Flow physics of how surfactants can reduce water blocking caused by hydraulic fracturing in low permeability reservoirs

Liang, Tianbo; Achour, Sofiane Haythem; Longoria, Rafael A.; DiCarlo, David A.; Nguyen, Quoc P.

doi:10.1016/j.petrol.2017.07.042

Cited by 45 publications

(9 citation statements)

References 16 publications

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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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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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“…Another method to enhance the EUR is to inject a surfactant into the reservoir. As a functional fluid, the surfactant can be used as a fracturing fluid additive and can be injected during the fracturing or can be injected in the huff- n -puff mode after the fracturing. − The wettability of the rock can be changed by adding surfactants to the fracturing fluid. The structure, concentration, and formation of microemulsions of surfactants all influence the effect of changing wettability.…”

Section: Introductionmentioning

confidence: 99%

Dynamic Monitoring and Enhanced Oil Recovery Evaluation of the Water Flooding Process of Liquid Nanofluids in Tight Reservoirs

et al. 2023

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The CT scanning technology can observe fluid saturation distribution in the rock at different times during water flooding in tight reservoirs. However, this technology has not been used to study the water flooding characteristics in changing the wettability of liquid nanofluids. First, this study evaluated the basic properties of a nonionic liquid nanofluid, including the contact angle (CA), interfacial tension (IFT), and aqueous stability tests. Then, the water flooding process in tight rocks is dynamically monitored by the CT scanning technology. The water flooding characteristics of liquid nanofluids changing reservoir wettability are analyzed by measuring the rock's water phase saturation distribution at different times. Finally, the spontaneous imbibition experiment evaluated the enhanced oil recovery of liquid nanofluids. The results show that the particle size of the liquid nanofluid is at the nanometer level (7.5 nm) and can change the wettability of oil-wet to water-wet. Liquid nanofluid has low interfacial tension and can exist stably in brine with a high salinity (20,000−50,000 ppm). In water flooding, the front profile of water phase saturation changes obviously, and it is driven forward with a similar "piston" type. Compared with the brine water, the water invasion front gradually becomes uniform, which is strong evidence that a liquid nanofluid can change the wettability of rocks. Besides, the invasion depth of the fracturing fluid with liquid nanofluids is deeper than that of brine water and displaces more oil. Finally, the spontaneous imbibition test shows that the recovery factor of high-concentration (1 wt %) liquid nanofluids increases by 28.9% compared with that of brine water. This paper provides theoretical support for applying liquid nanofluids in tight reservoirs.

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“…This is for the reason that a tight reservoir shows high capillary pressure, which captures fracturing fluid for a long time . However, the surfactant greatly reduces the interfacial tension between the fracturing fluid and the crude oil, weakens the capillary forces, and eliminates the blocking of the fracturing fluid. , Additionally, in the course of the fracturing process, the surfactant makes mechanical shear action with the oil to form the emulsion under the action of displacement pressure in the reservoir. In the process of well huff-n-puff production, the surfactant plays a stripping role, forming emulsion to improve the recovery. , The combination of the two effects can contribute to the development of tight reservoir fracturing stimulation.…”

Section: Introductionmentioning

confidence: 99%

Influencing Factors of Surfactant Stripping Crude Oil and Spontaneous Imbibition Mechanism of Surfactants in a Tight Reservoir

et al. 2022

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Surfactants play a vital role in the working fluid during the exploitation of tight reservoirs. The main goal is to clarify the mechanism of surfactant production enhancement in the reservoir. In this paper, starting from the interface properties and emulsifying properties of surfactants, the factors affecting the stripping of crude oil by different surfactants were described in detail. Meanwhile, the imbibition experiments of cores were used to clarify the two spontaneous imbibition mechanisms of the surfactant. Namely, they are the capillary force expulsion caused by the emulsion stripping thermal diffusion–convection and the wettability change. When the interfacial tension between the surfactant and oil is in the range of 10 –2 –10 –3 mN/m, the particle size of emulsion is less than 1 μm, and the oil stripping efficiency is greater than 58%. The imbibition is mainly caused by thermal diffusion–convection. The wetting angle of the surfactant mainly changing wettability is less than 15°, and the adhesion work is greater than 52 mN/m. Using X-ray computed tomography, the surfactant imbibition distance of different permeability types of cores was obtained. The results show that higher permeability cores have a deeper imbibition distance. The results of this paper enrich the mechanism of enhanced oil recovery by surfactants and have important implications for the exploitation of tight reservoirs.

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Flow physics of how surfactants can reduce water blocking caused by hydraulic fracturing in low permeability reservoirs

Cited by 45 publications

References 16 publications

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

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

Dynamic Monitoring and Enhanced Oil Recovery Evaluation of the Water Flooding Process of Liquid Nanofluids in Tight Reservoirs

Influencing Factors of Surfactant Stripping Crude Oil and Spontaneous Imbibition Mechanism of Surfactants in a Tight Reservoir

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