In the dynamic and volatile environment of the oil and gas industry, it is critical that rugged, reliable measurement instrumentation is used to keep operations running smoothly and safely. As oil and gas production pushes ever further into remote locations to find new sources, the equipment used in exploration, drilling and production has become increasingly complex, making the need for dependable and durable pressure sensors more crucial than ever.

Applications that require hazardous location pressure transmitters include wellheads, drilling in completion operations, well service vehicles, drilling tools, mud systems, intelligent pigs, core analysis, compression systems and vapor recovery units.

During hydraulic fracturing, or fracking, millions of gallons of water, sand and chemical additives are pumped into the well to break apart rock and release gas and oil. These materials are injected at high pressures up to 10,000 psi down and across into horizontally drilled wells as far as 10,000 feet below the surface. The pressurized mixture causes the rock layer to crack. These fissures are held open by the sand particles or other viscous materials (proppant is often used) so that gas and oil can flow up to the well.

Pressure transmitters play an important role in the hydraulic fracturing process to monitor pressure at different stages in remote data monitoring vehicles including fracturing pumps, blending units, and cementing, wireline and workover rigs. FM, CSA and ATEX approved explosion-proof and intrinsically safe transmitters must be used for safe, reliable, repeatable performance in these applications.

Other well servicing applications include pump pressure measurement on mud logging units at drilling locations, switching control of the liquid passing from tanks to the discharge hose on liquid additive trailers, and pressure measurement on mobile and stationary equipment control panels. Pressure measurement plays a key role on the control systems of cementing trucks, valve test benches, valve actuator panels, and chemical injection skids as well.

At wellheads and Christmas trees, monitoring wellhead pressure requires the use of rugged and weather-resistant intrinsically safe or explosion-proof pressure transmitters. If the pressure is not contained during drilling operations by the column of drilling fluid, casings, wellhead, and blowout preventer, a well blowout could occur.

Downhole drilling tools use pressure transmitters to monitor hydraulic and pipeline oil pressure. This extreme environment can often require transmitters with extreme high pressure and temperature ranges.

Pressure measurement is also important in mud flow lines. This is an especially viscous application and sometimes a transmitter with a flush diaphragm or a diaphragm seal is used to avoid clogging.

Intelligent or “smart” pigs are devices that are used to test and perform maintenance operations in oil and gas pipelines, as well as inspect for leaks which could be explosive and dangerous to the environment. Multiple pressure transmitters may be attached to the pig to monitor pipeline and hydraulic pressure, including differential pressure transmitters. In this application, a transmitter with low power consumption works best to minimize energy draw from the pig battery system.

Core analysis is used to study samples of reservoir rocks which provide information on the condition of a well, including porosity, permeability, fluid saturation and grain density which can provide insight on the well’s potential productivity. During core analysis an oil sample may be forced at high pressure through a piece of rock core. It’s essential that a pressure transmitter used in this application provide high accuracy measurement up to 10,000 psi with Hastelloy or Monel construction to avoid corrosion of the diaphragm.

As EPA regulations have become more stringent to reduce the emissions produced by the disposal of saltwater and other caustic by-products of oil and gas production, reliable low pressure measurement is even more critical. Vapor recovery units are designed to comply with these EPA standards, provide the producer with additional profits that may be lost due to stock tank vapor emissions, and eliminate stock tank vapor emission into the atmosphere. Recovered vapors have a significantly higher BTU content than natural gas from the pipeline, therefore recovered vapors can be more valuable than methane alone.

Vapory recovery units, along with saltwater disposal systems and storage tanks, require precise pressure measurement to ensure optimal control and monitoring, and maximize recovered emissions and profit to the producer. Pressure transmitters used in vapor recovery control, saltwater disposal control systems, tank vent monitoring systems and liquid level monitoring in shallow tanks must offer low pressure ranges and be safe for hazardous location service.

Depending on the type of application, hazardous location pressure transmitters must be of Intrinsically Safe, Explosion-Proof or Non-Incendive design. A flush diaphragm connection can also be used to protect against plugging, which is ideal for applications involving measuring viscous fluids and for measuring pressure when fluid is pumped down the well.

Hazardous location transmitters exist in concert with the classification rating of the area in which they are installed. Pressure transmitters are rarely installed in isolation and require other associated equipment for operation. As such, areas known to have a hazard of combustion or explosion are given an area classification.

In general, the classification system identifies the type of hazardous substance that can be present in the area, how much or often the hazardous material will be present, and the risk of ignition due to a fault condition of the equipment in the area. When considering hazardous locations, it is helpful to remember the concept of the hazard triangle. This concept states that an area can be considered hazardous if a fuel source (hazardous gas, liquid or solid), oxygen, and an ignition source are all present. In this construction, it can be seen that the inside of a natural gas fireplace could be considered a hazardous location as all three components of the hazard triangle are present. Alternatively, the inside of a sealed hydrogen vessel may not be classified as hazardous if no oxygen is present, even though hydrogen is a very easily combustible gas.

The classification system to identify a hazardous zone and associate equipment is an in-depth discussion and beyond the scope of this article. However, below are some general definitions of the markings found on hazardous location equipment. For equipment classified using the US National Electric Code, class, division or zone, group, and temperature ratings will be commonly encountered markings. In this standard, class defines the type of hazardous substance that can be present. Class I for gasses, class II for dust, and class III for fibers and flyings. The division marking (and analogous zone marking) define the risk of the hazardous material presence. For instance, Division I and Zone 0 identify locations where the hazardous substance is present continuously under normal operating conditions. Where as Division II identifies an area where the hazardous substance is not likely to be present under normal conditions. The group marking further identifies the particular hazardous substance (for instance Group B for hydrogen). Lastly, the temperature rating will be seen as a T with a number following. The temperature ratings range from T1 to T6 and define the maximum safe operating temperature of the equipment in the classified area.

When considering hazardous location ratings, there are generally two different paradigms applied for risk mitigation. Explosion-Proof and Non-Incendive Transmitters seek to minimize risk of catastrophic incidence by managing the energy of an explosion if it were to happen. Specifically, explosion proof equipment is built to contain and dissipate the energy of a combustion so that the explosion does not propagate further to other equipment and areas. This manifests as enclosures and wiring conduit systems that are capable of containing an explosion if it were to occur. While this type of area classification does require more costly installation and wiring techniques, it is a very well developed and understood standard within hazardous location installations. Explosion-Proof Transmitters are ideal for monitoring tubing and casing pressures in a wellhead. These sensors provide consistently accurate and stable output, stand up to extremely harsh environments, and endure the test of time.

As point of note, the construction of explosion proof and non-incendive transmitters is very similar by way of the hazardous location standard. Even though they are strictly classified differently, the installation techniques and equipment for these two types of devices is very similar. Furthermore, in some cases when the area classification allows, explosion proof or non-incendive transmitters can be used safely and can follow typical installation practices and procedures.

By contrast, Intrinsically Safe Transmitters are engineered in such a way that they cannot contain or source any energy sufficient to cause an ignition in a hazardous zone. These devices are paired with intrinsically safe power supply barriers that limit the amount of energy that can be sourced into the hazardous area. Significantly, this type of classification allows for less costly wiring and field installation when compared to explosion proof and non-incendive installations. Many oil applications require Intrinsically Safe Sensors that can be submerged into storage tanks or boreholes to monitor the level of potentially flammable liquids or in zones with potentially explosive atmospheres.

In hazardous oil and gas environments, operators can’t afford to take a chance on faulty or inaccurate pressure measurement sensors. Choosing the right high quality, durable pressure transmitters can keep these systems running safely and smoothly, and prevent costly accidents.