Deep Injection of Acid Gas (H2S) in Western Canada

Acid-gas injection operations constitute a commercial-scale analogue for CO₂ geological sequestration in sedimentary basins.

Acid gas is a mixture of hydrogen sulphide (H₂S) and carbon dioxide (CO₂), with minor traces of hydrocarbons, which is the by-product of “sweetening” sour hydrocarbons.

In-Situ Characteristics of Acid-Gas Injection Operations in Western Canada

Location of acid-gas injection operations in Canada at the end of 2003.

Over the past decade, oil and gas producers in western Canada have been faced with a growing challenge to reduce atmospheric emissions of H₂S, which is produced from “sour” hydrocarbon pools. Sour oil and gas are hydrocarbons that contain H₂S and CO₂, which have to be removed before the produced oil or gas is sent to markets. Since surface desulphurization through the Claus process is generally uneconomical, and the surface storage of the produced sulphur constitutes a liability, more operators are turning to acid gas disposal by injection into deep geological formations. In addition to providing a cost-effective alternative to sulphur recovery, the deep injection of acid gas reduces emissions of noxious substances into the atmosphere and alleviates the public concern resulting from sour gas production and flaring.

Location and status of acid-gas injection operations in western Canada at the end of 2003.

Although the purpose of the acid-gas injection operations is to dispose of H₂S, significant quantities of CO₂ are being injected at the same time because it is costly to separate the two gases. In the context of current efforts to reduce anthropogenic emissions of CO₂, these acid-gas injection operations represent an analogue to geological storage of CO₂. Large-scale injection of CO₂ into depleted oil and gas reservoirs and into deep saline aquifers is one of the most promising methods of geological storage of CO₂, and in this respect, it is no different from acid-gas injection operations. Thus, the study of the acid-gas injection operations in western Canada provides the opportunity to learn about the safety of these operations and about the fate of the injected gases, and represents a unique opportunity to investigate the feasibility of CO₂ geological storage. Acid gas injection currently occurs at 39 active operations in Alberta and northeastern British Columbia.

In their pure state, CO₂ and H₂S have similar volatility, but at different pressures and temperatures. They exhibit the normal vapour/liquid behaviour with pressure and temperature, with CO₂ condensing at lower temperatures than H₂S. Methane (CH₄) also exhibits this behaviour, but at much lower temperatures. The phase behaviour of the acid gas system is represented by a continuous series of two-phase envelopes (separating the liquid and gas phases), located between the bounding systems in the pressure-temperature space. If water is present, both CO₂ and H₂S form hydrates at temperatures up to 10°C for CO₂ and more than 30°C for H₂S. If there is too little water, the water is dissolved in the acid gas and hydrates will generally not form. These properties of the acid gas dictate surface engineering and injection strategies and technology.

Phase behaviour of methane (CH4), carbon dioxide (CO2) and hydrogen sulphide (H2S), and of an acid gas mixture.

Representation of a four-stage compression cycle for acid gas delivered at the well head.

Typically, four stages of compression are required to provide the required discharge pressure above the bubble point of the acid gas mixture. Each compression cycle is generally kept at a higher temperature than the stability field for hydrates, to prevent compressor breakdown and plugging.

In Alberta, applications for acid gas disposal need to conform to the specific requirements listed in ERCB Directive 65 (Alberta Energy and Utilities Board, Guide 65: Resources Applications for Conventional & Gas Reservoirs, Calgary, AB, 2000). Acid-gas injection wells are classified as Class III disposal wells, unless the acid gas is dissolved in produced water prior to injection, in which case the well is designated as either Class Ib or Class II, depending on the produced-water designation (Energy Resources Conservation Board, Directive 51: Injection and Disposal Wells, Calgary, AB, 1994).

Bigoray gas plant.

Acid-gas injection well at the Bigoray gas plant.