September 11, 2012
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.
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.
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.
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).