In oilfield operations, a hazardous location is defined as a place where concentrations of flammable hydrocarbon gases, vapors, or mists can occur. These are usually areas around wellheads, compression equipment, tanks, and pipelines. Electrical equipment that installed in such locations is has to be especially designed, tested and certified to ensure that it does not ignite a flammable gas, or initiate an explosion. Improperly designed and installed electrical equipment can cause explosions or act as ignition sources due to arcing contacts, sparks, high surface temperature or uncontrolled release of energy.
Many different design strategies exist for prevention of ignition and explosions in hazardous areas caused by electrical equipment. These include: Flameproofing, Increased Safety, Oil-filling, Encapsulation, Purging, and intrinsic safety. The Rapidlogger data-acquisition system is available in versions that are suitable for use in hazardous locations.
Two primary classification systems are used globally to define hazardous locations: the North American system (NEC/CEC) and the International system (IEC/ATEX). Understanding these classification systems is essential for proper equipment selection and installation.
North American Classification (NEC Article 500/505 and CEC Section 18):
The National Electrical Code (NEC) in the United States and the Canadian Electrical Code (CEC) use a Class/Division/Group system:
• Class I: Locations where flammable gases, vapors, or liquids are present (most oilfield locations)
• Class II: Locations with combustible dust
• Class III: Locations with ignitable fibers or flyings
• Division 1: Hazardous conditions exist under normal operating conditions or frequently
• Division 2: Hazardous conditions exist only under abnormal conditions or infrequently
• Groups (for Class I): A (acetylene), B (hydrogen), C (ethylene), D (propane, methane, natural gas - most common in oilfield operations)
Most oilfield locations are classified as Class I, Division 1, Group D or Class I, Division 2, Group D. Division 1 areas include locations immediately around wellheads, inside pump houses, and near open tanks. Division 2 areas are typically those adjacent to Division 1 locations where gas concentrations would only occur due to abnormal conditions such as equipment failure or unusual operations.
International Classification (IEC 60079, ATEX Directive 2014/34/EU):
The IEC system uses a Zone classification:
• Zone 0: Explosive atmosphere present continuously or for long periods (>1000 hours/year)
• Zone 1: Explosive atmosphere likely to occur in normal operation occasionally (10-1000 hours/year)
• Zone 2: Explosive atmosphere not likely to occur in normal operation, or if it does occur, only for short periods (<10 hours/year)
• Gas Groups: IIA (propane), IIB (ethylene), IIC (hydrogen, acetylene)
Most oilfield natural gas environments fall into Group IIA, which is equivalent to NEC Group D.
Zone/Division Equivalency:
• Zone 0 is more restrictive than Division 1 (no direct equivalent)
• Zone 1 is roughly equivalent to Division 1
• Zone 2 is roughly equivalent to Division 2
Electrical equipment is assigned a temperature class (T-Code) indicating the maximum surface temperature it will reach during operation. This temperature must be lower than the autoignition temperature of the gases present. The temperature classification system ensures that even if flammable gases contact the equipment surface, they will not ignite.
NEC/IEC Temperature Classes:
• T1: Maximum surface temperature 450°C (842°F)
• T2: Maximum surface temperature 300°C (572°F)
• T3: Maximum surface temperature 200°C (392°F)
• T4: Maximum surface temperature 135°C (275°F)
• T5: Maximum surface temperature 100°C (212°F)
• T6: Maximum surface temperature 85°C (185°F)
Most petroleum gases (methane, propane, natural gas) have autoignition temperatures above 450°C, making T1-T4 equipment suitable for most oilfield applications. However, some lighter hydrocarbon vapors may require T5 or T6 rated equipment. The ambient temperature and operating conditions must also be considered when calculating maximum surface temperatures.
Various protection techniques have been developed to prevent electrical equipment from becoming an ignition source. Each method uses different engineering principles to eliminate the risk of explosion.
Explosion-Proof / Flameproof (NEC "d" / IEC "Ex d"):
The equipment enclosure is designed to withstand an internal explosion of flammable gas and prevent the explosion from propagating to the external atmosphere. The enclosure must have sufficient mechanical strength to contain the explosion pressure and flame paths (joints, threads, shafts) that cool the hot gases below their ignition temperature as they escape. Explosion-proof enclosures are typically constructed of cast aluminum, stainless steel, or ductile iron with precisely machined flanges. Thread engagement, gap widths, and path lengths are strictly controlled. This method allows for normal sparking or arcing components (relays, switches, motors) to be used inside the enclosure. Maximum Internal Safe Gap (MISG) values determine the maximum gap through which a flame will not propagate for a given gas group.
Increased Safety (IEC "Ex e"):
Additional measures are applied to give increased security against the possibility of excessive temperatures and the occurrence of arcs or sparks. Equipment is designed to operate well below ignition-capable temperatures, use high-quality insulation materials, provide increased creepage and clearance distances for electrical components, and ensure all connections are secure and will not loosen due to vibration. Increased safety protection is commonly used for terminal boxes, junction boxes, squirrel-cage motors, and lighting fixtures. This method is NOT suitable for equipment with make-and-break contacts (switches, relays) or components that normally spark.
Intrinsic Safety (NEC "IS" / IEC "Ex i"):
The electrical energy in the circuit is limited to levels incapable of causing ignition by either spark or thermal effect under both normal and abnormal fault conditions. Intrinsic safety is achieved through the use of safety barriers or isolators that limit voltage, current, and stored energy (capacitance and inductance). This method is divided into two levels:
• ia: Safe with two independent faults (suitable for Zone 0/Division 1)
• ib: Safe with one fault (suitable for Zone 1/Division 2)
Intrinsically safe circuits must be installed with proper separation from non-IS circuits, using blue-coded cables, and documented through entity parameters (Vmax, Imax, Pmax, Co, Lo, Ci, Li). Sensor circuits for pressure, temperature, and flow measurement are commonly designed as intrinsically safe. The Rapidlogger system can be equipped with intrinsically safe input modules for sensor connections, allowing safe operation in Division 1/Zone 1 areas while keeping the main processing equipment in a Division 2/Zone 2 or non-hazardous location.
Purging and Pressurization (NEC "Type X, Y, Z" / IEC "Ex p"):
The enclosure is supplied with clean air or inert gas (typically nitrogen) at sufficient pressure to prevent entry of flammable gases. Three types exist:
• Type X (Ex px): Reduces classification inside enclosure to non-hazardous (suitable for Division 1/Zone 1)
• Type Y (Ex py): Reduces classification inside enclosure to Division 2/Zone 2
• Type Z (Ex pz): Reduces classification inside enclosure to Zone 2 only
Pressurization systems include pressure monitoring, purge timers, alarm systems, and automatic shutdown if pressure is lost. A pre-purge cycle of at least 4 air changes is required before energizing the equipment. Purged enclosures are commonly used for analyzer houses, motor control centers, and large instrumentation panels in petrochemical facilities.
Oil Immersion (IEC "Ex o"):
Electrical components that could produce sparks or excessive heat are immersed in oil to a depth sufficient to prevent ignition of the flammable atmosphere above the oil. The oil must be free from contaminants and regularly checked for level and condition. This method is commonly used for transformers, switchgear, and some types of control relays. Oil immersion is less common in modern oilfield data acquisition systems but may be encountered in older installations.
Encapsulation (NEC "m" / IEC "Ex m"):
Parts that could ignite an explosive atmosphere are enclosed in a compound (potting material such as epoxy or polyurethane resin) in such a way that the explosive atmosphere cannot be ignited under normal operating or installation conditions. The compound must maintain its properties over the expected temperature range and service life. Encapsulation is commonly used for electronic assemblies, solid-state relays, and LED indicators. Many modern transmitters and sensors use encapsulated electronics.
Non-Incendive (NEC "NI"):
Equipment that, in its normal operating condition, is not capable of igniting a flammable atmosphere. This is similar to intrinsic safety but applies only under normal (non-fault) conditions. Non-incendive equipment is acceptable for Class I, Division 2 locations but NOT Division 1. This classification is commonly used for low-power sensor circuits, indicator lights, and instrumentation in Division 2 areas.
Electrical equipment for hazardous locations must be tested and certified by nationally recognized testing laboratories (NRTLs) or notified bodies. Certification ensures the equipment meets rigorous design, construction, and testing requirements.
North American Certification Bodies:
• UL (Underwriters Laboratories): Tests to UL 1203, UL 2279, UL 913, and other standards
• CSA (Canadian Standards Association): Tests to CSA C22.2 standards
• FM Approvals (Factory Mutual): Tests to FM 3600, FM 3610, FM 3611, FM 3615 standards
• MET Labs, Intertek (ETL): Additional NRTLs recognized by OSHA
International Certification Bodies:
• ATEX: European directive requiring equipment certification for use in explosive atmospheres (notified bodies include BASEEFA, DEKRA, SIRA, TÜV)
• IECEx: International certification scheme based on IEC standards, providing mutual recognition between participating countries
• PESO (India), NEPSI (China), TIIS (Japan), INMETRO (Brazil): Country-specific certification schemes
Key Testing Standards:
• IEC 60079 series: International standards for equipment in explosive atmospheres (60079-0 General Requirements, 60079-1 Flameproof, 60079-7 Increased Safety, 60079-11 Intrinsic Safety, etc.)
• NFPA 70 (NEC): Articles 500-505 for hazardous location requirements
• API RP 500/505: Recommended practices for area classification in petroleum facilities
• ISA-12.12.01: Nonincendive electrical equipment for use in Class I and II, Division 2 locations
• ANSI/UL 60079 series: Harmonized North American adoption of IEC standards
Equipment nameplates must display the certification marking, class/division or zone rating, gas group, temperature class, and protection method. Example markings include:
• Class I, Div 1, Groups B, C, D, T4
• Ex d IIC T4 Gb (ATEX/IECEx marking for flameproof, gas group IIC, T4 temperature, EPL Gb)
The IEC system assigns an Equipment Protection Level (EPL) that indicates the likelihood of the equipment becoming an ignition source:
Gas Atmospheres:
• Ga (Very high level of protection): Suitable for Zone 0, provides protection with two independent faults, equipment remains safe even with rare malfunctions
• Gb (High level of protection): Suitable for Zone 1, provides protection during normal operation and expected malfunctions
• Gc (Enhanced level of protection): Suitable for Zone 2, provides protection during normal operation
Dust Atmospheres:
• Da: Suitable for Zone 20 (dust present continuously)
• Db: Suitable for Zone 21 (dust present occasionally)
• Dc: Suitable for Zone 22 (dust present infrequently)
EPL markings allow quick identification of where equipment can be safely installed. For example, equipment marked EPL Gb can be used in Zone 1 and Zone 2, but NOT Zone 0.
Proper installation is critical to maintaining the integrity of hazardous location protection methods. Even certified equipment can become dangerous if improperly installed.
General Installation Requirements:
• All conduit systems must be sealed to prevent migration of flammable gases through the conduit into non-hazardous areas. Seals must be installed within 18 inches (457 mm) of the enclosure in Division 1 locations.
• Threaded entries must have at least 5 threads fully engaged for explosion-proof enclosures.
• Cable glands and sealing fittings must be certified for the area classification and match the equipment certification.
• Unused openings in enclosures must be closed with certified plugs, maintaining the enclosure rating.
• Equipment must be installed in accordance with manufacturer's instructions and control drawings.
• Intrinsically safe wiring must be segregated from non-IS wiring using separate conduits or cable trays with minimum separation distances (typically 50mm / 2 inches).
• Intrinsically safe cables should be identified with blue insulation or blue markers.
Grounding and Bonding:
Proper grounding is essential to prevent static charge accumulation and provide fault current paths. All metallic equipment, conduit, and cable armor must be bonded and grounded according to NEC Article 250 or equivalent standards. Impedance of the grounding path must be low enough to facilitate fast operation of overcurrent protective devices. For intrinsically safe systems, both the hazardous and non-hazardous location grounds must be connected to the same grounding system to prevent ground loops that could introduce dangerous voltages.
Environmental Considerations:
Equipment enclosures must provide adequate protection against environmental factors:
• Ingress Protection (IP) Rating: Indicates protection against solids and liquids (e.g., IP66 = dust-tight and protected against powerful water jets). Oilfield equipment typically requires IP65 or IP66 minimum.
• NEMA Ratings: North American system (NEMA 4/4X for outdoor use, corrosion resistance)
• Corrosion Protection: Saltwater, H2S, and other corrosive gases require stainless steel (316L), super duplex, or special coatings
• Vibration Resistance: Equipment near pumps, compressors, or on mobile units must be vibration-rated and properly mounted
Ongoing inspection and maintenance are required to ensure continued safe operation of electrical equipment in hazardous locations.
Initial and Periodic Inspections:
Inspections should verify:
• Equipment certification markings match the area classification
• Enclosure integrity (no cracks, corrosion, missing bolts, damaged flanges)
• Conduit seals are in place and properly installed
• Cable glands are tight and sealing washers are in good condition
• Unused openings are properly plugged
• No unauthorized modifications have been made
• Grounding connections are secure and show low resistance
• Intrinsically safe barriers are installed correctly and documents (control drawings) are available
• Temperature ratings are appropriate for the gases present and ambient conditions
Inspection Frequency:
• Initial Inspection: Before energizing new or modified installations
• Detailed Inspection: Every 1-3 years depending on area classification and environmental severity (Division 1/Zone 0-1 areas require more frequent inspection)
• Close Visual Inspection: Every 6-12 months in harsh environments
• Routine Inspection: During normal operations by trained operators
Documentation and Compliance Records:
Facilities must maintain documentation including:
• Area classification drawings showing Class/Division or Zone boundaries
• Equipment certification documents and nameplates
• Installation control drawings for intrinsically safe systems (showing entity parameters, cable types, and barrier specifications)
• Inspection reports and maintenance logs
• Procedures for work in hazardous areas (hot work permits, lock-out/tag-out)
• Training records for personnel working with hazardous location equipment
Maintenance Procedures:
Maintenance in hazardous locations requires special precautions:
• De-energize equipment before opening enclosures unless specifically rated for live maintenance
• Hot work permits required for any work that could produce ignition sources
• Gas testing to verify area is safe before maintenance (LEL must be below 10% of lower explosive limit)
• Replacement parts must match original certification (same material, dimensions, specifications)
• Gasket replacement: Flameproof enclosures require gaskets to be in perfect condition; damaged gaskets must be replaced immediately
• Re-certification may be required after major repairs or modifications
The Rapidlogger data acquisition system is designed with hazardous location requirements in mind and is available in configurations suitable for Division 1/Zone 1 installations. The system achieves compliance through multiple protection methods:
Intrinsically Safe Input Modules: Sensor input circuits use certified intrinsically safe barriers or isolated interfaces, allowing sensors to be connected in Division 1/Zone 1 areas while the main processing unit remains in a safer location. Entity parameters for all IS circuits are documented in system control drawings.
Purged/Pressurized Enclosures: Complete Rapidlogger systems can be installed in NEMA 4X purged enclosures with Type X or Type Y pressurization systems, allowing installation of the full system including displays and operator interfaces in Division 1 or Division 2 locations.
Division 2/Zone 2 Installation: When installed in Division 2 or Zone 2 areas, the Rapidlogger system uses non-incendive circuits and sealed enclosures that meet the requirements for these less restrictive classifications.
Compliance Documentation: Each Rapidlogger system is supplied with appropriate certification documents, wiring diagrams, and installation instructions to ensure compliant installation. Technical support is available to assist with area classification questions and installation planning.
Customers should consult with Rapidlogger technical support during system specification to ensure the selected configuration meets the specific hazardous area classification requirements of their facility. Proper system selection, installation, and maintenance ensure safe, reliable operation in oilfield environments while meeting all regulatory requirements.
