recommended Practice for Design and Hazards Analysis for Offshore Production Facilities) govern the offshore platform safety design. For HVAC on a fixed offshore platform or FPSO/FLNG these standards drive:

• Hazardous-area classification with API RP 14J as the offshore equivalent of AS/NZS 60079.10.1.
• Safety system analysis under API RP 14C — the HVAC system on a platform is part of the safety system inventory and is documented in the platform Safety Analysis Function Evaluation chart.
• Accommodation module fire protection — A-60 rated bulkheads and decks per IMO SOLAS and the AS 1530.4 equivalent. HVAC penetrations through these barriers require certified fire-rated dampers and intumescent seals.
• Helideck fuelling area classification — typically Zone 1 within 3 m of the fuelling point and Zone 2 to 15 m. HVAC intake locations must be on the opposite side of the platform.

OPGGS Act, NOPSEMA, WHS and MARPOL — the Australian offshore regulatory frame

Australian offshore facilities operate under the Offshore Petroleum and Greenhouse Gas Storage Act (OPGGS), administered by NOPSEMA — the National Offshore Petroleum Safety and Environmental Management Authority. The Act and its associated regulations require an operating facility to maintain a Safety Case approved by NOPSEMA; the Safety Case includes a Formal Safety Assessment (FSA) of every credible major accident event scenario, with the HVAC system identified as a control or recovery measure where appropriate.

The WHS Regulations for offshore facilities sit alongside the OPGGS Act and impose duty-of-care obligations on the operator for the health and safety of workers, including the workplace exposure standards published by Safe Work Australia. The relevant exposure standards for hydrocarbon and gas-processing workers include hydrogen sulphide (10 ppm TWA, 15 ppm STEL — extremely toxic), carbon monoxide (30 ppm), sulphur dioxide (2 ppm), mercaptans including methyl mercaptan (0.5 ppm STEL), benzene (1 ppm STEL — extremely toxic carcinogen present in petroleum refinery streams), toluene (50 ppm), xylene (50 ppm), ethylbenzene (100 ppm), hexane (50 ppm), n-pentane (600 ppm), propane (1000 ppm), methane (1000 ppm — asphyxiant), oxygen (19.5% to 23.5%), ammonia (25 ppm TWA, 35 ppm STEL), monoethylene glycol and triethylene glycol (minor), MDEA methyldiethanolamine (1 ppm TWA), mercury vapour (0.025 mg/m³ — relevant to gas treatment), arsine AsH3 (0.05 ppm STEL — extremely toxic, present in some natural gas streams), and particulate sulphur powder (5 mg/m³).

IMO MARPOL Annex VI governs air pollution from ships and offshore facilities and imposes emission limits on engine exhaust, flare emission and overall facility off-gas. The HVAC interface is on the emission stack monitoring scope — process emissions stacks (NOx, SO2 and VOC continuous emissions monitoring systems, or CEMS) are heated to prevent condensation and built in 316L stainless for the sampling line and probe assembly.

The LNG cryogenic train — cold box building HVAC

The heart of an LNG export terminal is the liquefaction train — the chain of heat exchangers, refrigerant compressors and cryogenic columns that cool natural gas from approximately 30°C to -162°C, condensing it into liquid for storage and export. The cold box is the insulated enclosure (typically perlite-insulated steel) around the cryogenic distillation column and the main heat exchangers. The HVAC scope around a cold box building is shaped by three constraints:

• Cold spill containment. A leak of LNG inside the cold box produces a heavy cold vapour cloud that sinks to ground level and disperses slowly. HVAC ventilation must achieve displacement flow — supply at high level, extract at low level — to avoid trapping cold vapour in the bottom of the enclosure.
• Asphyxiation risk. Cold methane vapour displaces oxygen as it expands; a leak in an enclosed cold-box building creates an oxygen-depletion hazard before it creates a flammability hazard. Oxygen monitoring at 19.5 percent triggers emergency extract at 30 ACH.
• Brittle-fracture risk to structural steel. Cold spill onto the structural steel of the building can cause brittle fracture below the steel’s nil-ductility transition temperature. HVAC supply diffusers are positioned to avoid cold-jet impingement on structural members; ventilation is sized to dilute any cold vapour cloud before it can contact structure.

The duct material around a cold box building is 316L stainless throughout. The supply air is conditioned to a controlled temperature (typically 18 to 24°C) to maintain stable conditions around the cold box vapour barrier; the extract is sized for both normal-mode dilution (12 ACH) and emergency-mode displacement (30 ACH on oxygen-depletion or hydrocarbon LEL). Fans are spark-resistant with IECEx Ex-d motors. Damper actuators are Zone 2 rated.

LNG storage tank — full containment design and boil-off gas handling

The LNG storage tank at an Australian export terminal is a full-containment tank — an inner tank of 9 percent nickel steel containing the LNG at -162°C, a concrete outer tank that serves as the secondary containment in a worst-case leak, and a perlite insulation layer between them that minimises heat ingress. Each tank holds 130,000 to 250,000 cubic metres of LNG and is rated for a 50-year design life.

Boil-off gas (BOG) is the unavoidable consequence of heat ingress through the tank insulation — even with perlite at the design heat-leak rate, approximately 0.05 to 0.10 percent of the tank inventory boils off per day as methane vapour. This BOG is captured and either re-liquefied (return to the train) or compressed for delivery as fuel to a power plant or marine bunker. The BOG compressor enclosure is a Zone 2 ventilated building with 12 ACH normal and 30 ACH emergency on hydrocarbon LEL detection. The tank instrument room (the small building adjacent to each tank housing the level instruments, pressure controllers and the tank automation system) is pressurised under AS/NZS 60079.4 to maintain non-hazardous classification adjacent to Zone 2.

Duct material around the tank and the BOG compressor is 316L stainless throughout because of combined coastal chloride and hydrocarbon vapour. The instrument room is fed through a high-level outside-air intake on the side furthest from the tank vent and the relief valve discharge stack.

LNG truck loading and marine berth — Zone 1 vapour handling

LNG export terminals load product into:

• LNG carriers at the marine berth jetty — the dominant export route. A typical Q-Max or Q-Flex carrier loads 210,000 to 266,000 cubic metres of LNG in about 24 hours from the storage tank through the manifold and the loading arms.
• LNG trucks and rail tankers at the loading rack for domestic LNG fuel distribution — a much smaller volume but still a significant Zone 1 envelope.

Both loading operations are Zone 1 under AS/NZS 60079.10.1. The marine berth control building, the loading rack operator shelter and any adjacent equipment shelter is pressurised under AS/NZS 60079.4 to maintain non-hazardous classification. The HVAC outside-air intake is located on the side opposite the manifold, at the highest practical elevation, with hydrocarbon and oxygen detection in the intake stream. On hydrocarbon detection at 20 percent LEL or oxygen depletion below 19.5 percent the intake closes and the building runs on internal recirculation.

Acid gas removal (AGR) — amine MDEA scrubbing and HVAC

Raw natural gas from offshore Australian fields typically contains 0.5 to 8 percent CO2 and varying amounts of H2S (sour gas) — both of which must be removed before liquefaction because CO2 freezes at LNG temperature and H2S is corrosive and toxic. The standard removal technology is amine absorption, with MDEA (methyldiethanolamine) the dominant amine in modern LNG plants because of its selectivity for H2S over CO2 and its lower regeneration energy.

The AGR unit is a vertical tower stack — the absorber column where lean amine contacts sour gas and removes CO2 and H2S, the regenerator column where rich amine is heated to release the acid gases for routing to sulphur recovery, and the heat-exchanger train that recovers heat between the streams. The building envelope around the AGR is typically:

• Absorber building. Zone 2 at the column boundary. 8 to 12 ACH normal, 30 ACH emergency on H2S at 10 ppm or hydrocarbon at 20 percent LEL.
• Regenerator building. Zone 1 at the regenerator overhead where wet acid gas at high temperature is most likely to leak; Zone 2 elsewhere. 15 ACH normal, 30 ACH emergency. Localised Inconel 625 cladding on extract sections near the regenerator overhead.
• Amine sump and storage area. AS 3780 corrosive substance storage (MDEA is a mild base but not classified Class 8 itself — the corrosive classification is for the rich-amine acid loading). 6 ACH normal, 25 ACH on H2S detection.

The HVAC duct material is 316L stainless throughout, with localised Inconel 625 cladding at the high-acid-gas extract nodes — the cladding is procured from specialist alloy fabricators that work alongside the SBKJ-equipped 316L shop. MDEA itself is moderately corrosive to zinc but compatible with 316L over the operating life.

Sulphur recovery unit (SRU) — Claus process HVAC

The acid gas removed from the natural gas stream by the AGR is routed to the sulphur recovery unit, where the H2S is converted to elemental sulphur by the Claus process — thermal stage at approximately 1100°C, followed by two or three catalytic stages at progressively lower temperature. The tail gas is either incinerated and vented through a stack with SO2 monitoring, or routed to a tail gas treatment unit (TGTU) for additional sulphur recovery before final venting.

The SRU building envelope is the highest-aggressive-chemistry envelope on an LNG or gas processing site. The HVAC scope includes:

• SRU furnace and reactor area. Zone 2. 15 to 20 ACH normal, 30 ACH emergency on H2S, SO2, or hydrocarbon detection. 316L stainless with localised Inconel 625 cladding on extract sections near the furnace skin and the catalytic reactor manholes. Hot-air supply needed in winter to keep the building above the sulphur dew point and prevent condensation of H2SO4 from SO2 in moist air.
• Sulphur storage and handling. Solid sulphur prills and pastilles in storage shed (sulphur dust hazard — AS/NZS 60079.10.2 Zone 22). 8 to 12 ACH normal, 25 ACH emergency. 316L stainless, anti-static internal lining, continuous earthing.
• Molten sulphur transfer. Where the SRU runs in molten sulphur mode (typical for large LNG sites), the molten sulphur transfer pit and the rail-load-out area is Zone 2 with elevated SO2 and residual H2S exposure. 316L stainless with localised Inconel cladding.
• Tail gas incinerator stack. 316L stainless with external lagging to prevent condensation. CEMS for SO2 monitoring under MARPOL and state air quality regulations.

The Safe Work Australia workplace exposure standards for the SRU area are H2S 10 ppm TWA / 15 ppm STEL (extremely toxic), SO2 2 ppm, sulphur dust 5 mg/m³. The HVAC design has to keep continuous exposure below these levels and trigger emergency-mode extract on detection.

Dehydration and mercury removal — TEG and activated carbon

After acid gas removal the gas stream still contains water and trace mercury. Water must be removed because it freezes at LNG temperature and forms hydrates that plug heat exchanger tubes. Mercury must be removed because even trace mercury (sub-ppb) embrittles aluminium in the cryogenic heat exchanger and causes catastrophic failure.

The dehydration unit uses either triethylene glycol (TEG) absorption or molecular sieve adsorption. The TEG contactor is a vertical column where wet gas contacts lean TEG, transferring water to the glycol; the rich glycol is regenerated in a reboiler that drives water off and recycles the lean glycol. The HVAC scope for a TEG unit is similar to the amine AGR scope but with lower acid loading — 316L stainless throughout, no Inconel cladding required because TEG is benign.

The mercury removal unit (MRU) uses sulphur-impregnated activated carbon as the adsorbent — the sulphur reacts with mercury to form mercuric sulphide, which is captured on the carbon and disposed as hazardous waste at end of bed life. The HVAC scope for the MRU is:

• MRU vessel area. Zone 2. 8 to 12 ACH normal, 25 ACH emergency on mercury detection above 0.025 mg/m³ (the Safe Work Australia workplace exposure standard for mercury vapour) or hydrocarbon LEL.
• Spent carbon handling. The spent carbon is mercury-contaminated and is handled as hazardous waste. The carbon change-out building is a Zone 22 dust envelope with elevated mercury detection. 316L stainless throughout.

Refinery process units — distillation, FCC, hydrocracker, reformer, alkylation, hydrogen plant

The two remaining Australian refineries — Viva Energy Geelong and Ampol Lytton — operate the standard refinery unit stack:

Atmospheric and vacuum distillation

The crude is heated in the atmospheric distillation column to about 350°C and separated into LPG, naphtha, kerosene, diesel and atmospheric residue. The residue goes to the vacuum distillation column for further separation into vacuum gas oil and vacuum residue. The HVAC scope around the distillation columns is Zone 2 — heavy hydrocarbon vapour exposure at the column shelves, pump bays and instrument shelters. 316L stainless throughout. 8 to 12 ACH normal, 30 ACH emergency on hydrocarbon LEL.

Fluid catalytic cracker (FCC)

The FCC cracks heavy gas oils into lighter products (LPG, gasoline, light cycle oil) using a fluidised catalyst at high temperature. The catalyst regenerator burns off coke deposits at approximately 730°C and produces a hot flue gas stream that drives a power-recovery turbine before being routed through the CO boiler and the flue gas stack. The HVAC scope around the FCC building is dominated by heat — supply air at high volumes to keep the equipment shelter cool, with 316L stainless on the extract because of intermittent fugitive hydrocarbon and CO exposure (Safe Work Australia CO 30 ppm TWA).

Hydrocracker

The hydrocracker uses hydrogen at high pressure (typically 100 to 200 bar) and elevated temperature (350 to 420°C) over a catalyst to crack heavy molecules into lighter products. The unit operates with significant hydrogen inventory and the building envelope is Zone 2 with the cracker reactor manhole vicinity Zone 1. HVAC scope is 316L stainless with elevated air-change rate (15 ACH normal, 30 ACH emergency on hydrogen at 20 percent LEL).

Catalytic reformer

The reformer converts naphtha into high-octane reformate and produces hydrogen as a co-product. The unit operates at elevated temperature and the reactor furnace is a significant fire-hazard envelope. HVAC scope is Zone 2 around the reactor and Zone 1 at the regenerator vent points.

Alkylation

Alkylation combines isobutane with light olefins to produce a high-octane gasoline component. The Australian refineries use sulphuric acid catalysis; HF alkylation has been used historically at some Australian sites but is being phased out globally because of the HF toxicity hazard. The sulphuric acid alkylation unit has a building envelope with elevated acid mist exposure — 316L stainless throughout with localised Inconel 625 cladding on the hot acid settler extract. Sulphuric acid mist exposure is limited under the Safe Work Australia standard to 1 mg/m³ (sulphuric acid mist).

Hydrogen plant — steam methane reformer

The hydrogen plant generates the hydrogen required by the hydrocracker, the hydrotreater and the desulphurisation units. The dominant technology is steam methane reforming (SMR), in which methane reacts with steam over a nickel catalyst at high temperature to produce hydrogen, carbon monoxide and CO2. The HVAC scope is Zone 2 throughout with Zone 1 at the SMR reactor vent and the PSA tail gas vent. CO detection at the Safe Work Australia 30 ppm TWA exposure standard triggers emergency mode. 316L stainless throughout because of the combined H2, CO and the elevated temperature of the local environment. Cross-reference the hydrogen production, electrolyser, ammonia and H2 refuelling HVAC duct guide for the broader hydrogen-handling HVAC envelope including renewable hydrogen production.

Tank farm — Zone 1 and Zone 2 with vapour return

The crude oil and product tank farm at a refinery or LNG site is a network of atmospheric storage tanks under API 650. Floating roof tanks (internal or external) minimise vapour emission and reduce the size of the hazardous-area envelope around each tank; fixed roof tanks have a more extensive Zone 2 envelope. The vapour return system collects vapour from tank breathing and from loading-and-unloading operations and routes it back to a vapour recovery unit (VRU) or to the flare header.

The HVAC scope in the tank farm is limited to the operator shelters, the sample shelter and the fire-water pumphouse — each of which is a pressurised non-hazardous enclosure under AS/NZS 60079.4 with 316L stainless duct on the outside-air run. The tank farm itself does not have a building envelope but the pump bays and the manifold sheds along the tank farm boundary do, and each one is Zone 2 with 316L stainless extract.

Pump house and compressor station — Zone 1 and Zone 2 with spark-resistant fans

The pump house and compressor station scope at a gas processing or LNG site is dominated by the rotating equipment — process pumps, reciprocating compressors, centrifugal compressors and turbo-expanders. The building envelope is Zone 2 by AS/NZS 60079.10.1 dilution-ventilation classification (where continuous mechanical ventilation maintains the area below the hydrocarbon flammability threshold). If ventilation is lost the area reverts to Zone 1 and the electrical equipment must be rated accordingly.

The HVAC scope is:

• Compressor enclosure ventilation. 12 ACH minimum continuously to maintain Zone 2 classification under the AS/NZS 60079.10.1 dilution-ventilation provision. 30 ACH on hydrocarbon at 20 percent LEL or oxygen depletion below 19.5 percent.
• Spark-resistant fans. AMCA 99 Type B or Type C. Aluminium-bronze or stainless impeller. Anti-static drive belts.
• IECEx Ex-d or Ex-e motors. Zone 1 or Zone 2 rated. Sealed bearings, anti-static drive train, Ex e or Ex d enclosure on the terminal box.
• 316L stainless duct. With continuity-tested earthing across every joint and bonding straps across flexible connectors and damper spindles.

Control room, substation, MCC and field equipment shelter — pressurisation

The non-hazardous islands inside an otherwise-hazardous plant are the control room, the substation, the motor control centre (MCC) and the various field equipment shelters that house analysers, telemetry, instrument power supplies and operator equipment. These buildings are pressurised under AS/NZS 60079.4 (Equipment protection by pressurised enclosure "p") or the equivalent NFPA 496 Class I Division 2 framework to maintain non-hazardous classification adjacent to the surrounding Zone 2 envelope.

The pressurisation design is:

• Positive pressure 50 to 75 Pa above the surrounding hazardous area, maintained by mechanical ventilation with redundant supply fans.
• High-level outside-air intake on the side of the building furthest from any credible release source, with hydrocarbon and H2S detection in the intake stream.
• Intake damper isolation on hydrocarbon detection at 20 percent LEL or H2S at 10 ppm. The building reverts to internal recirculation only until the alarm clears.
• Gas-tight building envelope — walls, ceiling, doors, cable transits and HVAC duct penetrations all sealed to the pressurisation criterion. Door interlocks ensure that only one door is open at a time.
• Blast-rated wall and roof construction per API RP 752 where the building is within the consequence envelope of a credible release. HVAC penetrations through the blast wall use blast-rated dampers and AS 1530.4 fire-rated seals.

The duct material is 316L stainless on the outside-air run and galvanised on the internal recirculation run (the recirculation air is benign indoor air). The supply fan and the exhaust fan are non-spark-resistant general-purpose units because they are inside the pressurised envelope — the spark-resistance and IECEx rating apply only to the equipment outside the pressurised envelope.

Helideck — Zone 1 fuelling envelope

Offshore platforms and FPSO/FLNG facilities have a helideck for crew and freight access. The helideck fuelling envelope is Zone 1 within 3 metres of the fuelling point and Zone 2 to 15 metres under API RP 14J. HVAC intakes on the platform topsides must be located on the opposite side of the platform from the helideck, at the highest practical elevation, with hydrocarbon detection in the intake stream.

Accommodation module — A-60 fire wall and fresh-air HVAC

The accommodation module on an offshore platform houses the crew quarters, the galley, the mess, the conference and recreation spaces and the control room. The module is separated from the process area by an A-60 rated fire wall — a wall capable of withstanding a hydrocarbon fire for 60 minutes without exceeding the temperature rise limit on the protected side. The HVAC penetrations through the A-60 wall use certified fire-rated dampers and intumescent seals, and the accommodation module HVAC system is fed from a fresh-air intake on the far side of the module from any credible release source.

The accommodation module HVAC is otherwise a standard commercial-grade system — supply at approximately 8 to 10 L/s/person fresh air, recirculation for energy efficiency, room-by-room temperature and humidity control. The duct material on the outside-air run is 316L stainless because of the marine atmosphere; the internal recirculation duct is galvanised.

Laboratory and on-line analyser — fume extraction and sample handling

The laboratory and the on-line analyser shelters on an LNG, gas processing or refining site are local-extract environments. The lab handles BTU calorimetric analysis, gas chromatography, sulphur content analysis and water dewpoint measurement. The fume hoods over the sample preparation benches are stainless-lined and extracted at the AS 1668.2 lab-fume-hood rate. The analyser shelters house the on-line GC and the moisture analyser; they are Zone 2 envelopes pressurised under AS/NZS 60079.4 with fresh-air intake from a non-hazardous side.

Workshop and maintenance — fume capture and welding extraction

The workshop and maintenance building on an LNG or refinery site handles rotating equipment overhaul, welding fabrication of replacement parts, hot work in controlled conditions and a portfolio of mechanical activities. The HVAC scope is:

• General workshop ventilation at 4 to 8 ACH for occupant comfort and dilution.
• Welding fume extraction at the work-station — articulated extract arms with HEPA-grade filtration and outdoor discharge.
• Spray paint booth extraction where present — AS 1668.2 paint booth rate and explosion-proof fan if solvent paints are used.

The duct material is 316L stainless on the local extract because of the salt environment and galvanised on the general supply.

Office, admin and amenity — non-hazardous, segregated

The office, admin and amenity buildings on an LNG or refinery site are physically segregated from the process areas and are non-hazardous. The HVAC scope is commercial-grade — supply at the AS 1668.2 occupancy rate, packaged DX or chilled-water cooling, room-by-room thermostat control. The duct material is 316L stainless on the outside-air run (coastal salt) and galvanised inside the building.

Flare stack and process emissions stack — radiant heat and CEMS

The flare stack is the primary safety device of an LNG, gas processing or refining site — every relief stream and every emergency vent ultimately discharges to the flare for safe combustion. The flare itself does not have an HVAC envelope, but the radiant heat generated by the flare during a major upset can affect buildings nearby — the HVAC design must accommodate the credible thermal load on the building envelope from the flare radiant zone and ensure the HVAC intake does not draw in flue gas from the flare under any operating condition.

The process emissions stacks — the SRU tail gas stack, the FCC flue gas stack, the SMR flue gas stack, the reformer reactor stack and the CEMS monitoring stacks for state air quality compliance — are 316L stainless construction with external lagging to prevent condensation and corrosion of the stack interior. The CEMS sample lines are heated 316L stainless tube traced to maintain the sample above its acid dew point.

Worked example — Pluto LNG Train 2 process building scope

To make the design discussion concrete, here is a notional summary of the HVAC envelope on a single LNG train building scope at the Pluto LNG site near Karratha, sized at approximately 5 million tonnes per annum of LNG. The site is on the Burrup Peninsula in the Pilbara, in ISO 9223 C5-M industrial-marine corrosivity, with combined salt-aerosol, hydrocarbon-vapour and intermittent sour-gas exposure. The building scope:

• Cold box building. Zone 2 throughout. 12 ACH normal, 30 ACH emergency on hydrocarbon LEL or oxygen depletion. 316L stainless throughout with stainless NC-55 attenuators. Spark-resistant fans, IECEx Ex-d motors. Approximately 280 metres of 316L stainless duct.
• BOG compressor enclosure. Zone 2. 12 ACH normal, 30 ACH emergency. 316L stainless. Approximately 90 metres of duct.
• Amine regeneration building. Zone 1 at the regenerator overhead, Zone 2 elsewhere. 15 ACH normal, 30 ACH emergency on H2S at 10 ppm or hydrocarbon LEL. 316L stainless with localised Inconel 625 cladding at the regenerator overhead extract. Approximately 150 metres of 316L plus 20 metres of Inconel cladding.
• SRU enclosure. Zone 2. 18 ACH normal, 30 ACH emergency. 316L stainless with localised Inconel cladding on the furnace and reactor extract. Approximately 200 metres of 316L plus 30 metres of Inconel.
• Sulphur storage and prilling. Zone 22 dust envelope. 10 ACH normal, 25 ACH emergency. 316L stainless with anti-static internal lining and continuous earthing. Approximately 120 metres.
• Dehydration TEG building. Zone 2. 12 ACH normal, 30 ACH emergency. 316L stainless. Approximately 100 metres.
• Mercury removal unit. Zone 2. 10 ACH normal, 25 ACH emergency on mercury or hydrocarbon LEL. 316L stainless. Approximately 60 metres.
• Central control room. Pressurised non-hazardous, blast-rated. 75 Pa positive pressure. Outside-air intake on the side furthest from the process. 316L stainless on the outside-air run, galvanised on the recirculation. Approximately 80 metres total.
• Substation and MCC. Pressurised non-hazardous. 50 Pa positive pressure. 316L outside-air, galvanised internal. Approximately 60 metres each.
• Field analyser shelters. Five shelters, each pressurised non-hazardous, 50 Pa positive pressure. 316L outside-air. Approximately 25 metres each.
• Laboratory. Pressurised. Fume hood local extract at AS 1668.2 rate. 316L stainless on local extract, galvanised general supply. Approximately 70 metres.
• Workshop. Non-hazardous, segregated. General ventilation plus welding fume extract. 316L outside-air, galvanised inside. Approximately 90 metres.
• Admin and amenity. Non-hazardous, segregated. Commercial-grade HVAC. 316L outside-air, galvanised internal. Approximately 80 metres.

Total scope is approximately 1,800 metres of 316L stainless duct, 50 metres of Inconel 625 clad sections (specialist sub-contract), and 250 metres of galvanised duct in segregated non-hazardous spaces. The SBKJ machine line for this scope is the SBAL-V stainless auto duct line, the SB-ZF1500 automatic stitchwelder for longitudinal seam closure, the SBSF-1525 hydraulic flanging machine for round-duct flanges, the SBPC1500 plasma cutter for 316L plate cutting and the SBLR-600 for the accommodation-style aluminium flexible duct in the analyser shelters and the control room recirculation system. The Inconel 625 cladding is sub-contracted to a specialist alloy fabricator. Total shop fabrication is approximately 14 weeks single-shift.

Worked example — Viva Energy Geelong refinery FCC and alkylation upgrade

The second worked example is the refinery side — a notional HVAC scope refresh on the FCC and the alkylation unit at the Viva Energy Geelong refinery. The site is on Corio Bay in Geelong, in ISO 9223 C5-M industrial-marine, with combined salt and hydrocarbon exposure. The scope:

• FCC reactor and regenerator structure. Open structure, no enclosed building envelope. HVAC scope is limited to the equipment shelter at the base.
• FCC catalyst handling building. Zone 22 dust envelope at the fresh catalyst hopper and the equilibrium catalyst handling. 8 ACH normal, 25 ACH on dust detection. 316L stainless with anti-static lining.
• FCC operator shelter. Pressurised non-hazardous, 50 Pa. 316L outside-air. Approximately 40 metres.
• Sulphuric acid alkylation unit. Zone 2 around the acid settler and reactor area. 12 ACH normal, 30 ACH emergency on hydrocarbon LEL or sulphuric acid mist detection. 316L stainless with localised Inconel 625 cladding on the hot acid settler extract. Approximately 110 metres of 316L plus 15 metres of Inconel.
• Spent acid handling. AS 3780 corrosive substance storage. Zone 2 in the wet acid mist zone. 8 ACH normal, 25 ACH on acid mist. 316L stainless. Approximately 50 metres.
• Alkylation operator shelter. Pressurised non-hazardous. 316L outside-air. Approximately 35 metres.

Total scope is approximately 235 metres of 316L stainless duct, 15 metres of Inconel 625 clad sections (specialist sub-contract), and 75 metres of galvanised duct in segregated non-hazardous spaces. SBKJ machine line is the same as the Pluto example. Total shop fabrication is approximately 6 weeks single-shift.

Worked example — Bass Strait offshore platform topsides HVAC

The third worked example is a Bass Strait offshore platform topsides HVAC refresh, modelled loosely on a Gippsland Basin fixed platform. The platform sits in the open ocean off the Victorian coast in ISO 9223 CX corrosivity (tropical/extreme marine) with continuous salt-aerosol exposure and extensive Zone 1 and Zone 2 envelopes around the process modules. The scope:

• Process module ventilation. Zone 2 throughout. 12 ACH normal continuously to maintain Zone 2 classification under AS/NZS 60079.10.1. 316L stainless with fully welded joints throughout. Approximately 320 metres.
• Wellhead area ventilation. Zone 1 within the wellhead envelope. Mechanical extract only with the supply through open louvres. 316L stainless. Approximately 80 metres.
• Accommodation module. Non-hazardous, A-60 fire wall to process. Fresh-air HVAC at 8 to 10 L/s/person. 316L on outside-air run, galvanised on internal recirculation. Approximately 240 metres total.
• Helideck operator shelter. Zone 2 perimeter, non-hazardous interior pressurised. 316L outside-air. Approximately 30 metres.
• Central control room. Non-hazardous, pressurised, blast-rated where applicable. 316L outside-air. Approximately 60 metres.
• Switchgear and MCC. Pressurised non-hazardous. 316L outside-air, galvanised inside. Approximately 50 metres each.
• Workshop and store. Non-hazardous in segregated area. 316L outside-air, galvanised inside. Approximately 70 metres.

Total scope is approximately 950 metres of 316L stainless duct (fully welded throughout) and 360 metres of galvanised duct in the segregated non-hazardous interior spaces. SBKJ machine line is the SBAL-V stainless auto duct line with the SB-ZF1500 stitchwelder configured for fully welded round and rectangular sections. All flanges are minimised in favour of welded butt joints because the offshore service does not tolerate flange leakage. Total shop fabrication is approximately 10 weeks single-shift, with offshore installation by a specialist marine contractor.

SBKJ machine configuration for hydrocarbon-industry ductwork

Fabricating hydrocarbon-industry ductwork at the scale required by Australian LNG, gas processing, refining and offshore projects — typically 1,000 to 2,500 metres of run per process building, with 50 to 90 percent of joints fully welded — requires the right shop equipment. The SBKJ standard machine configuration for hydrocarbon-industry fabrication shops is:

• SBAL-V stainless 316L auto duct line. The SBAL-V is the stainless variant of the SBAL auto duct line, configured with 316L-compatible tooling, full TIG-welded longitudinal seam closure and a coil de-coiler and leveller sized for 316L sheet stock at 1.2 mm to 2.0 mm thickness up to 1500 mm wide. The line produces rectangular duct sections at TDF or PB flange standard with consistent dimensional tolerances meeting AS/NZS 4254 and SMACNA. For LNG and refining projects the SBAL-V is typically configured with a stainless plasma cutter for the slot-and-tab transverse joint and a notch-and-bend station for the TDF flange profile. Cross-reference the SBAL-V product page for full specification.
• SB-ZF1500 automatic stitchwelder. The SB-ZF1500 is SBKJ's automatic longitudinal seam stitchwelder, the critical machine for hazardous-area duct welding because it produces consistent TIG seam welds at production speed with documented weld procedure specifications. For LNG and offshore service every longitudinal seam is closed on the SB-ZF1500 to AS/NZS 1554.6 with 316L filler. The SB-ZF1500 is also configured for sour-service welding with controlled heat input to minimise sensitisation in the heat-affected zone.
• SBSF-1525 hydraulic flanging machine. The SBSF-1525 produces 316L stainless round-duct flanges for the round-duct sections of the process extract and supply system. The flange is formed by hydraulic press to a consistent dimensional standard and welded to the duct on the SB-ZF1500.
• SBPC1500 plasma cutter. The SBPC1500 is the plasma cutter for 316L plate cutting at cleanroom-grade dimensional tolerance. The plasma cut is used for cutting blanks, openings, branch connections and dimensional details that are not produced on the SBAL-V auto duct line.
• SBLR-600 / SBLR-600A aluminium flexible duct forming machine. The SBLR-600 produces aluminium flexible ducts used for accommodation module connections, recirculation system flexibles in the control room and ductwork details where rigid duct cannot be installed. The SBLR-600A is the three-section variant for higher production rate.
• Spark-resistant fans and IECEx motor sourcing. SBKJ does not directly manufacture spark-resistant fans or IECEx motors — these are sourced from specialist suppliers (typically Howden, Greenheck, COFIMCO, ABB or SEW Eurodrive for the motor side) and packaged with the SBKJ-fabricated duct as part of the project deliverable. For LNG and offshore service the fan is AMCA 99 Type B or Type C with the IECEx Ex-d or Ex-e motor matched to the zone.
• Specialist alloy sub-contract for Inconel 625, Monel and Hastelloy. Where the duct scope includes severe sour-service or high-temperature acid-gas sections requiring Inconel, Monel or Hastelloy cladding, SBKJ sub-contracts the cladding fabrication to a specialist alloy fabricator while retaining responsibility for the overall scope, integration and documentation.
• AS/NZS 60079, ATEX and IECEx fabrication-shop option. Where the fabrication shop itself is classified as a Zone 22 dust-handling area (because of stainless-steel grinding swarf), the SBKJ machine line is configured with hazardous-area-rated electrical components, anti-static drive belts and bonded earthing throughout. This is the right shop configuration for fabrication shops that operate inside an existing chemical or hydrocarbon site footprint.

Cross-reference the SBKJ machine catalogue for full specification, output and certification details, and the 47-point HVAC duct machine buyer's checklist for the procurement verification questions to ask any vendor.

Project sequencing and lead time

Hydrocarbon-industry HVAC projects sit on long lead times because of the metallurgy, the certification stack and the project documentation burden. A representative schedule for a single LNG train HVAC scope from design freeze to first article fabricated is:

• Weeks 1 to 6 — Design and hazard freeze. Hazardous-area classification drawing signed off, dangerous-goods register complete, NFPA 59A and API RP 752 references applied, AS/NZS code applicability matrix complete, single-line ventilation drawing signed off, Safety Case bow-tie linkage documented.
• Weeks 6 to 12 — Procurement and material lead. 316L stainless sheet stock ordered to project schedule (lead time 6 to 12 weeks from mill for project tonnages), Inconel 625 and Monel ordered (lead time 16 to 26 weeks from specialist mill), IECEx fan-and-damper package ordered (lead time 14 to 22 weeks from specialist supplier).
• Weeks 12 to 24 — Fabrication. SBAL-V stainless auto duct line single-shift output is approximately 2,500 m² of duct per week at hydrocarbon-grade thickness; a 5 million tonne per annum LNG train HVAC scope (approximately 1,800 metres of 316L) fabricates in roughly 12 to 14 weeks of shop time. Quality records (welder qualifications, weld procedure specifications, root and visual inspection records, mill certificates) are compiled in parallel.
• Weeks 24 to 30 — Shipment and site delivery. 316L stainless duct shipped flat-packed for site assembly; pre-fabricated welded sections shipped in protective crating with ISPM-15 fumigation stamp and humidity indicators. Offshore scope crated for marine transport and barge transfer.
• Weeks 30 to 42 — Site assembly, hazardous-area continuity testing, gas-detection commissioning, cause-and-effect matrix witness testing.
• Weeks 42 to 50 — Documentation hand-over to the operator EHS and regulatory audit.

The single most common schedule risk is under-ordering the IECEx fan-and-damper package and the Inconel 625 cladding — the specialist suppliers have 14 to 26 week lead times and stockholding is thin for the larger sizes. Ordering these items on day one of the project, in parallel with the duct, is the discipline that keeps the schedule from slipping at week 20.

Cost envelope — 316L stainless and superalloy pricing

A representative cost envelope for hydrocarbon-industry ductwork in 2026 prices (Australian dollars, ex-works fabrication shop, before site installation and commissioning):

• Galvanised steel duct — AUD 70 to AUD 120 per square metre installed, for non-hazardous office, amenity and warehouse areas physically segregated from process.
• 316L stainless duct, TIG-welded, mill-finished — AUD 380 to AUD 620 per square metre installed, for general LNG, refining and offshore service.
• 316L stainless duct, TIG-welded, electropolished or passivated — AUD 480 to AUD 780 per square metre installed, for severe-service sections.
• Inconel 625 clad duct — AUD 2,400 to AUD 4,800 per square metre installed, for severe sour-service and high-temperature acid gas sections. Specialist sub-contract.
• Monel 400 clad duct — AUD 2,800 to AUD 5,200 per square metre installed, for HF and high-acid service. Specialist sub-contract.
• Hastelloy C-276 clad duct — AUD 2,000 to AUD 3,600 per square metre installed, for chlorinated solvent and halogen-acid service. Specialist sub-contract.
• Spark-resistant fan with IECEx Ex-d motor — AUD 18,000 to AUD 65,000 per unit depending on size and zone, sourced through SBKJ from a specialist supplier.
• IECEx Zone 1/2 damper actuator — AUD 2,800 to AUD 9,500 per unit depending on size and torque, sourced through SBKJ from a specialist supplier.

The cost case for designing the network bay-by-bay rather than blanketing the whole project in one alloy is straightforward — the difference between specifying Inconel 625 throughout a 1,800 m² duct envelope (AUD 4.3 million to AUD 8.6 million) and specifying 316L for 90 percent and Inconel for 10 percent (AUD 1.0 million to AUD 1.7 million combined) is roughly AUD 3 to AUD 6 million of saved capital at no compromise in performance.

Documentation and audit pack

Every hydrocarbon-industry HVAC project hands over a documentation pack that goes into the site EHS document control system and feeds into the next NOPSEMA or Major Hazard Facility regulatory audit. The pack contents are:

• Hazardous-area classification drawings (AS/NZS 60079.10.1 and 10.2) signed by the responsible engineer.
• As-built single-line and isometric drawings of the duct network.
• Weld procedure specifications and welder qualification records for every TIG-welded joint under AS/NZS 1554.6 (and ASME Section IX where parent-company alignment requires it).
• Mill certificates for 316L stainless sheet stock, traceable by heat number to each fabricated section.
• Specialist alloy mill certificates for Inconel 625, Monel and Hastelloy clad sections.
• IECEx certificates for every fan, damper actuator, gas detector, motor and electrical accessory inside a hazardous zone.
• AMCA 99 spark-resistant fan documentation.
• Continuity-test records for every duct joint inside a hazardous zone, showing earth resistance below the Safety Case-defined limit (typically 1 Ω).
• Pressure-test records to AS 4254 leakage class C or the project-specified class.
• Cause-and-effect matrix for the gas-detection system showing normal-to-emergency mode transitions.
• Witness-test records for the emergency-mode air-change rate against a simulated gas-detector trip.
• Fire-rated penetration certificates under AS 1530.4.
• Fire damper inspection schedules under AS 1851.
• Operating and maintenance manuals in English including spare-parts lists, lubrication schedules and inspection intervals under AS/NZS 60079.17.
• Cross-references to the operator's Major Hazard Facility Safety Case (onshore) or OPGGS Safety Case (offshore) showing where the ductwork is named as a layer of protection in bow-tie analyses.
• For offshore — additional documentation for IMO MARPOL air pollution compliance and the platform Safety Analysis Function Evaluation chart under API RP 14C.

SBKJ supplies the as-built, weld and material documentation for the SBKJ scope; the IECEx, hazardous-area classification and Safety Case integration documents are supplied by the principal designer or the site EHS team. The interface is defined at project award and walked through at the project pre-start meeting.

Industry bodies and the Australian engagement map

The Australian hydrocarbon industry is represented by a network of industry bodies that publish guidance, set standards and engage with the regulator on behalf of operators. Engagement with these bodies is part of the long-term commercial development for any fabricator or supplier into the sector:

• APPEA — Australian Petroleum Production and Exploration Association. The peak body for the upstream oil and gas industry in Australia. APPEA hosts an annual conference that is the primary networking and policy forum for the sector.
• Australian Energy Council (AEC). The peak body covering the gas-and-electricity downstream — particularly the gas distribution and gas retail side.
• Australian Pipelines and Gas Association (APGA). The peak body for transmission pipeline operators and the gas pipeline construction industry. APGA standards reference AS 2885 (Pipelines — Gas and Liquid Petroleum) which connects pipeline design to facility design.
• NOPSEMA — National Offshore Petroleum Safety and Environmental Management Authority. The regulator for Australian offshore petroleum operations. NOPSEMA publishes guidance on facility Safety Case and Environment Plan content that informs offshore HVAC scope.
• AMOSC — Australian Marine Oil Spill Centre. The industry-funded oil spill response co-operative; not directly relevant to HVAC scope but part of the offshore-operations ecosystem.

EPC contractor base and the Australian project pipeline

The EPC contractor base for Australian LNG, gas processing and refining is a small group of internationally-experienced firms with established Australian operations:

• Worley (ASX:WOR) — Brisbane and Perth offices, the largest Australian LNG EPC firm and a global engineering services provider.
• Bechtel Australia — built three of the four Curtis Island LNG trains; significant Australian footprint.
• Fluor Australia — LNG and downstream EPC.
• McDermott Australia — offshore engineering and EPC including FLNG.
• KBR Australia — engineering services across LNG, refining and petrochemical.
• Saipem Australia — offshore installation and subsea engineering.
• Monadelphous (ASX:MND) — mining and LNG construction services with significant Pilbara presence.
• John Holland — civil and process construction with CIMIC group resources.
• Civmec (ASX:CVL) — heavy fabrication and construction services with a major Henderson WA yard.

SBKJ engages with this EPC base through the partner fabricators in the Perth, Karratha, Darwin, Gladstone, Brisbane, Melbourne and Geelong corridors that operate SBKJ equipment, and through direct engineering pre-construction support to consulting engineers and project teams.

How SBKJ supports Australian LNG, gas and refining projects

SBKJ Group has supplied HVAC duct fabrication equipment to LNG, gas processing, refining, petrochemical and offshore projects across 100+ countries since 1995. The Australian footprint runs through the SBKJ office in Box Hill North VIC for English-speaking after-sales, project engineering and spare-parts support, and through the Australia Ducting Pty Ltd presence as the local trade-show face at events including ARBS 2026. For hydrocarbon-industry projects we typically engage at one of three project phases:

• Design support. Pre-construction review of the duct material, joint, fan and damper scope against AS/NZS, NFPA, API and ISO references — usually as an unpaid courtesy to architects and consulting engineers who are sizing the fabrication-shop footprint.
• Shop equipment supply. Supply of the SBAL-V stainless auto duct line, SB-ZF1500 automatic stitchwelder, SBSF-1525 hydraulic flanging machine, SBPC1500 plasma cutter, SBLR-600 aluminium flexible duct forming machine and ancillary handling equipment to a buyer fabricating duct in their own shop. Lead time 18 to 26 weeks; on-site commissioning by SBKJ engineers from the Box Hill North office.
• Toll fabrication via partners. For projects where the buyer prefers to procure duct directly rather than fabricate in-house, SBKJ partners with Australian fabrication shops that operate SBKJ equipment in the Perth, Henderson, Karratha, Darwin, Gladstone, Brisbane, Melbourne and Geelong areas.

Cross-reference the why choose SBKJ summary, the SBKJ machine catalogue, the SBAL-V product page, the pricing and lead time guide and the 47-point HVAC duct machine buyer's checklist. For related industry guides see the specialty chemicals, petrochemical, agrochemical and industrial gas HVAC duct guide, the hydrogen production, electrolyser, ammonia and H2 refuelling HVAC duct guide, the coal and gas power plant HVAC duct guide and the container port, cargo terminal, stevedore and ferry HVAC duct guide for the marine logistics side of the LNG export supply chain.

Get an LNG-grade HVAC duct quote from SBKJ →

FAQ

What ductwork material is required for an Australian LNG export terminal?

316L stainless steel is the default specification across an Australian LNG export terminal because every building sits in either a hazardous area with sour-gas or hydrocarbon exposure, a coastal ISO 9223 C5-M chloride-aerosol envelope, or both. Galvanised duct fails inside two summers at any Karratha, Onslow, Barrow Island, Darwin or Curtis Island site because of combined salt and hydrocarbon attack on the zinc coating. For severe sour-gas service — amine acid-gas removal units, sulphur recovery units, acid gas injection — Inconel 625 or Monel cladding is specified by ISO 15156 NACE MR0175 and is procured from specialist alloy fabricators outside the SBKJ scope. The SBAL-V stainless auto duct line and the SB-ZF1500 stitchwelder are the SBKJ machine configuration used to fabricate the 316L rectangular and round duct envelope around these process islands.

What hazardous-area zone classification applies inside an LNG plant?

AS/NZS 60079.10.1 applies to gaseous flammable atmospheres throughout an LNG plant. The liquefaction train cold box, the boil-off-gas compressor enclosure, the truck loading rack vapour zone, the marine berth manifold and the flare knock-out drum are Zone 1 in normal operation. Most of the process unit including pump bays, valve manifolds and the perimeter of buildings adjacent to live equipment is Zone 2. The interior of a fully welded pipe is technically Zone 0 but is not a ventilation envelope. Control rooms, substations and motor control centres are non-hazardous by design provided they are pressurised under AS/NZS 60079.4 (purged and pressurised enclosures). The HVAC scope is to keep the purge intact, which means duct integrity, fan reliability and pressure-cascade discipline.

What is sour gas service and what does it mean for the duct?

Sour gas is natural gas with hydrogen sulphide (H2S) content above the threshold that triggers ISO 15156 NACE MR0175 — typically 0.0003 MPa H2S partial pressure for steel selection. H2S is extremely toxic at the Safe Work Australia workplace exposure standard of 10 ppm TWA and 15 ppm STEL, and it causes sulphide stress cracking in susceptible steels. Most Western Australian and Northern Territory gas fields produce sour gas at varying severity. The duct itself does not carry process gas, but every duct inside the acid gas removal unit, the sulphur recovery unit, the amine regeneration column area and the dehydration unit is exposed to fugitive H2S, MDEA mist, mercaptans and elemental sulphur dust. 316L stainless is the default; localised Inconel 625 cladding is specified where H2S concentrations exceed 100 ppm or where wet H2S can condense, and that cladding is supplied by specialist alloy fabricators outside SBKJ scope.

What ventilation rate applies to an LNG compressor enclosure?

AS 1668.2 sets the baseline and AS/NZS 60079.10.1 sets the hazardous-area trigger. For LNG and boil-off-gas compressor enclosures the design rate is 12 air changes per hour on normal operation, stepping to 30 air changes per hour on hydrocarbon detection at 20 percent LEL or H2S at 10 ppm. Ventilation must achieve a documented air-change rate of at least 12 ACH continuously to maintain Zone 2 classification under the AS/NZS 60079.10.1 dilution-ventilation provision; if ventilation is lost the enclosure reverts to Zone 1 and fan-and-damper electrical equipment must be rated accordingly. Fans are spark-resistant AMCA Type B or C with IECEx Ex-d or Ex-e motors. Ductwork is 316L stainless throughout with continuity-tested earthing across every joint.

How is an LNG control room HVAC designed?

LNG control rooms are pressurised non-hazardous enclosures under AS/NZS 60079.4 or the equivalent NFPA 496 Class I Division 2 framework — a positive pressure of typically 50 to 75 Pa above the surrounding hazardous area is maintained by mechanical ventilation with redundant supply fans. Outside air is drawn from a high-level intake on the side of the building furthest from any credible release source, with hydrocarbon and H2S detection in the intake stream. On gas detection the intake closes and the building runs on internal recirculation only until the alarm clears. Walls, ceiling, doors and ductwork penetrations are gas-tight; HVAC penetrations through a blast-rated wall (per API RP 752 building siting) need blast-rated dampers, AS 1530.4 fire-rated penetrations and gas-tight seals. Duct material is 316L stainless on the outside-air run and galvanised internally because the recirculation air is benign.

What standards govern an offshore platform HVAC system in Australian waters?

Offshore platforms in Australian waters operate under the Offshore Petroleum and Greenhouse Gas Storage Act (OPGGS) administered by NOPSEMA, the National Offshore Petroleum Safety and Environmental Management Authority. Layered on top of the Act are the WHS Regulations for offshore facilities, the IMO MARPOL air pollution requirements for facility emissions, and the API recommended practices for offshore safety including API RP 14C (Safety Systems for Offshore Production Facilities) and API RP 14J (Hazardous Area Classification for Offshore Production Installations). HVAC ducts on a fixed offshore platform or an FPSO/FLNG sit in a salt-laden marine atmosphere (ISO 9223 C5-M Industrial Marine) and in extensive Zone 1 and Zone 2 envelopes around wellheads, separator skids and gas compression. 316L stainless is the minimum material and fully welded joints are mandatory; bolted flanges are reserved for accommodation modules and helideck-area utility ducts.

Which Australian LNG and gas projects use SBKJ-supplied HVAC duct equipment?

SBKJ supplies HVAC duct machinery to fabrication shops servicing Australian LNG, gas processing, refining and petrochemical projects through partner fabricators in the Perth, Karratha, Darwin, Gladstone, Brisbane, Melbourne and Geelong corridors. The end-user operator base includes the Karratha Gas Plant and the North West Shelf venture (Woodside, BP, Chevron, Shell, Mitsubishi, Mitsui, BHP), Pluto LNG (Woodside), Wheatstone LNG (Chevron), Gorgon LNG (Chevron, Shell, ExxonMobil), Prelude FLNG (Shell), Ichthys LNG (INPEX, TotalEnergies), Darwin LNG (Santos), Queensland Curtis LNG (Shell, Tokyo Gas), Australia Pacific LNG (ConocoPhillips, Origin), Gladstone LNG (Santos, PETRONAS, Total, KOGAS), the Moomba gas processing complex (Santos), the Viva Energy Geelong refinery and the Ampol Lytton refinery. SBKJ engineers engage with the EPC contractor base — Worley, Bechtel Australia, Fluor Australia, McDermott, KBR, Saipem, Monadelphous, John Holland and Civmec — to specify the SBAL-V, SB-ZF1500, SBSF-1525, SBPC1500 and SBLR-600 configuration for each project.