Impure CO2 containing less than 2% H2S has been injected since 2002 into the depleted Long Coulee Glauconite F gas Pool in southeastern Alberta. Breakthrough was observed within one to three years in producing wells, leading to their abandonment. Simulation studies reported in this paper indicate that additional gas was recovered as a result of CO2 injection. An interesting observation at the breakthrough wells was that the CO2 broke through ahead of the H2S. The partitioning of the H2S and CO2 as they flow through the reservoir was studied in detail. One objective of the reported work is examination of interactions of the injected gas with the in-situ fluids and the displacement of the in-situ gas by the injection gas, for better understanding of the mechanisms involved in enhanced-gas recovery. Another objective of the work is to study factors that affect the spread of the injected gas in a depleted oil and gas reservoir and its implications with respected to CO2 geological storage. The results of this study indicate that at low pressures, the injected gas occupies a large reservoir volume and exhibits little density difference with the in-situ fluids, leading to rapid spread of the injected gas and early breakthrough. Also, it was found that in the case of Long Coulee Glauconite F gas Pool the well-spacing used for production did not allow a detailed geological characterization that was required for accurate prediction of breakthrough as a result of gas-gas displacement. Simulation studies, together with displacement experiments in the laboratory reported elsewhere, confirmed that the preferential solubility of H2S in the reservoir water led to stripping of the H2S at the leading gas front and it delayed its breakthrough relative to that of CO2. The implications of such chromatographic partitioning of H2S and CO2 in geological storage of impure CO2 streams are discussed. Introduction Carbon dioxide capture and storage in geological formations is considered to be one of the practical options for reducing atmospheric greenhouse gas emissions. A number of operators in Alberta have implemented injection into depleted gas and oil pools as a means of disposal and storage of acid gas, which is a mixture of H2S and CO2 stripped off produced sour gas before sending the natural gas to markets (Bachu and Gunter 2005). In many cases the composition of the injected gas is similar to that of impure CO2 in that the majority of the injected gas is CO2. For example, in the Long Coulee Glauconite F Pool in southeastern Alberta (Figure 1), CO2 concentration in the injected gas is about 98% (with H2S making up the majority of the balance). Significant interest has been shown in the study of these reservoirs as commercial-scale analogues for geological storage of CO2 (Bachu and Gunter 2005, Bachu and Haug 2005). The authors have studied five of these projects where either breakthrough of the injected gas in producing wells, or significant pressurization was observed. One objective of this paper is to examine the behavior of the Long Coulee Glauconite F Pool for the purpose of better understanding the spread of impure CO2 in a depleted oil and gas reservoir and its implications with respected to CO2 geological storage. In addition, CO2 injection could provide the opportunity for enhanced gas recovery (Mamora and Seo 2002, Oldenburg 2003, Sim et al. 2008). As we shall see, the modeling study indicates that additional gas was recovered as a result of the injection process. The second objective of this paper is to investigate enhanced gas recovery as a result of displacement of the in-situ gas by the injected gas. Special attention was given to better understanding of the mechanisms that lead to mixing of the injected gas and the in-situ fluids as this affects the spread of the injected gas and the recovery of the in-situ fluids. In the following the history of Long Coulee Glauconite F Pool is presented briefly, followed by basic fluid and reservoir characterization. The simulation and associated sensitivity studies, as well as their use for better understanding of the spread of the injected gas and displacement of the in-situ gases, are then presented.
Hydrogen sulfide breakthrough in producing wells occurred after the breakthrough of CO2 in the Long Coulee Glauconite F reservoir in southern Alberta, where acid gas (98% CO2, 2% H2S) has been injected since 2002. It was hypothesized that the preferential solubility of H2S in formation brine is responsible for the delay in H2S breakthrough. To study the chromatographic separation of H2S and CO2, a series of experiments were conducted to measure the solubility of CO2 and H2S in formation brine at in-situ conditions. Immiscible displacement experiments were performed in a slim tube packed with silica sand to study the breakthrough behaviour of different gas components. The experiments were then modelled using a compositional simulator, and the effect of different factors on the delayed breakthrough of H2S was examined using a series of sensitivity studies. It was confirmed that the preferential solubility of H2S over CO2 leads to it being stripped off at the leading edge of the gas displacement front, resulting in its delayed breakthrough. A similar delay in H2S breakthrough occurs even at higher H2S concentrations (e.g. 30%) in the injected gas. Through the simulation studies it was shown that the delay in H2S breakthrough becomes more pronounced if the gas front is more diffusive. For example, it was shown that, when gravity forces or mobility ratio favour stable displacement, CO2 and H2S breakthroughs occur closer to each other. This is of significance, particularly for monitoring of impure CO2 storage in deep saline aquifers, where the impurity may consist of H2S. Detection of CO2 at a monitoring well would indicate that the more noxious H2S is likely to show up after some time lag. This paper describes the experiments and the simulation studies and presents the implications of the chromatographic partitioning of H2S and CO2 for geological storage of acid gas or impure CO2.
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 10 3 m 3 /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.
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 CO 2 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 CO 2 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 CO 2 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 CO 2 surface facilities. It may also help engineering and operations personnel, as well as regulatory agencies to understand the complex behavior of CO 2 injection wells.Pressure gradients in aquifers or reservoirs suitable for CO 2 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 10 3 m 3 /d. Three sensitivity studies illustrate the impact of bottomhole sandface pressure, CO 2 stream composition and wellhead temperature on wellhead pressure. Depending on conditions, the CO 2 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. IntroductionUnderground injection and storage is a highly specialized method of dealing with the hydrogen sulphide (H2S) and carbon dioxide (CO 2 ) "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 10 3 m 3 /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 10 3 ...
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