If sustainable development of Canadian waters is to be achieved, a realistic and manageable framework is required for assessing cumulative effects. The objective of this paper is to describe an approach for aquatic cumulative effects assessment that was developed under the Northern Rivers Ecosystem Initiative. The approach is based on a review of existing monitoring practices in Canada and the presence of existing thresholds for aquatic ecosystem health assessments. It suggests that a sustainable framework is possible for cumulative effects assessment of Canadian waters that would result in integration of national indicators of aquatic health, integration of national initiatives (e.g., water quality index, environmental effects monitoring), and provide an avenue where long-term monitoring programs could be integrated with baseline and follow-up monitoring conducted under the environmental assessment process.

Over the past couple of years oil and gas operators in Alberta have been faced with an increasing challenge to reduce atmospheric emissions. One of these emission sources comes from oil and gas pools that contain uneconomic quantities of hydrogen sulphide and carbon dioxide (acid gas). Disposal of this acid gas to underground formations is sometimes a cost effective alternative to sulphur recovery and it also can reduce the public concern resulting from sour gas production and flaring. In Alberta, the Oil and Gas Conservation Act requires that operators apply for and obtain approval from the Alberta Energy and Utilities Board (EUB) to dispose of the acid gas. Before approving any scheme, the EUB reviews the application in order to satisfy several primary issues: maximizing conservation of hydrocarbon resources, minimizing environmental impact, promoting public safety, and ensuring that the equity interests of mineral rights owners are protected. To adequately address these matters, the EUB requires that applicants submit information regarding surface facilities, disposal well configurations, and reservoir factors. This paper discusses the information required and describes the process that should be followed by operators who wish to obtain EUB approval for underground disposal of acid gas. In addition, this paper discusses the performance of some of the acid gas disposal schemes currently operating in Alberta. Introduction (Author's note: The Alberta Energy and Utilities Board (EUB) is empowered by provincial legislation, to regulate the development of energy resources in the Province of Alberta. The EUB replaced its predecessor the Alberta Energy Resources Conservation Board (ERCB) in 1995. References made to both the ERCB and the EUB throughout the text of this paper can be used interchangeably). A significant portion of raw natural gas production in Alberta contains varying percentages of acid gas components, specifically hydrogen sulphide (H2S) and carbon dioxide (CO2). In order for this raw sour natural gas to meet pipeline and sales gas specifications, it must pass through gas processing and treating facilities which separate out the acid gas components. Prior to 1988, if sulphur recovery technology could not economically remove the sulphur from the acid gas, the alternative was to burn the acid gas in flare stacks or incinerators. Each point source of flaring was permitted to emit up to 10 tonnes per day of sulphur. In order to reduce the waste and pollution resulting from this sour gas flaring, the ERCB issued Informational Letter (IL) 88-13, in August 1988, which outlined a new set of sulphur recovery guidelines for sour gas plants in Alberta. These guidelines stated that new gas plants with a sulphur throughput of 1 or more tonnes per day would be required to recover sulphur (and thus remove much of the H2S) from the gas stream. Under these new guidelines gas plants with sulphur throughputs between 1 and 5 tonnes per day had to recover 70 per cent of the sulphur; those between 5 and 10 tonnes per day had to recover 90 per cent of the sulphur; and plants with greater than 10 tonnes per day had to recover more than 96 per cent of the sulphur. Even with sulphur recovery in place, these plants still generate significant volumes of tail gas (acid gas) that is then burned in incinerators and emitted to the atmosphere in the form of sulphur dioxide (SO2) and CO2. There are also a number of locations in Alberta that continue to burn uneconomic volumes of sour gas (natural gas with H2S in it) and acid gas (primarily H2S and CO2). The current EUB regulations do not require sulphur recovery at gas plants with inlet gas streams containing less than 1 tonne per day of sulphur. In such cases acid gas is removed from the raw sour gas stream and is burned at gas plant flare stacks. Often additional fuel gas is needed to assist combustion and this adds to the atmospheric emissions of CO2. Furthermore, a number of sour oil well batteries throughout the province are not tied into gas gathering systems and as a result, sour solution gas produced with the oil is flared from stacks at these battery sites. P. 181