Effects of temperature and CO2/Brine cycles on CO2 drainage endpoint phase mobility – implications for CO2 injectivity in deep saline aquifers

2021 ◽  
Vol 112 ◽  
pp. 103491
Paul Tawiah ◽  
Hongqian Wang ◽  
Steven L. Bryant ◽  
Mingzhe Dong ◽  
Steve Larter ◽  
2017 ◽  
Vol 57 (1) ◽  
pp. 100 ◽  
Emad A. Al-Khdheeawi ◽  
Stephanie Vialle ◽  
Ahmed Barifcani ◽  
Mohammad Sarmadivaleh ◽  
Stefan Iglauer

CO2 migration and storage capacity are highly affected by various parameters (e.g. reservoir temperature, vertical to horizontal permeability ratio, cap rock properties, aquifer depth and the reservoir heterogeneity). One of these parameters, which has received little attention, is brine salinity. Although brine salinity has been well demonstrated previously as a factor affecting rock wettability (i.e. higher brine salinity leads to more CO2-wet rocks), its effect on the CO2 storage process has not been addressed effectively. Thus, we developed a three-dimensional homogeneous reservoir model to simulate the behaviour of a CO2 plume in a deep saline aquifer using five different salinities (ranging from 2000 to 200 000 ppm) and have predicted associated CO2 migration patterns and trapping capacities. CO2 was injected at a depth of 1408 m for a period of 1 year at a rate of 1 Mt year–1 and then stored for the next 100 years. The results clearly indicate that 100 years after the injection of CO2 has stopped, the salinity has a significant effect on the CO2 migration distance and the amount of mobile, residual and dissolved CO2. First, the results show that higher brine salinity leads to an increase in CO2 mobility and CO2 migration distance, but reduces the amount of residually trapped CO2. Furthermore, high brine salinity leads to reduced dissolution trapping. Thus, we conclude that less-saline aquifers are preferable CO2 sinks.

2011 ◽  
Vol 38 (6) ◽  
pp. n/a-n/a ◽  
W. J. Rayward-Smith ◽  
Andrew W. Woods

Geofluids ◽  
2017 ◽  
Vol 2017 ◽  
pp. 1-16 ◽  
Yuan Wang ◽  
Jie Ren ◽  
Shaobin Hu ◽  
Di Feng

Salt precipitation is generated near the injection well when dry supercritical carbon dioxide (scCO2) is injected into saline aquifers, and it can seriously impair the CO2 injectivity of the well. We used solid saturation (Ss) to map CO2 injectivity. Ss was used as the response variable for the sensitivity analysis, and the input variables included the CO2 injection rate (QCO2), salinity of the aquifer (XNaCl), empirical parameter m, air entry pressure (P0), maximum capillary pressure (Pmax), and liquid residual saturation (Splr and Sclr). Global sensitivity analysis methods, namely, the Morris method and Sobol method, were used. A significant increase in Ss was observed near the injection well, and the results of the two methods were similar: XNaCl had the greatest effect on Ss; the effect of P0 and Pmax on Ss was negligible. On the other hand, with these two methods, QCO2 had various effects on Ss: QCO2 had a large effect on Ss in the Morris method, but it had little effect on Ss in the Sobol method. We also found that a low QCO2 had a profound effect on Ss but that a high QCO2 had almost no effect on the Ss value.

2013 ◽  
Vol 3 (4) ◽  
Reza Azin ◽  
Mohamad Mahmoudy ◽  
Seyed Raad ◽  
Shahriar Osfouri

AbstractStorage of CO2 in deep saline aquifers is a promising techniques to mitigate global warming and reduce greenhouse gases (GHG). Correct measurement of diffusivity is essential for predicting rate of transfer and cumulative amount of trapped gas. Little information is available on diffusion of GHG in saline aquifers. In this study, diffusivity of CO2 into a saline aquifer taken from oil field was measured and modeled. Equilibrium concentration of CO2 at gas-liquid interface was determined using Henry’s law. Experimental measurements were reported at temperature and pressure ranges of 32–50°C and 5900–6900 kPa, respectively. Results show that diffusivity of CO2 varies between 3.52–5.98×10−9 m2/s for 5900 kPa and 5.33–6.16×10−9 m2/s for 6900 kPa initial pressure. Also, it was found that both pressure and temperature have a positive impact on the measures of diffusion coefficient. Liquid swelling due to gas dissolution and variations in gas compressibility factor as a result of pressure decay was found negligible. Measured diffusivities were used model the physical model and develop concentration profile of dissolved gas in the liquid phase. Results of this study provide unique measures of CO2 diffusion coefficient in saline aquifer at high pressure and temperature conditions, which can be applied in full-field studies of carbon capture and sequestration projects.

2015 ◽  
Vol 51 (4) ◽  
pp. 2595-2615 ◽  
Hamid Emami‐Meybodi ◽  
Hassan Hassanzadeh ◽  
Jonathan Ennis‐King

2017 ◽  
Vol 21 (6) ◽  
pp. 2751-2775 ◽  
Alexander Kissinger ◽  
Vera Noack ◽  
Stefan Knopf ◽  
Wilfried Konrad ◽  
Dirk Scheer ◽  

Abstract. Saltwater intrusion into potential drinking water aquifers due to the injection of CO2 into deep saline aquifers is one of the hazards associated with the geological storage of CO2. Thus, in a site-specific risk assessment, models for predicting the fate of the displaced brine are required. Practical simulation of brine displacement involves decisions regarding the complexity of the model. The choice of an appropriate level of model complexity depends on multiple criteria: the target variable of interest, the relevant physical processes, the computational demand, the availability of data, and the data uncertainty. In this study, we set up a regional-scale geological model for a realistic (but not real) onshore site in the North German Basin with characteristic geological features for that region. A major aim of this work is to identify the relevant parameters controlling saltwater intrusion in a complex structural setting and to test the applicability of different model simplifications. The model that is used to identify relevant parameters fully couples flow in shallow freshwater aquifers and deep saline aquifers. This model also includes variable-density transport of salt and realistically incorporates surface boundary conditions with groundwater recharge. The complexity of this model is then reduced in several steps, by neglecting physical processes (two-phase flow near the injection well, variable-density flow) and by simplifying the complex geometry of the geological model. The results indicate that the initial salt distribution prior to the injection of CO2 is one of the key parameters controlling shallow aquifer salinization. However, determining the initial salt distribution involves large uncertainties in the regional-scale hydrogeological parameterization and requires complex and computationally demanding models (regional-scale variable-density salt transport). In order to evaluate strategies for minimizing leakage into shallow aquifers, other target variables can be considered, such as the volumetric leakage rate into shallow aquifers or the pressure buildup in the injection horizon. Our results show that simplified models, which neglect variable-density salt transport, can reach an acceptable agreement with more complex models.

Sign in / Sign up

Export Citation Format

Share Document