Evaluation of wettability alteration and IFT reduction on mitigating water blocking for low-permeability oil-wet rocks after hydraulic fracturing

Liang, Tianbo; Zhou, Fujian; Lu, Jun; DiCarlo, David A.; Nguyen, Quoc P.

doi:10.1016/j.fuel.2017.08.029

Cited by 84 publications

(38 citation statements)

References 40 publications

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“…Some other experimental results show that the presence of divalent cations can significantly increase surface wettability compared to monovalent cations [2,17]. In addition, there are related studies claiming that ion type and strength significantly affect the wettability of the oil-brine-rock system, but the results were mostly obtained from macroscopic changes such as contact angle and interfacial tension [18][19][20]. Therefore, quantitative research and responsible mechanisms for wettability alteration are a great need.…”

Section: Introductionmentioning

confidence: 99%

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

et al. 2020

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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.

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Section: Introductionmentioning

confidence: 99%

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

et al. 2020

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“…After the system was stabilized, a 3-step coreflood sequence was conducted on this core sample. The broken/degraded guar system has a higher density than the formation brine; to improve the stability of the displacement front during the coreflood, the mimicked fracturing fluid after gel breaking was injected from the bottom to the top of the core sample while the mimicked brine was injected in the opposite direction [41][42][43]. Details are as follows.…”

Section: Coreflood Testmentioning

confidence: 99%

Study on Fluid-Rock Interaction and Reuse of Flowback Fluid for Gel Fracturing in Desert Area

et al. 2018

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Hydraulic fracturing requires a large volume of fresh water, which is difficult and expensive to obtain in the desert area such as Tarim Basin. Currently, flowback fluid is typically transported to the sewage treatment plant and then discharged after reaching environmental requirements; however, this is not only costly, but also a waste of water resource. Therefore, it is imperative to understand the potential interactions between fracturing fluid and reservoir rock, and then find solutions to reuse the flowback water for subsequent fracturing. In this study, once flowback fluid was directly collected from the field, its chemical compositions were analyzed; then, filtering, decoloring, and chelating methods were chosen to effectively remove or shield the unfavorable reintroduced components. Moreover, pH value was further tuned during different stages of the recycling process to ensure good gelation and cross-linking properties of guar. Cross-linked guar synthesized with the flowback fluid was evaluated in the lab through shear resistance tests and coreflood tests under the reservoir conditions; results indicated the recycled gel behaved similarly as the original gel, or even better. From this work, a cheap and effective treatment process was proposed to reuse the flowback fluid in the desert area.

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“…The corresponding matrix notation is f = kd (19) where and are the node force, N; k is the stiffness matrix of the spring element, N/m; d is the node displacement vector, m; f is the node force vector, N. During SLFTP, the previously created fractures were plugged by diverting agents; thus the injected fracturing fluid and proppants were not able to flow back to the wellbore and retained within fractures. Moreover, the fluid leak-off rate was low due to the low-permeability [36][37][38]; thus the fracturing fluid and proppants trapped in the fracture space will prevent the previous fractures from closure. The propped fractures would squeeze the surrounding rocks and alter local stress fields, which may affect the injection pressure of the subsequent fractures created in other layers.…”

Section: Spring Modelmentioning

confidence: 99%

Evaluations of Fracture Injection Pressure and Fracture Mouth Width during Separate-Layer Fracturing with Temporary Plugging

Wang

Zhou

Liang

et al. 2018

Mathematical Problems in Engineering

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Separate-layer fracturing with temporary plugging (SLFTP) is a potential way to stimulate multiple layer reservoirs due to its low cost, low risk, and high efficiency. In this study, based on the cohesive zone model (CZM), a 3D fully fluid-solid coupling and multiple layer model is established to investigate factors influencing fracture injection pressure and fracture mouth width. The cohesive layer properties are based on the reported study, which have been validated through a series of numerical experiments. Innovatively, the spring model is innovatively proposed to represent the plugging effect of diverting agents and prop the aperture of the previous fractures. Simulation results reveal that the effects of previous fractures in multiple layer formations can be neglected, which is quite different from multistage fracturing for horizontal wells. Fracture injection pressure can be evaluated more accurately by taking the following factors into consideration: the minimum horizontal principal stress, rock tensile strength, injection rate, and pore pressure enhancement. Further, fracture mouth width is strongly influenced by rock tensile strength, Young’s modulus, and injection rate. This study provides a guidance for candidate well selection and diverting agent optimization during SLFTP in multilayer formations.

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Evaluation of wettability alteration and IFT reduction on mitigating water blocking for low-permeability oil-wet rocks after hydraulic fracturing

Cited by 84 publications

References 40 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

Study on Fluid-Rock Interaction and Reuse of Flowback Fluid for Gel Fracturing in Desert Area

Evaluations of Fracture Injection Pressure and Fracture Mouth Width during Separate-Layer Fracturing with Temporary Plugging

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