The global transition and shifting energy landscape has significantly expanded the role of gas detection in the oil and gas sector, driven by different types of gases needing to be monitored, increasing environmental considerations, and greater awareness of fugitive methane and its prevalence.
Modern gas detection techniques involve utilising a mix of sensors – infrared, catalytic bead, ultrasonic, and electrochemical – to accurately identify and track multiple types of gases in real time.
Sensors now integrate directly with digital platforms that allow alerts, data logs, and environmental reports to synchronise automatically, providing an interconnectedness that transforms detection from an emergency response tool into a decision-making asset.
These systems can identify through predictive analytics the source and trajectory of a small leak before it escalates, ensuring both safety and sustainability.
Along with hydrogen and carbon dioxide (and the usual suspect methane), new gases that must be safely contained include carbon monoxide, hydrogen sulphide, and nitrogen dioxide, all of which exhibit varying behaviours and present different kinds of risk.
Carbon monoxide provides a clear example of a cumulative hazard, with its toxic effects driven primarily by the accumulation of carboxyhaemoglobin in the bloodstream, making cumulative exposure over time the dominant risk factor.
Hydrogen sulphide, on the other hand, is an acutely toxic gas capable of causing rapid incapacitation at elevated concentrations and is governed by peak exposure rather than cumulative dose.
In this context, extended work shifts do not alter the nature of the hazard – a short-term increase in concentration remains dangerous regardless of whether the shift is eight hours or 12.
Nitrogen dioxide presents a more complex case, exhibiting both acute irritant properties and cumulative exposure characteristics.
In extended shift environments, moderate but sustained concentrations of nitrogen dioxide may contribute to cumulative exposure, while short-term increases may produce immediate respiratory effects.
A 2022 research project undertaken by the Gas Industry Social and Environmental Research Alliance (GISERA) investigated options for long-term monitoring of well integrity in decommissioned onshore gas wells in the Northern Territory, including exploration and production wells.
The results identified the most effective monitoring approach currently available for fully decommissioned wells required direct monitoring immediately above the well at the surface using methane gas detection equipment, supported by indirect methane monitoring at the well pad scale.
More specifically, two broad objectives for well integrity monitoring for decommissioned wells were identified: monitoring well barrier components to confirm they meet performance criteria and are not degrading; and monitoring the consequences of breaches of well integrity that could lead to a release of fluids from the well.
It was also found that confirming the integrity of wells at the time of decommissioning was the best means of reducing long-term post-decommissioning risk.
GISERA said onshore gas wells that had reached the end of their productive life and were decommissioned and sealed with cement could be potential sources of methane emissions or aquifer contamination due to compromised cement or well casing integrity.
The alliance added: “Concerns around the potential of leaking decommissioned wells (failed well integrity leading to movement of fluids along or into/out of the well) have been raised by community groups and other stakeholders.
“If well barrier integrity issues were to occur, the buoyancy and mobility of methane mean it is the most likely hydrocarbon to move to the surface.
“The availability of reliable, robust, and sensitive methane detectors that can be used in the field will allow leaks that reach the surface to be identified.”
The project included assessment of well decommissioning practices and monitoring techniques and technology, in the context of Northern Territory regulatory requirements, with the results helping to develop long-term well monitoring approaches that support best practice in onshore well decommissioning.
The research also found that emerging technologies had the potential to improve the performance of both decommissioning and remediation techniques.
GISERA explained decommissioning was the point where a well was taken out of service, permanently sealed (plugged) and all surface infrastructure removed.
It said: “The goal of decommissioning the well is to ensure the integrity of the well in perpetuity, effectively reestablishing the natural barriers formed by the impermeable rock layers that were drilled through to reach the resources during the well construction phase.”
Quantitative optical gas imaging (OGI) is an approach to gas detection that gives workers actionable and precise information regarding the toxicity of their immediate surroundings, without endangering them when detecting such hazards.
OGI devices use a spectrally-filtered camera to visualise otherwise invisible gas leaks by measuring the infrared radiation passing through a volume of gas, and multiple studies have demonstrated the potential of OGI to detect gas leaks in a variety of environmental situations.
Refinery employees equipped with OGI cameras can ascertain whether an area contains toxic gas build-up, limiting exposure that would normally set off a wearable gas monitor.
Similarly, workers gauging large tanks can judge the emission characteristics of the tank before placing themselves in any potential gas cloud.
Other detection methods such a toxic vapour analyser (TVA), colloquially known as a ‘sniffer’, or a Bacharach Hi Flow Sampler (BHFS), can quantify a variety of gas leaks in mass leak rate and volumetric leak rate, as well as concentration path length.
A TVA offers concentration analysis but no measurement of flow, while a BHFS is capable of measuring both flow and concentration.
However, both TVA and BHFS devices can return differing interpretations of the same leak, depending on where and when the leak is sampled and how the device is positioned.
This limitation is a result of these devices’ functionality – they provide a leak snapshot in time while a quantitative OGI system provides a rolling average leak rate over time.
