Surfactant selection criteria with flowback efficiency and oil recovery considered

Wijaya, Nur; Sheng, James J.

doi:10.1016/j.petrol.2020.107305

Cited by 19 publications

(4 citation statements)

References 40 publications

Supporting

Mentioning

Contrasting

Order By: Relevance

“…Scholars have investigated the relationship between residual oil saturation and capillary number, i.e., study the capillary desaturation curve (CDC). However, the relationship between fracturing fluid flowback efficiency and the capillary number for gas-fracturing fluid two-phase, which are also immiscible two-phase fluids, has rarely been studied [ 16 , 17 ].…”

Section: Introductionmentioning

confidence: 99%

Investigation of Fracturing Fluid Flowback in Hydraulically Fractured Formations Based on Microscopic Visualization Experiments

et al. 2023

View full text Add to dashboard Cite

Fracturing fluids are widely applied in the hydraulic fracturing of shale gas reservoirs, but the fracturing fluid flowback efficiency is typically less than 50%, severely limiting the shale gas recovery. Additionally, the mechanism and main influencing factors of fracturing fluid flowback are unclear. In this study, microscopic experiments are conducted to simulate the fracturing fluid flowback progress in shale gas reservoirs. The mechanism and factors affecting fracturing fluid flowback/retention in the fracture zone were analyzed and clarified. Results show that the ultimate flowback efficiency of fracturing fluid is positively correlated with the fracturing fluid concentration and the gas driving pressure difference. There are four kinds of mechanisms responsible for fracturing fluid retention in the pore network: viscous resistance, the Jamin effect, the gas blockage effect and the dead end of the pore. Additionally, the ultimate flowback efficiency of the fracturing fluid increases linearly with increasing capillary number. These insights will advance the fundamental understanding of fracturing fluid flowback in shale gas reservoirs and provide useful guidance for shale gas reservoirs development.

show abstract

Section: Introductionmentioning

confidence: 99%

Investigation of Fracturing Fluid Flowback in Hydraulically Fractured Formations Based on Microscopic Visualization Experiments

et al. 2023

View full text Add to dashboard Cite

show abstract

“…The performance of surfactants as flowback aids also depends on their ability to lower IFT and concomitant capillary forces, allowing both the fracturing fluid and the oil to more easily traverse the narrow pore throats which comprise the microfracture networks (Kim et al, 2016; Liang et al, 2017), for which studies have demonstrated positive correlations between reductions in capillary pressure and fluid‐oil IFT and improved hydrocarbon permeabilities (Liang et al, 2015). In general, it is recognized that surfactants useful in the application will reduce IFT to within the range of low, ~0.1 mN/m, to ultralow, <0.001 mN/m, levels (Chai et al, 2019; Mansour et al, 2021; Tangirala & Sheng, 2018; Wijaya & Sheng, 2020b). However, it is important to recognize that the selection and use of surfactants is quite system dependent and not always straightforward.…”

Section: Introductionmentioning

confidence: 99%

“…Moreover, the work of some researchers has illustrated that boosting flowback recovery rates does not always lead to improved oil production. Wijaya and Sheng (2020b) have argued that while a notable reduction in IFT enhances flowback, a more modest reduction is desirable to increase oil productivity.…”

Section: Introductionmentioning

confidence: 99%

Nonionic and anionic surfactants as flowback aids in hydraulic fracturing methods of crude oil production

Clements

2023

J Surfact & Detergents

View full text Add to dashboard Cite

Surfactants find utility in hydraulic fracturing operations for their ability to modify rock wettability and increase the flowback of fracturing fluid following proppant delivery. The performance of a series of nonionic and anionic surfactants was evaluated by gravity drainage displacement testing. Alkylbenzenesulfonates having alkyl chains possessing at least 16 carbons were among the best performers, yet a similar surfactant having an alkyl chain possessing only ~12 carbons performed quite poorly. These data illustrate that a critical chain length exists for this series. Lauryldimethylamine oxide also performed well. In general, those surfactants possessing the greatest ionic character outperformed nonionic surfactants. Critical micelle concentration, surface tension, contact angle, relative solubility number, and hydrophilic–lipophilic balance were determined for each surfactant studied. Unexpectedly however, few correlations between any of these physical and surface properties and performance in gravity drainage displacement tests were identified, underscoring the complexity of selecting surfactants suitable in the application. These data suggest that more real‐world test methods, employing stationary phases, temperatures and pressures that better mimic the fields and individual wells being considered, are needed to better guide surfactant selection.

show abstract

“…Such staged fracturing in a shale gas reservoir generally lasts for a long time, following by a period of shut-in, and then a large-scale fracture network could be formed. , Therefore, both the contact surface and contact time between the fracturing fluid and reservoir are large, resulting in a large amount of fracturing fluid imbibition and retention in a shale gas reservoir . Meanwhile, the capillary force to imbibe aqueous phase is large because a shale is generally hydrophilic and has a small pore size. , The fracturing fluid is easy to enter and difficult to exit, resulting in a low flow back efficiency of a shale gas well. − A large amount of retained fracturing fluid that does not flow back tends to be trapped in the matrix near the fracture network or in the unpropped fractures closing within a relatively short time after hydraulic fracturing . It has been demonstrated that a short-term aqueous retention in a shale gas reservoir could be beneficial to inducing small cracks due to the hydration of clay minerals and even displacing methane originally adsorbed in the matrix. , However, it is believed that the retained fracturing fluid in a reservoir would block the gas transport and finally result in the formation damage through aqueous phase trapping (APT) in a long run, which severely restricts the stimulation effectiveness of hydraulic fracturing. − …”

Section: Introductionmentioning

confidence: 99%

Evaluation of Aqueous Phase Trapping in Shale Gas Reservoirs Based on Analytic Hierarchy Process

et al. 2021

View full text Add to dashboard Cite

A large amount of fracturing fluid retained in a shale gas reservoir that does not flow back after hydraulic fracturing could induce formation damage of aqueous phase trapping (APT). A shale gas reservoir generally has a multiscale pore and fracture structure, so both retained fracturing fluid distribution and gas transport have multiscale characteristics. In this work, a comprehensive evaluation method of shale APT damage based on the analytic hierarchy process in fuzzy mathematics is put forward considering the petrophysical properties and multiscale gas transport behavior in a shale reservoir. First, the critical indexes of shale APT damage evaluation are determined. Then the hierarchy structure for APT damage evaluation for a shale gas reservoir is constructed. Finally, the weights of the critical evaluation indexes of shale APT damage are calculated on the basis of the analytic hierarchy process. Taking Longmaxi shale reservoir as an example, the APT damage degrees for matrix and fractures are calculated to be 65% and 84%, respectively. The evaluation method for shale APT damage proposed in this work is beneficial to accurately predicting the productivity of a shale gas well and optimizing the hydraulic fracturing process to improve the stimulation effect.

show abstract

Surfactant selection criteria with flowback efficiency and oil recovery considered

Cited by 19 publications

References 40 publications

Investigation of Fracturing Fluid Flowback in Hydraulically Fractured Formations Based on Microscopic Visualization Experiments

Investigation of Fracturing Fluid Flowback in Hydraulically Fractured Formations Based on Microscopic Visualization Experiments

Nonionic and anionic surfactants as flowback aids in hydraulic fracturing methods of crude oil production

Evaluation of Aqueous Phase Trapping in Shale Gas Reservoirs Based on Analytic Hierarchy Process

Contact Info

Product

Resources

About