Numerical simulations of pressure buildup and salt precipitation during carbon dioxide storage in saline aquifers

Meng, Qingliang; Jiang, Xi; Li, Didi; Xie, Qiyuan

doi:10.1016/j.compfluid.2015.08.012

Cited by 8 publications

(3 citation statements)

References 31 publications

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“…The pressure buildup region extends further than that of the acid gas plume, which is in agreement with existing research results (Birkholzer et al, 2009;Liu et al, 2018;Meng et al, 2015). In response to acid gas injection, the fluid pressure in the storage formation reached maximum values of approximately 0.285 bar near the injection zone.…”

Section: Discussionsupporting

confidence: 92%

“…As investigated in the literature (Meng et al, 2015;Pruess and García, 2002;Pruess and Müller, 2009;Zhao and Cheng, 2017), salt precipitation is caused at the dry-out region near the injection well where liquid saturation is lower than the residual water saturation. The formation porosity and permeability may be reduced by solid salt precipitation.…”

Section: Discussionmentioning

confidence: 99%

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Numerical simulation and feasibility assessment of acid gas injection in a carbonate formation of the Tarim Basin, China

Zhang

Zheng

et al. 2020

Oil Gas Sci. Technol. – Rev. IFP Energies nouvelles

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An enormous amount of acid gas, containing carbon dioxide (CO2) and hydrogen sulfide (H2S), is generated in the exploitation of oil and gas reservoirs in the Tarim Basin, China. An appropriate management plan is required to safely dispose of the acid gas, and common strategy considered for the safe disposal of acid gas is the injection of it into deep formations – this strategy mitigates greenhouse gas emissions and avoids costs associated with desulfurization. A feasibility assessment of acid gas injection requires a detailed investigation of the potential physical and geochemical impacts. Reactive transport simulations based on the mineralogical composition and the hydrochemical characteristics of a carbonate formation in the Tarim Basin were conducted to identify the physical and geochemical interactions of acid gas with the mineral matrix and formation water. Acid gas (59% CO2 and 41% H2S) was injected at a constant rate of 19 200 Nm3/d for 25 years, and the simulation was run by the TMVR_EOSG module of the TOUGHREACT code for a period of 10 000 years. The results indicate that the minimum liquid saturation is much larger than the residual water saturation, and the pressure buildup is below the allowable pressure increase. Additionally, the porosity change is found to be negligible due to the small changes in calcite and quartz in the volume fraction. From this perspective, acid gas injection in the carbonate formation of the Tarim Basin seems feasible. Furthermore, the fast breakthrough of CO2 can provide an advanced warning of a potential breakthrough of acid gas. Last, the injection rate can be increased to accelerate acid gas trapping, and the results could be used as guidance for future acid gas injection operations.

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Section: Discussionsupporting

confidence: 92%

Section: Discussionmentioning

confidence: 99%

Numerical simulation and feasibility assessment of acid gas injection in a carbonate formation of the Tarim Basin, China

Zhang

Zheng

et al. 2020

Oil Gas Sci. Technol. – Rev. IFP Energies nouvelles

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“…Clogging of pores in the near-well region is a long-standing research topic, especially in the context of oil and gas production, and can be caused by a number of effects such as mineral/salt precipitation, hydrate/ice formation, filtrated mud particles and precipitation of asphaltenes. The particular case of salt precipitation during CO2 injection for storage has received less attention, but some work has been undertaken using laboratory-scale experiments [4,5], larger field experiments [3] as well as reservoir flow simulations [6][7][8][9]. The latter has usually been done with simulators initially built for studying other phenomena such as nuclear waste disposal safety, where CO2 injection capabilities have been added later.…”

Section: Introductionmentioning

confidence: 99%

Thermo-Fluid-Dynamical Modelling of Salt Precipitation During Co2 Injection in Saline Aquifers, and the Effect on Injectivity

et al. 2019

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CO2 injection is a crucial part of CCS technology. To enable the injection and storage of many gigatonnes of CO2 per year, a large number of injection wells are needed, and it is important to understand the physics of CO2 injection in general and of salt precipitation in particular. Salt precipitation in the near-well region can lead to reduced permeability and subsequent reservoir damage. To be able to consistently model the salt precipitation, it is necessary to combine highly accurate equations of state (EoS) for the thermodynamic properties and phase compositions together with the fluid-dynamical models in a consistent fashion. The present work develops such a combination which enables the simulation of injection with analysis of the precipitation and injectivity loss, and thus makes possible parameters studies to identify the cases where precipitation is an operational risk.

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Optimization of acid gas injection to improve solubility and residual trapping

Zhang

Wei

2021

Greenhouse Gases

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In acid gas injection, the solubility and residual trapping of acid gas can be effectively improved by optimizing the acid gas injection, which is important for short-term storage of acid gas and reducing the risk of acid gas leakage. The current study numerically investigates three different acid gas injection schemes, namely continuous acid gas injection, intermittent acid gas injection, and water alternating gas injection. The results suggest that the continuous acid gas injection with higher injection rate is slightly conducive to the solubility and residual trapping of acid gas. In particular, Continuous injection-Case1 with a rate of 19 200 Nm 3 d −1 reduces mobile acid gas by 1.82% and enhances residual trapping by 1.25%. While the intermittent acid gas injection can hardly improve the solubility and residual trapping of acid gas. Water alternating gas injection scheme shows superior behavior over other schemes. Specially, the Water alternating gas injection-Case3 with higher water injection rate is the most effective, which can reduce mobile acid gas by 13.66% and enhance solubility trapping by 23.95%. The acid gas plume is funnel-shaped in the acid gas injection stage. However, in the subsequent water injection stage, the acid gas plume gradually becomes fan shaped. This is because the injected water accelerates the dissolution of the acid gas, causing almost all the rear of the acid gas plume to dissolve in the water. Thus, we conclude that water alternating gas injection scheme can significantly enhance the acid gas trapping and Water alternating gas injection Case 3 is the preferred injection scheme.

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Numerical simulations of pressure buildup and salt precipitation during carbon dioxide storage in saline aquifers

Cited by 8 publications

References 31 publications

Numerical simulation and feasibility assessment of acid gas injection in a carbonate formation of the Tarim Basin, China

Numerical simulation and feasibility assessment of acid gas injection in a carbonate formation of the Tarim Basin, China

Thermo-Fluid-Dynamical Modelling of Salt Precipitation During Co2 Injection in Saline Aquifers, and the Effect on Injectivity

Optimization of acid gas injection to improve solubility and residual trapping

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