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.
The main objectives of “Independent Verification of Safety Critical Elements” are to help substantiate that current oil and gas best practices are used, to provide assurance that facilities have been designed to operate safely throughout and to ensure that all Health Safety and Environment risks have been managed to acceptable / As Low As Reasonably Practicable levels. It anticipates the lack of applicable laws or standards, especially in the case of new environments. This approach, which was initially introduced in the United Kingdom after Piper Alpha disaster in 1988, is now becoming an industry standard worldwide. Offshore Russia offers extreme (remote and arctic) conditions which are a challenge today. This, and the lack of Russian Federation laws applicable to the control of Major Accident Hazards, may represent an issue regarding Health, Safety and Environment for operating companies. This paper will describe the history of independent verification, and particularly show its application on the Front End Engineering Design stage of a project lead in Russia. It will highlight the regulatory differences and the value of a goal setting process in such situations. This article shows an example of implementation in a country unfamiliar with independent verification.
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