Influence of water composition on formation damage and related oil recovery in carbonates: A geochemical study

Al-Shalabi

Journal of Energy Resources Technology

et al. 2022

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Carbonates are characterized by low oil recovery due to their positive surface charge and consequent high affinity to negatively charged crude oil, rendering them to a state of mixed-to-oil wettability. In order to understand the rock/brine/oil interactions and their effect on potential-determining-ions (PDIs) adsorption/desorption during engineered water injection is needed for realistic and representative estimations of oil recovery. Therefore, this study reveals a novel approach to capture various interactions and better predict the effect of PDIs adsorption/desorption as well as concentrations of various ionic species in the effluent using Phreeqc. In this work, we determined adsorption/desorption of PDIs for the first time using surface complexation reactions and then we validated our results with experimental data from the literature. Our results showed that the presence of PDIs and their respective adsorption/desorption results in surface charge decrease and increase in pH. Also, this study found that ionic adsorption depends on ionic strength and species activity where calcium adsorption remained constant while magnesium and sulfate adsorptions varied with ionic strength. Moreover, magnesium ion was found to be the most sensitive ionic species to temperature as opposed to calcium and sulfate ions. In addition, sulfate spiking and dilution might decrease sulfate adsorption since the sulfate starts reacting with magnesium and forming complexes. Additionally, deionized water resulted in the highest charge decrease and pH increase with related incremental oil recovery. The adsorption/desorption of ions is case-dependent and thus, the findings cannot be generalized.

Section: Introductionmentioning

confidence: 99%

Geochemical Modeling of Engineered Water Injection in Carbonates Under Harsh Conditions: New Insights With Ionic Adsorption

Al-Shalabi

Journal of Energy Resources Technology

et al. 2022

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“…The results show that sulfate spiking leads to a pronounced decrease in surfactant adsorption. One should note that although the reported advantages of sulfate spiking for the injected water (engineered water injection) on wettability alteration (Adegbite et al 2018), hybrid surfactant-engineered water injection floods should be carefully designed to maximize wettability alteration while maintaining lowest levels of surfactant adsorption and formation damage (Khurshid et al 2018;Khurshid et al 2020;Afgan 2021a, 2021b). Additionally, it is important to mention that the surfactant adsorption mechanisms during chemical flooding are very case-dependent and subject to formation properties, crude oil/brine/rock compositions, and thermodynamic conditions.…”

Section: Surfactant-minerals Interface Reactionmentioning

confidence: 99%

New Insights into Surfactant Adsorption Estimation in Carbonates under Harsh Conditions Using Surface Complexation Modeling

Al-Shalabi

SPE Reservoir Evaluation &Amp; Engineering

2022

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Summary Several laboratory experiments demonstrated that the use of sodium hydroxide could increase the solution pH and reduce the adsorption of anionic surfactants. However, a better understanding of rock-oil-brine interactions and their effect on surfactant adsorption during alkaline-surfactantpolymer (ASP) flooding is needed for realistic and representative estimations of surfactant adsorption levels. Therefore, this study presents a novel approach to capture these interactions and better predict their effect on surfactant adsorption as well as effluent concentrations of surfactant and various aqueous species using the Phreeqc simulator. Currently, surface complexation models (SCMs) consider rock-brine, oil-brine, and surfactant-brine reactions. In this work, four new surface complexation reactions with intrinsic stability constants that honor oil-surfactant interactions have been proposed for the first time and then validated against experimental data reported in the literature. In addition, we analyzed the effect of various parameters on surface adsorption under harsh conditions of high temperature and high salinity using the proposed SCM. The results showed that the developed surfactant-based SCM is capable of estimating surfactant adsorption and its concentration in the effluent during chemical floods. The model was validated against two sets of ASP corefloods from the literature including single-phase and two-phase dynamic surfactant adsorption studies. The findings highlighted that oil-surfactant surface complexation reactions are important and should be captured for a more representative and accurate estimation of surfactant adsorption during chemical flooding. Moreover, the detailed and comprehensive analysis showed that surfactant adsorption increased and its concentration in the effluent decreased with the increase in temperature of the chemical flood. The latter shows that the adsorption process is endothermic and it is more of chemisorption as opposed to physio-adsorption. It was also showed that a decrease in water total salinity decreases the surfactant adsorption on the rock surface, which is related to the increase in the repulsive forces between the rock surface and adsorbed species. Additionally, with the increase in surfactant concentration in the chemical flood, surfactant concentration in the effluent increases, with a slight increase in surfactant adsorption. This slight increase in adsorption can be neglected compared with the injected and produced masses of the surfactant that are proportional. Moreover, the effect of sulfate spiking is significant where the increase in sulfate concentration reduces the surfactant adsorption. Furthermore, it is worth highlighting that the lowest surfactant adsorption levels were achieved through injected water dilution; less than 0.1 mg/g of rock. This is the first study to test a novel formulation of SCM considering the oil-surfactant effect on surfactant adsorption properties. The proposed framework to estimate surfactant adsorption is conducted for high-temperature and high-salinity reservoir conditions. Thus, it could be used in numerical reservoir simulators to estimate oil recovery due to wettability alteration by chemical flooding in carbonates, which will be investigated in our future work. The surfactant adsorption mechanisms during chemical flooding are very case-dependent and hence, the findings of this study cannot be generalized.

“…The analytical Van't Hoff equation could be used to calculate the equilibrium constants and its dependency on temperature [15] and reads as follows: (8) Energies 2021, 14, 7676…”

Section: Effect Of Temperature and Pressurementioning

confidence: 99%

Geochemical Investigation of CO2 Injection in Oil and Gas Reservoirs of Middle East to Estimate the Formation Damage and Related Oil Recovery

2021

Energies

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The injection performance of carbon dioxide (CO2) for oil recovery depends upon its injection capability and the actual injection rate. The CO2–rock–water interaction could cause severe formation damage by plugging the reservoir pores and reducing the permeability of the reservoir. In this study, a simulator was developed to model the reactivity of injected CO2 at various reservoir depths, under different temperature and pressure conditions. Through the estimation of location and magnitude of the chemical reactions, the simulator is able to predict the effects of change in the reservoir porosity, permeability (due to the formation/dissolution) and transport/deposition of dissoluted particles. The paper also presents the effect of asphaltene on the shift of relative permeability curve and the related oil recovery. Finally, the effect of CO2 injection rate is analyzed to demonstrate the effect of CO2 miscibility on oil recovery from a reservoir. The developed model is validated against the experimental data. The predicted results show that the reservoir temperature, its depth, concentration of asphaltene and rock properties have a significant effect on formation/dissolution and precipitation during CO2 injection. Results showed that deep oil and gas reservoirs are good candidates for CO2 sequestration compared to shallow reservoirs, due to increased temperatures that reduce the dissolution rate and lower the solid precipitation. However, asphaltene deposition reduced the oil recovery by 10%. Moreover, the sensitivity analysis of CO2 injection rates was performed to identify the effect of CO2 injection rate on reduced permeability in deep and high-temperature formations. It was found that increased CO2 injection rates and pressures enable us to reach miscibility pressure. Once this pressure is reached, there are less benefits of injecting CO2 at a higher rate for better pressure maintenance and no further diminution of residual oil.