Federal Regulations on NOx emissions from Boilers, Heaters and Stationary-Spark Engines have come into play.

Environment and Climate Change Canada (ECCC) states:

“The Regulations implement a subset of the Base Level Industrial Emission Requirements (BLIERs) that have been developed under the Air Quality Management System (AQMS)

Purpose: Nationally consistent air pollutant emission standards for nitrogen oxides (NOx) and sulphur dioxide (SO2) from the cement sector and from the boilers, heaters and stationary spark-ignition engines that are used in several industrial sectors at a level that is consistent across the country.”

These regulations will apply to upstream oil and gas and oil sands in the following areas:

• Large new and existing boilers and heaters that burn gaseous fossil fuels, such as natural gas. Ongoing emission testing and reporting will be required for the larger boilers and heaters (>105 GJ/hr). There is a transitional period of up to three years to ease financial impacts during which some equipment will be required to meet NOX emission intensity limits that are less stringent than equipment that is installed after the transitional period.
• New and existing stationary engines at facilities. Compliance with the NOX requirements for existing engines can be achieved on a per engine basis or based on the average of the annual emissions of all of a company’s engines. Engine registration and ongoing emission testing and reporting will be required.

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Introduction

Raw natural gas consists primarily of methane (CH4), and varying amounts of higher molecular weight hydrocarbons and other contaminants. Natural gas containing acidic contaminants (H2S and/or CO2) is commonly referred to as sour gas. H2S is a highly toxic gas which can be fatal to humans at higher concentrations. Acid contaminants can also create operational problems such as increased corrosion in gas pipelines.

To avoid these health, safety and operational problems, acidic contaminants (H2S and/or CO2) in  natural gas need to be removed to produce a ‘sweet’ gas stream. The resulting stream should have an H2S content of less than 4 ppmv. The process to remove these contaminants is commonly known as natural gas sweetening. The most widely used method utilizes amine solutions to absorb the H2S and CO2. According to the GPSA Engineering Databook (13th edition) [1], the amine circulation rate can be determined based on the moles of acid gas that need to be removed, as well as the ‘acid gas loading’ in the rich amine solution. Hence it is very important to understand the acid gas loading parameter for effective and efficient operations.