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Alberta Landowners Guide, Gas Plant Risks and Questions Regarding Other Infrastructure

Landowners Guide Cover.jpg
3rd edition
Authors:            Duncan Kenyon, Nikki Way, Andrew Read, Barend Dronkers, Benjamin Israel, Binnu Jeyakumar, Nina Lothian
Publisher: Pembina Institute
Publish Date: October 2016
PDF Download: [Landowners' Guide]              [Landowners' Primer]                                                                    
Initiation Phase
Exploration Phase
Development Phase
Pipelines and Other Infrastructure
              Pipelines and Emergency Response
              Pipelines Regulated by AER
              Questions Before Signing a Pipeline Agreement
              Oil Batteries and Gas Compressor Plants
              Gas Plant Risks and Questions Regarding
               Other Infrastructure
Environmental Impacts
Abandonment and Reclamation
Compensation, Rights, and Hearings

Risks of Gas Plants

Air emissions

Occasionally there may be a problem at a gas plant, so that the company has to flare some or all of the gas being processed.[1] This is called a “plant upset.” Gas plant upsets can result in flaring the full volume of gas entering the plant (referred to as the “inlet gas” or “raw gas”), the full volume of gas leaving the plant (referred to as the “sales gas”), or the highly concentrated acid gas stream created by the sweetening process in sour gas plants. Upset flaring can produce large volumes of air pollution. Therefore, gas plant operating approvals usually limit the length of time gas can be flared before companies must shut down both the plant and the pipeline that brings gas to the plant. Flaring and Venting provides more information on flares.

The many valves and pipe connections in oil and gas processing facilities can develop tiny leaks. These leaks can release air pollutants, such as methane and volatile organic compounds (VOCs),[2] into the air. These types of emissions are referred to as “fugitive emissions.” Another source of fugitive emissions at these facilities is vapours from liquid hydrocarbon storage tanks.

Tank venting and fugitive emissions were recently found to be a likely cause of extreme odour problems in the Peace River area in northeast Alberta that forced residents to leave their homes due to the resulting health impacts.[3]

Acid gas injection

Instead of separating the sulphur and flaring other waste gases, the waste acid gas, which contains predominantly H2S and CO2, can be injected deep underground. Acid gas injection facilities normally have very low emissions of sulphur dioxide (SO2). However, if there is a problem with the acid gas disposal well, pipeline or compressor, the highly concentrated acid gas is flared, resulting in very high levels of SO2 and some fugitive H2S emissions that can adversely affect local air quality for a period of time before the gas plant can be safely shut down. AER approvals typically contain requirements to minimize the duration of these flaring events. If an acid gas injection facility is planned near you, you should inquire about the flaring minimization requirements at the gas plant and whether it would be completely shut down in the event of a problem.

Glycol dehydration

Glycol dehydrators are used at gas processing plants, well sites and compressor stations to remove water from gas before introducing the gas into pipelines. Removing the water prevents freezing and corrosion in the pipeline. To remove the water, the gas is exposed to glycol, which also absorbs benzene, toluene, ethylbenzene, and xylene (collectively referred to as “BTEX” molecules) and H2S (if present). The water is subsequently separated from the glycol by a process called heat regeneration, allowing the glycol to be reused. Emissions from glycol dehydrators include BTEX if the vapours from the regeneration process are vented to the atmosphere.

Benzene is classified as “toxic” as defined under the Canadian Environmental Protection Act, and Canada-wide standards for the chemical were adopted in 2001.[4] The oil and gas industry subsequently committed to voluntarily limit the emissions of benzene from dehydrators.[5] In 2006, these voluntary initiatives were adopted by the Energy Resources Conservation Board (the predecessor to the Alberta Energy Regulator). Since that time, the regulatory requirements have been revised to try to minimize the public’s exposure to benzene by placing stricter emissions limits based on the proximity to a permanent residence or public facility such as a rural hospital or school. The AER’s current requirements aim to transition all current and new glycol dehydrators to meet a maximum emissions limit of 1 tonne annually for uncontrolled sources and 3 tonnes annually for those with a flare or incinerator control by 2018.[6]

If a glycol dehydrator is planned near you, you should inquire about the expected benzene emissions and how they are to be managed. If it is planned to be in close proximity to your residence or pasture, you may wish to ask for monitoring of benzene or other BTEX emissions around the site and request that results are reported back to you.

Large petroleum production facilities

A company is required to obtain approval if it is developing a large-scale oil production site for the recovery of heavy oil or oilsands. Environmental Impact Assessments are also mandatory for oilsands mines, and for oilsands in situ and processing plants that produce more than 2000 cubic metres of bitumen per day.[7]

If a company wants to expand or significantly alter its operations, they may need to change their AER approvals to allow for the alterations. If so, there will be an opportunity for public input (and in some cases, such as what is outlined under the Environmental Protection and Enhancement Act, the opportunity to appeal a decision respecting the approval).

Questions to ask regarding batteries, compressors and facilities

The series of questions presented below may be helpful for identifying issues to discuss with respect to batteries, compressors and facilities. First it is important to find out what kind of facility a company is proposing, and what kind of air, water and land impacts are expected. Then you can select the questions that will be relevant to that particular development.

Air quality

Will there be any flares and, if so, how will the amount of flaring be minimized?
This question applies especially to oil battery sites.
What type of fugitive emission detection/control system will the company have in place?
Tank vapours and small leaks at pipe connections and valves can be sources of fugitive emissions. These types of releases can start and worsen gradually — requiring companies to do regular preventative maintenance or periodic checks.

Water quality

How will groundwater and surface water be protected?
There may be dykes around storage tanks or berms around the entire site, to control surface water runoff.
How will surface water be managed on the site?
If there is a possibility that surface water could be contaminated by leaks, etc. from on-site equipment, it must be drained to a collection area.
Will water quality testing of surface runoff be required before it is discharged?
If government regulations require surface runoff to be collected, it usually must be tested and meet certain criteria before it can be released off-site. If it does not meet the criteria it must be treated or trucked off to an approved disposal facility.
Will monitoring of groundwater be required?
Groundwater monitoring is sometimes required. This may depend on whether there are storage tanks on the site, and how they are constructed and contained.


What noise mitigation measures will be used?
This applies in particular to compressor stations, but is relevant for other facilities. It is advisable to obtain a copy of the noise plan, as required by the AER.


Does the company have a site specific emergency response plan (ERP), and if so how large is the evacuation zone?
An ERP is required for sour gas facilities (see Emergency response plans).


  1. This material is from the Pembina Institute publication 'Landowners' Guide to Oil and Gas Development, 3rd edition (2016)'
  2. Volatile organic compounds are comprised of hydrocarbon compounds larger than three carbon molecules in size and that turn to vapour under ambient conditions.
  3. AER, Report of Recommendations on Odours and Emissions in the Peace River Area (2014).
  4. Canadian Council of Ministers of the Environment, Canada-wide Standard for Benzene Phase 2 (2001). http://www.ccme.ca/en/resources/air/benzene.html
  5. Canadian Association of Petroleum Producers. Benzene: Emission Reductions by the Upstream Petroleum Industry, 2003; https://web.archive.org/web/20170910162736/http://www.capp.ca/publications-and-statistics/publications/60315
  6. AER, Directive 039: Revised Program to Reduce Benzene Emissions from Glycol Dehydrators (2013), 3. https://www.aer.ca/documents/directives/Directive039.pdf. Note that Benzene rules may have been updated since publication. See Directive 039 for more details.
  7. Alberta, Environmental Assessment (Mandatory and Exempted Activities) Regulation, 111/1993.