Study maps hydrocarbon potential in Canadian region of British Columbia | New

The multi-year, multi-partner study aimed to understand why sour gas is only affecting some wells in the area’s Montney, Doig and Duvernay formations – the source of the majority of natural gas produced in British Columbia.

Many theories had been proposed previously, and the report concludes that the cause is most likely sulfate that had migrated through faults and fractures into the Montney Formation from deeper areas.

Sour gas is natural gas that contains measurable amounts of (hydrogen sulphide) H2S. If sour gas is present underground, it creates health, environmental and economic risks when drilling, producing or processing gas.

Read more: Hydrogen Sulfide – A Paradigm Shift from Waste to Resource

Isotope analysis of sulfur in sour gas has largely demonstrated a match with Triassic anhydrite-bearing rocks. This sulphate-rich mineral has migrated (in solution) to rocks of the Montney Formation which host hydrocarbons. The reaction between the hydrocarbons and the sulphate led to the formation of the acid gas.

What could that mean?

In addition to tracing the source of the gas, the new study includes maps that can aid in acid gas risk analysis.

The study also used detailed workflows and modeling 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 Director, Energy and Water, Randy Hughes, explained the significance of the results: “Being able to map and better understand the source of sour gas, as well as better predict the distribution of natural gas liquids can help operators and regulators make better decisions regarding the development of new wells.

Unlocking these stranded wells and assets could help secure additional energy capacity, at a time when energy security is in the headlines more than ever.

Sour natural gas reserves are difficult 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 falling gas prices.

At current gas prices, however, development of the Ghasha gas field – along with many others – would yield excellent returns. Significant LNG capacity could be acquired and, in turn, this LNG could be exported to build foreign exchange reserves to fund clean energy investments.

Overcome Acid Gas Problems

Sour gas is rich in carbon dioxide (CO2) and H2S. Sweet natural gas contains low levels of these “sour” compounds.

To enable pipeline gas distribution, H2S must be removed to prevent corrosion of gas transmission assets. If the gas is to be converted to LNG, the CO2 must also be removed from the LNG to avoid jamming the liquefaction equipment with solid CO2.

As recently explored in a feature exclusively for gasworld, the removal of CO2 and H2S is achieved using a double tower absorption and stripping process in which an amine solution absorbs these acid gases. The process works the same way CO2 is cleaned from afterburner flue gases in carbon capture and storage systems.

Water is removed from natural gas using a similar process, but the glycol is the absorbent. The water must be drained off to prevent corrosion of the gas pipeline and to prevent the formation of ice, if the gas is to be liquefied.

The elimination of H2S emissions into the atmosphere has been mandatory for decades to avoid the problem of acid rain. The H2S is generally eliminated after the amine treatment according to the Claus process.

Residual H2S or SO2 emissions can be removed before the flue gases are released into the air. Flue gases are rich in CO2 and this stream is ideal for carbon capture and storage to reduce greenhouse gas (GHG) emissions. Increasing costs of taxing CO2 emissions will lead to the implementation of this additional process step in many places.

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