Effect of operational parameters on the performance of carbonated water injection: Experimental and numerical modeling study

Ahmadi, Mehdi; Hasanvand, Mahdi Zeinali; Behbahani, Sara Shokrollahzadeh; Nourmohammad, Alireza; Vahidi, Akram; Amiri, Mojtaba Maali; Ahmadi, Goodarz

doi:10.1016/j.supflu.2015.07.012

Cited by 32 publications

(7 citation statements)

References 28 publications

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“…As CO 2 is dissolved in the brine phase, the IFT of crude oil/CB may significantly change compared to crude oil/CO 2 and crude oil/brine systems. Based on the results reported by Johnson et al (1952), Yang et al (2005), Riazi and Golkari (2016) and Honarvar et al (2017), it can be shown that the IFT of crude oil/CO 2 -enriched water is lower than that of crude oil/water which makes the IFT reduction a property of CB injection (Ahmadi et al 2016b;Foroozesh et al 2016;Mosavat and Torabi 2014). For instance, Riazi and Golkari (2016) and Honarvar et al (2017) measured the IFT of crude oil/carbonated and noncarbonated brine.…”

Section: Introductionmentioning

confidence: 90%

The role of CO2 and ion type in the dynamic interfacial tension of acidic crude oil/carbonated brine

2019

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The effects of CO 2 and salt type on the interfacial tension (IFT) between crude oil and carbonated brine (CB) have not been fully understood. This study focuses on measuring the dynamic IFT between acidic crude oil with a total acid number of 1.5 mg KOH/g and fully CO 2 -saturated aqueous solutions consisting of 15,000 ppm of KCl, NaCl, CaCl 2 and MgCl 2 at 30 °C and a wide range of pressures (500-4000 psi). The results of IFT measurements showed that solvation of CO 2 into all the studied aqueous solutions led to an increase in IFT of acidic crude oil (i.e., comparison of IFT of crude oil/CB and crude oil/brine), while no significant effect was observed for pressure. In contrast, the obtained results of studied salts indicated a positive effect on the IFT reduction of acidic crude oil/carbonated water (CW) (i.e., comparison of IFT of crude oil/CB and crude oil/CW).

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Section: Introductionmentioning

confidence: 90%

The role of CO2 and ion type in the dynamic interfacial tension of acidic crude oil/carbonated brine

2019

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“…due to the reduction in the interfacial tension) will lower the Swr (i.e. enhance the fluid displacements) (Ahmadi et al, 2015). On the other hand, reducing M will result in a more uniform displacement of water by CO2 , which can result in reducing the Swr.…”

Section: Effect Of Fluid Pressure Temperature and Injection Rate Onmentioning

confidence: 99%

Gaseous CO2 behaviour during water displacement in a sandstone core sample

Al-Zaidi

Edlmann

Fan

2019

International Journal of Greenhouse Gas Control

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CO2 injection into subsurface formations involves the flow of CO2 through a porous medium that also contains water. The injection, displacement, migration, storage capacity and security of CO2 is controlled mainly by the interfacial interactions and capillary, viscous, and buoyancy forces which are directly influenced by changes in subsurface conditions of pressure and temperature; the impact of bouncy forces is assumed negligible during this study. In this study, gaseous CO2 is injected into a water-saturated sandstone core sample to explore the impact of fluid pressure (40-70 bar), temperature (29-45 °C), and CO2 injection rate (0.1-2 ml/min) on the dynamic pressure evolution and displacement efficiency. This study highlights the impact of capillary or viscous forces on the two-phase flow characteristics and shows the conditions where capillary or viscous forces become more influential. The results reveal a moderate to considerable impact of the parameters investigated on the differential pressure profile, endpoint CO2 relative permeability (KrCO2 max), and irreducible water saturation (Swr). Overall, the increase in fluid pressure, temperature, and CO2 injection rate cause an increase in the maximum and final differential pressures, an increase in the KrCO2 max , a reduction in the Swr. Swr was in the range of around 0.38-0.45 while KrCO2 max was less than 0.25. The data show a significant influence for the capillary forces on the pressure and production behaviour. The capillary forces produce high oscillations in the pressure and production data while the increase in viscous forces impedes the appearance of these oscillations. The appearance and frequency of the oscillations depend on the fluid pressure, temperature, and CO2 injection rate but to different extents.

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“…In other words, CWI can be considered as an immiscible injection which includes the advantage of CO 2 diffusion from carbonated water to oil (with respect to the higher solubility of CO 2 in oil compared to water); subsequently, with more CW-oil contact time, the oil phase becomes lighter as the partitioning mechanism happens. To summarise, this method leads to higher oil recovery by swelling the oil phase, decreasing the oil viscosity and oil-water IFT, changing the wettability of reservoir rock toward more water-wet (Ahmadi 2016;Ali et al xxxx; Foroozesh and Jamiolahmady 2016; Kumar and Mandal 2017; Mosavat and Torabi 2013;Seyyedi et al 2015;Singh 2014;Sohrabi et al 2012).…”

Section: Introductionmentioning

confidence: 99%

The effect of CO2-enriched water salinity on enhancing oil recovery and its potential formation damage: an experimental study on shaly sandstone reservoirs

Sadati

Sahraei

Rahnema

et al. 2020

J Petrol Explor Prod Technol

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Many experimental investigations on carbonated water injection (CWI) have shown an increase in oil recovery which CWI is defined as the process of injecting CO 2-saturated water in oil reservoirs as a displacing fluid. In every enhanced oil recovery method, the potential formation damage of the injected fluid is considered. This is due to the fact that the injection of incompatible fluids often causes clay swelling and fines migration and thus impairs the formation permeability. Permeability reduction by clay particles mostly depends on its distribution which can be pore lining, pore bridging, dispersed or combination of these causing pore blocking or pore-throat diameter reduction. Besides, fine migration is considered as an important mechanism of recovery improvement during injection of low-salinity water in sandstone oil reservoirs. The present paper investigates the impact of injection of carbonated water and brines with the different salt concentrations on oil recovery and formation damage focusing on permeability variation. The investigation has been done on 12 relatively homogeneous claycontaining sandstone cores, while the compositions of the injection water were varied from 40,000 to 1000 ppm, at 176° F and 2000 psi. The amount of recovery improvement and permeability drop recorded in all tests and the fine effluent of two experiments were analysed using XRD, one for CWI and one for WF (water flooding). In all salinities, CWI has shown more oil recovery improvement than conventional water. CWI of 40,000 ppm showed the minimum permeability reduction of 6 percent, while the highest permeability was obtained by injection of water with 1000 ppm. Maximum ultimate oil recoveries of 61.2% and 42% were achieved by 1000 ppm both for CWI and WF, respectively. In comparison with brine injection, CWI resulted in more permeability drop in salinity above critical salt concentration (CSC), while below CSC, WF has caused more formation damage than CWI. Experimental results also showed that fine migration was the main reason behind formation damage. It was also revealed that permeability was significantly reduced due to fine production in the effluent.

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Effect of operational parameters on the performance of carbonated water injection: Experimental and numerical modeling study

Cited by 32 publications

References 28 publications

The role of CO2 and ion type in the dynamic interfacial tension of acidic crude oil/carbonated brine

The role of CO2 and ion type in the dynamic interfacial tension of acidic crude oil/carbonated brine

Gaseous CO2 behaviour during water displacement in a sandstone core sample

The effect of CO2-enriched water salinity on enhancing oil recovery and its potential formation damage: an experimental study on shaly sandstone reservoirs

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