Altering wettability to recover more oil from tight formations

Brady, Patrick V.; Bryan, Charles R.; Thyne, Geoffrey D.; Li, Huina

doi:10.1016/j.juogr.2016.05.004

Cited by 36 publications

(30 citation statements)

References 20 publications

Supporting

Mentioning

Contrasting

Order By: Relevance

“…Moreover, the interaction of the asphaltene-brine-silica system is also thought to be governed by thermodynamics [26][27][28][29], which can be depicted using DLVO theory, together with electrostatics, [23,[30][31][32], which can be described using surface complexation modelling. In order to understand how the surface species at asphaltene-brine and brine-silica interfaces impact the interaction of asphaltene-brine-silica system, a geochemical study was performed in the following subsection.…”

Section: Effect Of Salinity On Interactions Of Asphaltene-brine-silicmentioning

confidence: 99%

See 1 more Smart Citation

Direct Evidence of Salinity and pH Effects on the Interfacial Interactions of Asphaltene-Brine-Silica Systems

et al. 2020

View full text Add to dashboard Cite

The hydraulic fracturing technique remains essential to unlock fossil fuel from shale oil reservoirs. However, water imbibed by shale during hydraulic fracturing triggers environmental and technical challenges due to the low flowback water recovery. While it appears that the imbibition of fracturing fluid is a complex function of physico-chemical processes in particular capillary force which is associated with wettability of oil-brine-shale, the controlling factor(s) to govern the wettability is incomplete and the literature data in this context is missing. We thus measured the adsorption/desorption of asphaltenes on silica surface in the presence of brines using quartz crystal microbalance with dissipation (QCM-D). We detected zeta potential of asphaltene-brine and brine-silica systems and calculated the disjoining pressures of the asphaltene-brine-silica system in the case of different salinity. Moreover, we performed a geochemical study to quantify the variation of surface chemical species at asphaltene and silica surfaces with different pH values and used the chemical force microscope (CFM) method to quantify the effect of pH on intermolecular forces. Our results show that lowering salinity or raising pH reduced the adhesion force between asphaltene and silica surface. For example, at a pH value of 6.5, when the concentration of injected water is reduced from 1000 mM to 100 mM and 10 mM, the adhesion force decreased by approximately 58% and 66%, respectively. In addition, for the 100 mM NaCl solution, when the pH value increased from 4.5 to 6.5 and 9, the adhesion force decreased by approximately 56% and 87%, respectively. Decreased adhesion forces between asphaltene and the silica surface could promote the desorption of asphaltene from the silica surface, resulting in a negative zeta potential for both asphaltene-silica and brine-silica interfaces and a shift of wettability towards water-wet characteristic. During such a process, -NH+ number at asphaltene surfaces decreases and the bonds between -NH+ and >SiO− break down, to further interpret the formation of a thinner asphaltene adlayer on the rock surface. This study proposes a reliable theoretical basis for the application of hydraulic fracturing technology, and a facile and possible manipulation strategy to increase flowback water from unconventional reservoirs.

show abstract

Section: Effect Of Salinity On Interactions Of Asphaltene-brine-silicmentioning

confidence: 99%

“…Asphaltene surface -NH + = -N + H + -6.0 -COOH = -COO -+ H + -5.0 Silica surface >SiOH = >SiO − + H + -4.0 [44] Note: As shown in Table 2, the "-" in -NH + or -COOH represents the groups present at the asphaltenebrine interface [23], and ">" in >SiOH represents the groups present at the silica-brine interface [30,45].…”

Section: Geochemical Reactions Log K298kmentioning

confidence: 99%

Direct Evidence of Salinity and pH Effects on the Interfacial Interactions of Asphaltene-Brine-Silica Systems

et al. 2020

View full text Add to dashboard Cite

show abstract

“…Given that this work aims to understand the response of non-polar component on the adhesion at calcite surface with the presence of various brines, we used model oil compound containing -CH 3 groups to represent hydrocarbon functional groups [27,38,39]. In this work, we used Octadecane (C 18 H 38 ) for contact angle measurements, and 1-Octadecanethiol (C 18 H 38 S) for AFM measurements.…”

Section: Oilmentioning

confidence: 99%

“…To better quantify and predict the wettability alteration process, surface complexation modelling has been implemented to model chemical surface species from oil and calcite surfaces, thus characterizing the adhesion of oil and calcite [22,23,[27][28][29][30]. For example, Brady et al [22] developed a surface complexation model to characterize the wettability of oil-brine-calcite using a bond product sum concept, which is equal to [ 3 Ca + ].…”

Section: Introductionmentioning

confidence: 99%

Response of Non-Polar Oil Component on Low Salinity Effect in Carbonate Reservoirs: Adhesion Force Measurement Using Atomic Force Microscopy

et al. 2019

View full text Add to dashboard Cite

While the effect of polar-oil component on oil-brine-carbonate system wettability has been extensively investigated, there has been little quantitative analysis of the effect of non-polar components on system wettability, in particular as a function of pH. In this context, we measured the contact angle of non-polar oil on calcite surface in the presence of 10,000 ppm NaCl at pH values of 6.5, 9.5 and 11. We also measured the adhesion of non-polar oil group (–CH3) and calcite using atomic force microscopy (AFM) under the same conditions of contact angle measurements. Furthermore, to gain a deeper understanding, we performed zeta potential measurements of the non-polar oil-brine and brine-calcite interfaces, and calculated the total disjoining pressure. Our results show that the contact angle decreases from 125° to 78° with an increase in pH from 6.5 to 11. AFM measurements show that the adhesion force decreases with increasing pH. Zeta potential results indicate that an increase in pH would change the zeta potential of the non-polar oil-brine and calcite-brine interfaces towards more negative values, resulting in an increase of electrical double layer forces. The total disjoining pressure and results of AFM adhesion tests predict the same trend, showing that adhesion forces decrease with increasing pH. Our results show that the pH increase during low-salinity waterflooding in carbonate reservoirs would lift off non-polar components, thereby lowering residual oil saturation. This physiochemical process can even occur in reservoirs with low concentration of polar components in crude oils.

show abstract

“…Shale oil reservoirs mainly consist of clays (50-70%), while a small amount of quartz, feldspar remain in reservoirs [7]. Moreover, clays comprise basal charged clays (e.g., smectite, illite, and chlorite) [19], and edge-charged clays (kaolintie) [20]. Due to the different crystal structures, basal charged clays and edge-charged clays have different surface chemistries [21].…”

Section: Mineralsmentioning

confidence: 99%

Drivers of Wettability Alteration for Oil/Brine/Kaolinite System: Implications for Hydraulic Fracturing Fluids Uptake in Shale Rocks

et al. 2018

View full text Add to dashboard Cite

Abstract:Hydraulic fracturing technique is of vital importance to effectively develop unconventional shale resources. However, the low recovery of hydraulic fracturing fluids appears to be the main challenge from both technical and environmental perspectives in the last decade. While capillary forces account for the low recovery of hydraulic fracturing fluids, the controlling factor(s) of contact angle, thus wettability, has yet to be clearly defined. We hypothesized that the interaction of oil/brine and brine/rock interfaces governs the wettability of system, which can be interpreted using Derjaguin-Landau-Verwey-Overbeek (DLVO) and surface complexation modelling. To test our hypothesis, we measured a suit of zeta potential of oil/brines and brine/minerals, and tested the effect of ion type (NaCl, MgCl 2 and CaCl 2 ) and concentrations (0.1, 1, and 5 wt %). Moreover, we calculated the disjoining pressure of the oil/brine/mineral systems and compared with geochemical modelling predictions. Our results show that cation type and salinity governed oil/brine/minerals wettability. Divalent cations (Ca 2+ and Mg 2+ ) compressed the electrical double layer, and electrostatically linked oil and clays, thus increasing the adhesion between oil and minerals, triggering an oil-wet system. Increasing salinity also compressed the double layer, and increased the site density of oppositely charged surface species which made oil and clay link more strongly. Our results suggest that increasing salinity and divalent cations concentration likely decrease water uptake in shale oil reservoirs, thus de-risking the hydraulic fracturing induced formation damage. Combining DLVO and surface complexation modelling can delineate the interaction of oil/brine/minerals, thus wettability. Therefore, the relative contribution of capillary forces with respect to water uptake into shale reservoirs, and the possible impairment of hydrocarbon production from conventional reservoirs can be quantified.

show abstract

Altering wettability to recover more oil from tight formations

Cited by 36 publications

References 20 publications

Direct Evidence of Salinity and pH Effects on the Interfacial Interactions of Asphaltene-Brine-Silica Systems

Direct Evidence of Salinity and pH Effects on the Interfacial Interactions of Asphaltene-Brine-Silica Systems

Response of Non-Polar Oil Component on Low Salinity Effect in Carbonate Reservoirs: Adhesion Force Measurement Using Atomic Force Microscopy

Drivers of Wettability Alteration for Oil/Brine/Kaolinite System: Implications for Hydraulic Fracturing Fluids Uptake in Shale Rocks

Contact Info

Product

Resources

About