CO2 storage in depleted gas reservoirs: A study on the effect of residual gas saturation

Depleted gas reservoirs are recognized as the most promising candidate for carbon dioxide storage. Primary gas production followed by injection of carbon dioxide after depletion is the strategy adopted for secondary gas recovery and storage practices. This strategy, however, depends on the injection strategy, reservoir characteristics and operational parameters. There have been many studies to-date discussing critical factors influencing the storage performance in depleted gas reservoirs while little attention was given to the effect of residual gas. In this paper, an attempt was made to highlight the importance of residual gas on the capacity, injectivity, reservoir pressurization, and trapping mechanisms of storage sites through the use of numerical simulation. The results obtained indicated that the storage performance is proportionally linked to the amount of residual gas in the medium and reservoirs with low residual fluids are a better choice for storage purposes. Therefore, it would be wise to perform the secondary recovery before storage in order to have the least amount of residual gas in the medium. Although the results of this study are useful to screen depleted gas reservoirs for the storage purpose, more studies are required to confirm the finding presented in this paper

Potential evaluation on CO 2 -EGR in tight and low-permeability reservoirs

CO2-EGR, i.e. enhanced gas recovery by injecting CO2, is to displace natural gas by injecting CO2 in the supercritical phase. It can both enhance the recovery of gas reservoirs and realize CO2 storage. Currently, this technique is still at its exploring stage. The effect of CO2-EGR is not clarified, the geologic conditions for CO2-EGR are not definite, and the rational working system for CO2-EGR is not available. In this paper, the long-core experiment was conducted to determine whether and how much the recovery of low-permeability reservoirs can be enhanced by injecting CO2. According to the experimental results, the recovery can be enhanced by 12% when CO2 content in produced gas is more than 10%. Moreover, the multi-component seepage mathematical model was built for displacing natural gas by injecting supercritical CO2, and the model accuracy was verified using laboratory data. With this mathematical model, the influence factors for displacing natural gas by injecting supercritical CO2 were analyzed in order to define the conditions for selecting favorable zones. The Well DK13 area in the Daniudi gas field, Ordos Basin, was selected for potential evaluation of CO2-EGR. As indicated by the numerical simulation results, when CO2 content of producing wells in the Well DK13 area is 10% (with a lower cost for corrosion prevention), the ratio of CO2-EGR is 8.0–9.5%, and 31.1% HCPV(hydrocarbon pores volume) of CO2 storage can be realized. It is thus concluded that the CO2-EGR technique can enhance the recovery of gas reservoirs and also store CO2 underground, contributing to the increase of both social and economic benefits

The role of N2 as booter gas during Enhanced Gas Recovery by CO2 flooding in a porous medium

Most research on CO2 flooding is focusing on CO2 storage than CH4 recovery and mostly simulation-based. To our knowledge, there have been limited reported experimental on CO2 injections capable of unlocking a high amount of the residual methane due to their miscibility effect. The empirical study has highlighted the impact of N2 as a buster gas during the Enhanced Gas Recovery (EGR) process by CO2 flooding. The N2 acts as a buster by re-pressurising the reservoir pressure before the CO2 breakthrough, enabling more CH4 recovery. It also acts as a retardant by creating a thin barrier at the CO2–CH4 interface, making it difficult for the CO2 to disperse into the CH4. This result in an extendable breakthrough, influencing the injected CO2 to migrate downward due to gravity for storage within the pore spaces. This study, a core flooding experiment at 1500 psig and 40 °C of pressure and temperature, respectively, was carried out to study the effect of N2 as buster gas during natural displacement in a porous medium (sandstone rock). The recoveries with N2 buster were better off than those without N2 buster (conventional CO2 flooding). Overall, an improved CH4 recovery and dispersion coefficient with substantial storage was noticed, with the optimum at 0.13 fraction of pore volume buster gas. Compared to the 0.4 ml/min optimum conventional CO2 injection, the results show a 10.64 and 24.84% increase in CH4 recovery and CO2 storage, respectively. 0.71 × 10-8 m2/s reduction in dispersion coefficient was recorded than the convention method. The additional CH4 recovery can provide extra revenue to offsets other operational expenses. This research signifies the potential of N2 as a buster medium on CH4 recovery, which can be applicable for pilot application within the oil and gas industry

Suitability of depleted gas reservoirs for geological CO2 storage: A simulation study

Hydrocarbon reservoirs, particularly depleted gas formations, are promising geological sites for CO2storage. Although there have been many studies on the storage aspects of gas reservoirs, the suitability of these formations in terms of fluid types such as dry, wet, and condensate gas has not been properly addressed at the reservoir level. In this study, an attempt was made to evaluate different gas reservoirs in order to provide an insight into their storage capabilities. A dynamic numerical simulation was carried out to simulate CO2injection in a synthetic but realistic model of a geologic formation having dry, wet, or condensate gas. The results obtained under particular conditions revealed that the condensate gas medium offers a good storage potential, favorable injectivity, and reasonable pressure buildup over a long period of time, whereas dry gas formations were found to be the least favorable sites for storage among gas reservoirs. A sensitivity analysis was done to evaluate the injection rate and the permeability variation of different media during and after the storage. It indicated that the storage behavior of gas reservoirs is sensitive to the injection rate, and selection of an optimum injection rate might help to achieve a good storage capacity in condensate gas systems. The results also highlighted that CO2immobilization in gas reservoirs after injection is enhanced due to the reduction of permeability, whereas no heterogeneity effect was observed under different permeability realizations

Coupled thermo–hydro–mechanical simulation of CO 2 enhanced gas recovery with an extended equation of state module for TOUGH2MP-FLAC3D

As one of the most important ways to reduce the greenhouse gas emission, carbon dioxide (CO₂) enhanced gas recovery (CO₂-EGR) is attractive since the gas recovery can be enhanced simultaneously with CO₂ sequestration. Based on the existing equation of state (EOS) module of TOUGH2MP, extEOS7C is developed to calculate the phase partition of H₂O–CO₂–CH₄–NaCl mixtures accurately with consideration of dissolved NaCl and brine properties at high pressure and temperature conditions. Verifications show that it can be applied up to the pressure of 100 MPa and temperature of 150 °C. The module was implemented in the linked simulator TOUGH2MP-FLAC3D for the coupled hydro–mechanical simulations. A simplified three-dimensional (3D) 1/4 model (2.2 km × 1 km × 1 km) which consists of the whole reservoir, caprock and baserock was generated based on the geological conditions of a gas field in the North German Basin. The simulation results show that, under an injection rate of 200,000 t/yr and production rate of 200,000 sm³/d, CO₂ breakthrough occurred in the case with the initial reservoir pressure of 5 MPa but did not occur in the case of 42 MPa. Under low pressure conditions, the pressure driven horizontal transport is the dominant process; while under high pressure conditions, the density driven vertical flow is dominant. Under the considered conditions, the CO₂-EGR caused only small pressure changes. The largest pore pressure increase (2 MPa) and uplift (7 mm) occurred at the caprock bottom induced by only CO₂ injection. The caprock had still the primary stress state and its integrity was not affected. The formation water salinity and temperature variations of ±20 °C had small influences on the CO2-EGR process. In order to slow down the breakthrough, it is suggested that CO₂-EGR should be carried out before the reservoir pressure drops below the critical pressure of CO₂