The multi-year, multi-partner study sought to understand why sour gas only affects some wells in the region’s Montney, Doig and Duvernay formations – the source of the majority of the natural gas produced in BC.
Numerous theories had been previously proposed, and the report concludes that the cause is most likely from sulfate that had migrated through faults and fractures into the Montney formation from deeper zones.
Sour gas is natural gas that contains measurable amounts of (hydrogen sulfide) H2S. If sour gas is present in the sub-surface, it creates health, environmental and economic risks while drilling, producing, or treating the gas.
Read more: Hydrogen sulfide – A paradigm shift from waste to resource
Isotopic analysis of the sulfur in the sour gas largely demonstrated a match with Triassic rocks containing anhydrite. This sulfate-rich mineral has migrated (while in solution) to the Montney Formation rocks that host hydrocarbons. The reaction between the hydrocarbons and sulfate led to formation of the sour gas.
Source: ©Geoscience BC
The Montney hydrogen sulfide and sulfur isotopic ratio
What could this mean?
In addition to tracing the source of the gas, the new study includes maps that can aid risk-analysis for sour gas.
The study also used detailed workflows and modelling to map the nature and distribution of natural gas liquids associated with the Montney Play. Natural gas liquids are a class of hydrocarbons that include products like propane, butane, and condensate.
Geoscience BC Manager, Energy and Water, Randy Hughes, explained the significance of the findings, “Being able to map and better understand the source of the sour gas, as well as better predict the distribution of natural gas liquids can assist operators and regulators in better decision-making around the development of new wells.”
Unlocking such wells and stranded assets could help secure additional energy capacity, at a time when energy security is in the headlines more than ever before.
Sour natural gas reserves are tough to process, compared to sweeter gas. Projects such as ADNOC’s Ghasha-mega project in the Middle East for example, where the gas contains 15% H2S, have been difficult to justify due to the suppressed gas price.
At current gas prices, however, the development of the Ghasha gas field – as well as many others – would yield excellent returns. Significant LNG capacity could be gained, and in turn that LNG can be exported to build currency reserves to fund investment in clean energy.
Overcoming sour gas issues
Sour gas is rich in carbon dioxide (CO2) and H2S. Sweet natural gas has low levels of these ‘sour’ compounds.
To enable gas distribution by pipeline, the H2S must be removed to avoid corrosion of the gas transmission assets. If the gas is to be converted to LNG, then CO2 must also be removed LNG to avoid blocking the liquefaction equipment with solid CO2.
As recently explored in a feature exclusively for gasworld, CO2 and H2S removal are achieved using a double-tower absorption and stripping process in which an amine solution absorbs these sour gases. The process operates in the same way that CO2 is cleaned from post-combustion flue gases in carbon capture and storage schemes.
Water is removed from the natural gas using a similar process, but glycol is the absorbent. Water must be removed to avoid corrosion of the gas pipeline and avoid ice formation, if the gas is to be liquefied.
Elimination of H2S emissions to the atmosphere has been mandated for decades to avoid the problem of acid rain. H2S is generally removed after the amine treatment using the Claus process.
Residual H2S or SO2 tail emissions can be eliminated prior to the flue gas being released to air. The flue gas is rich in CO2 and this stream is ideal for carbon capture and storage to reduce greenhouse gas (GHG) emissions. Rising CO2 emissions taxation costs will see this additional process step being implemented in many locations.