CO2 Injection for Enhanced Gas Recovery and Geological Storage of CO2 in the Long Coulee Glauconite F Pool, Alberta

Abstract

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.

Enhanced gas recovery with CO2 sequestration: The effect of medium heterogeneity on the dispersion of supercritical CO2–CH4

“…Physical dispersion at smaller length scales is also important because, as discussed below, the description of transport at the core scale can play an important role in the prediction of mixing at the field scale, particularly for carbonate formations. These challenges to describing the mixing of CO 2 and natural gas have limited EGR projects to only a few field trials (Pooladi-Darvish et al, 2008;Vandeweijer et al, 2011). The only current field-scale EGR project is the Rotliegend K12-B gas reservoir, located offshore of the Netherlands, which started in 2004 after 17 years of conventional gas production (Vandeweijer et al, 2011).…”

“…The EGR process began by injecting produced CO 2 into the formation of this depleted gas reservoir, improving the gas recovery along with CO 2 sequestration. A Canadian depleted gas reservoir was also used for an EGR/CO 2 sequestration trial in 2002 but the operation was terminated after three years due to the early CO 2 breakthrough into the producing wells (Pooladi-Darvish et al, 2008). Both of these two EGR field trials were implemented in sandstone formations, and carbonate reservoirs have not yet been considered for any EGR projects, largely due to their inherent heterogeneity and fluid flow and transport complexity.…”

Screening and selection criteria, and characterisation techniques for the geological sequestration of carbon dioxide (CO2)

“…In these cases, sites must meet an additional set of criteria very specific to the respective process of enhanced oil or gas recovery. use of cO 2 in enhanced gas recovery has not been practised to date, and it is questionable because gas reservoirs have a high recovery factor (greater than 80 %) and because, at the low reservoir pressures attained at this stage of production, cO 2 will expand quickly in the reservoir and will be produced together with the remaining gas (e.g., Pooladi-Darvish et al, 2008), hence necessitating additional separating facilities and recirculating the produced cO 2 . Thus, cO 2 will most likely be stored in gas reservoirs after abandonment (depletion).…”

Quantitative dependence of CH4‐CO2 dispersion on immobile water fraction

“…Since 2004 a total of 90 kT of CO 2 has been injected . A Canadian depleted gas reservoir was also used for an EGR/CO 2 sequestration trial in 2002; however, the operation was terminated after 3 years due to early CO 2 breakthrough at the natural gas production wells . Nevertheless, the outlook for EGR remains generally positive: a recent review of active CO 2 storage sites including the K12‐B EGR operation, established that they do not have a negative impact on the environment and considerations regarding such operations are now extending to include site closure at the end of the injection period .…”