ASP Experiments in Indiana Limestone using NaOH to Reduce Surfactant Retention

Maubert, M.; Liyanage, Pathma Jith; Pope, Gary A.; Upamali, Nadeeka; Chang, Leonard; Ren, Guangwei; Mateen, Khalid; Ma, Kun; Bourdarot, Gilles; Morel, Danielle

doi:10.2118/190187-ms

Cited by 18 publications

(5 citation statements)

References 34 publications

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“…233,238,239 However, recent studies on Indiana limestone suggested the use of NaOH to lower the surfactant retention. [240][241][242] The reasons for NaOH selection were the higher pH of NaOH compared with Na2CO3 or ammonia, suppressing and slowing down the dissolution of calcite, and less alkali consumption by calcite, dolomite, and quartz. In the meantime, NaHCO3 is a good choice for reservoirs containing clay minerals.…”

Section: Alkalismentioning

confidence: 99%

Comprehensive review on surfactant adsorption on mineral surfaces in chemical enhanced oil recovery

Liu

Zhao

Brewer

et al. 2021

Advances in Colloid and Interface Science

109

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Section: Alkalismentioning

confidence: 99%

Comprehensive review on surfactant adsorption on mineral surfaces in chemical enhanced oil recovery

Liu

Zhao

Brewer

et al. 2021

Advances in Colloid and Interface Science

109

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“…A geochemical study was performed using the PHREEQC software to simulate the interactions between the designed brines and the Indiana limestone rock. The composition of Indiana limestone is 97.7% calcite mineral, 0.9% quartz, 0.2% Fe-dolomite, 0.6% halite, and 0.6% illite and mica (Maubert et al 2018). Table 3 shows the SI for various minerals, including calcite (CaCO 3 ), anhydrite (CaSO 4 ), and dolomite [CaMg(CO 3 ) 2 ].…”

Section: Resultsmentioning

confidence: 99%

“…The geochemical study using the PHREEQC software assesses the interactions between the injected brines and the Indiana limestone outcrop. The mineral composition of Indiana limestone comprises 97.7% of calcite mineral (Maubert et al 2018). The SI for different minerals defines the likelihood of scale formation.…”

Section: Methodsmentioning

confidence: 99%

Investigating the Effect of Water Softening on Polymer Adsorption onto Carbonates through Single-Phase and Two-Phase Experiments

Sebastian,

Mushtaq,

Al-Shalabi

et al. 2024

SPE Journal

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Summary Polymer retention is considered a major challenge in polymer flooding applications, especially in carbonates. This is due to the prevailing conditions of low permeability (<100 md), high temperature (>85°C), and high salinity (>100,000 ppm) generally found in these formations, which limit the effectiveness of commonly used polymers such as hydrolyzed polyacrylamide (HPAM) and xanthan gum. To address these challenges, a polymer based on acrylamide tertiary butyl sulfonate (ATBS) has been used due to its tolerance to high-temperature and -salinity conditions. However, the high cost of manufacturing these polymers, combined with their anionic properties that promote adsorption onto positively charged carbonate rocks, necessitates the exploration of methods to reduce polymer retention. In this study, we aim to determine the sufficient concentration of hardness ions (Ca2+ and Mg2+) required to significantly reduce the adsorption of this polymer. The study is unique in its focus on mitigating polymer retention in carbonate formations using softened brine, as no prior research has investigated this aspect. Four different brines were investigated with a salinity of 8,000 ppm total dissolved salts (TDS) and varying ionic composition designed mainly by eliminating the hardness-causing ions, Ca2+ and Mg2+. A geochemical study was performed using the PHREEQC software to analyze the interaction between these injected brines and the rock. Furthermore, comprehensive rheological and static adsorption studies were performed at a temperature of 25°C using the potential ATBS-based polymer to evaluate the polymer performance and adsorption in these brines. Later, dynamic adsorption studies were conducted in both single-phase and two-phase conditions to further quantify polymer adsorption. The geochemical study showed an anhydrite saturation index (SI) of less than 0.5 for all the brines used when interacting with the rock, indicating a very low tendency for calcium sulfate precipitation. Furthermore, the rheological studies showed that polymer viscosity significantly increased with reduced hardness, where a polymer solution viscosity of 7.5 cp was obtained in zero hardness brine, nearly 1.5 times higher than the polymer viscosity of the base makeup brine of 8,000 ppm. Moreover, it was observed that, by carefully tuning the concentrations of the divalent cations, the polymer concentration consumption for the required target viscosity was reduced by 40–50%. For the single-phase static adsorption experiments, the polymer solution in softened brines resulted in lower adsorption in the range of 37–62 µg/g-rock as opposed to 102 µg/g-rock for the base makeup brine. On the other hand, the single-phase dynamic adsorption results showed an even lowered polymer adsorption of 33 µg/g-rock for the softened brine compared with 45 µg/g-rock for the base makeup brine. Additionally, the single-phase dynamic adsorption studies showed a remarkable improvement in polymer injectivity using softened brine. The polymer retention in wettability-altered cores was further reduced. The study highlights that water softening improves the performance of polymers, specifically in terms of lowering polymer adsorption. It concludes that a threshold hardness level (Ca2+ and Mg2+) of approximately 100 ppm is sufficient to achieve a significant reduction in polymer adsorption for the tested experimental conditions. In this paper, we show that the softened water increases the polymer viscosity and reduces polymer adsorption, which leads to an overall reduction in polymer consumption. Hence, the softened makeup water has the potential to enhance the application envelope of this potential polymer for polymer flood, especially in the case of carbonate reservoirs.

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“…In the base case, the pK A is 6 and the initial pH is 7, so the concentration of aqueous soap is 10 times that of aqueous acid. a K2i , the coefficient controlling the effect of pH on the adsorption constant, was estimated to be À0.15 from the combined data in Wang et al (2019) and Maubert et al (2018), compiled in Wang (2018). The surfactant retention in carbonate rocks decreases by a factor of approximately 1/3 when the pH is increased from 8 to 11.…”

Section: Effect Of Phmentioning

confidence: 99%

A new surfactant wettability alteration model for reservoir simulators

Chang

Pope

2023

J Surfact & Detergents

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Surfactants enhance oil recovery in naturally-fractured oil-wet rocks by wettability alteration and interfacial tension reduction. The oil-wet state is ascribed to the adsorption of soap on the rock surface. Soaps are the dissociated forms of carboxylic acids in the crude oil, that is, carboxylate surfactants. This paper describes a new mechanistic surfactant wettability alteration model that was developed for and implemented in a reservoir simulator. The model captures the geochemical reactions of acid/soap, the formation of mixed micelles, Henry's law adsorption, and the formation of cationic surfactant-anionic soap ion-pairs. A new wettability scaling factor is used to interpolate between the oil-wet and water-wet relative permeability and capillary pressure curves. The new model also accounts for the effect of salinity and pH, so it should also be useful for modeling lowsalinity flooding without surfactant. Previous surfactant wettability alteration models ignored the underlying mechanisms and were not predictive. Simulations of both static and dynamic imbibition were performed to better understand the key surfactant parameters and the dynamics of wettability alteration, microemulsion phase behavior, and interfacial tension reduction on oil recovery. Optimizing surfactant formulations for wettability alteration is discussed.

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ASP Experiments in Indiana Limestone using NaOH to Reduce Surfactant Retention

Cited by 18 publications

References 34 publications

Comprehensive review on surfactant adsorption on mineral surfaces in chemical enhanced oil recovery

Comprehensive review on surfactant adsorption on mineral surfaces in chemical enhanced oil recovery

Investigating the Effect of Water Softening on Polymer Adsorption onto Carbonates through Single-Phase and Two-Phase Experiments

A new surfactant wettability alteration model for reservoir simulators

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