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Abstract
This paper uses the experience gained over the past 13 years in analyzing and modeling wells that inject mixtures of hydrogen sulphide and carbon dioxide from sour gas plants to model the operating performance of injection wells for long term CO2 sequestration from electrical power plants. To predict wellhead pressures, a numerical simulation model integrates a modified Peng-Robinson equation-of-state for fluid phase behavior 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.

As the world embarks on large scale capture and injection of CO2 emissions from electrical power plants, understanding the operating characteristics of the injection well(s) will be critical to the design, construction and operation of these systems. Unlike water injection wells, increasing the injection rate for a CO2 well does not necessarily increase its wellhead operating pressure. A methodology to estimate wellhead operating pressures is a key requirement for the proper design of the injection wells and the CO2 surface facilities. It may also help engineering and operations personnel, as well as regulatory agencies to understand the complex behavior of CO2 injection wells.

Pressure gradients in aquifers or reservoirs suitable for CO2 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, CO2 stream composition and wellhead temperature on wellhead pressure. Depending on conditions, the CO2 stream may undergo phase transitions from a gas or liquid at the wellhead to dense phase fluid in the wellbore and back to gaseous or supercritical out in the reservoir. The complex interactions between phase behavior, fluid density and pressure can lead to unexpected operating characteristics, including an increase in injection rate or sandface pressure with little or no change in wellhead injection pressure.

Introduction
Underground injection and storage is a highly specialized method of dealing with the hydrogen sulphide (H2S) and carbon dioxide (CO2) “acid gas” by-products from a sour gas processing plant. Underground 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; the conventional method of treating H2S.

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 storage as an alternative to all sizes of Claus plants and long-term surface stockpiling of elemental sulphur. Wall and Kenefake (2005) describe a 1,845 103m3/d (65 MMscfd) acid gas injection facility in Southwestern Wyoming, United States that commenced operation in 2005 to replace aging Claus sulphur recovery units.
Sourisseau et al. (2000) discuss acid gas injection trains sized for 2,310 103m3/d (84 MMscfd) that are part of a new 22,500 103m3/d (866 MMscfd) sour gas development in Abu Dhabi.