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Abstract
This paper presents insights gained from analyzing and modeling acid gas (H2S and CO2) injection well performance over the last 13 years. As the world increasingly develops oil and gas reservoirs that contain significant concentrations of H2S and CO2, the number and size of acid gas injection facilities and their associated acid gas injection wells will increase. A methodology to estimate wellhead operating pressures satisfies a key requirement for design of the injection wells and sizing of the acid gas injection compressors. It may also help inform engineering and operations personnel, and regulatory agencies, of the complex behaviour of acid gas injection wells.

The initial impetus for this work was an operator who increased the acid gas injection rate on a well yet saw virtually no change in wellhead operating pressure, which is inconsistent with water injection well operations. To predict wellhead pressures, a numerical simulation model integrates a modified Peng-Robinson equation-of-state for fluid phase behaviour with a wellbore model and a multi-step adaptation of the Cullender and Smith method to account for the friction and hydrostatic pressure changes associated with flow in the wellbore.

Pressure gradients in aquifers or reservoirs suitable for acid gas sequestration may range from a normal hydrostatic gradient to extremely sub-normal in depleted hydrocarbon reservoirs. Two injection cases present wellbore pressure profiles for injection into a depleted and a normally pressured reservoir at rates of 20, 100 and 280 103m3/d. Three sensitivity studies illustrate the impact of bottomhole sandface pressure, fluid composition and wellhead temperature on wellhead pressure. Depending on conditions, injected acid gas may undergo phase transitions from a gaseous or two-phase mixture at the wellhead to liquid at the sandface and back to gaseous or supercritical out in the reservoir. The complex interactions between temperature, phase behavior, fluid density and pressure can lead to unusual operating characteristics including an increased injection rate or sandface pressure with little or no change in wellhead pressure.

Introduction
Production of oil and gas reservoirs that contain 3 to 35% hydrogen sulphide and carbon dioxide in the produced “sour” gas has been ongoing for over 50 years in Alberta, Canada. The development of amine and other gas “sweetening” technologies has enabled the removal of the H2S and CO2 components from the raw inlet production stream to the gas plant. Sweetening is the first step in deriving saleable hydrocarbon products from sour gas.

Acid gas injection is a highly specialized method of dealing with the effluent stream that is typically discharged from the sour gas amine reboiler or similar chemical sweetening process. Acid gas injection was initially developed for small “nuisance” volumes of acid gas, typically less than 14 103m3/d (500 Mscfd), that were too large to vent directly to atmosphere but were too small to justify processing through a Claus sulphur plant. However, since the 1990’s a worldwide increase in sulphur supply and ongoing market volatility has increasingly led to investigation of acid gas injection and sequestration as an alternative to a Claus plant and long term surface stockpiling of elemental sulphur.

Puik and Braithwaite (2007) conclude that new approaches to sulphur management, including acid gas injection and the application of new sulphur products, are required because planned sour oil and gas developments will double globally traded sulphur volumes over the next ten years. The underground storage of large volumes of acid gas also provides the option of future sulphur recovery from the gas should market conditions become favorable.