Formation damage in chemical enhanced oil recovery processes

Sheng, James J.

doi:10.1002/apj.2035

Cited by 27 publications

(9 citation statements)

References 76 publications

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“…However, salting out by incompatible surfactant causes solid plugging, leading to a permeability reduction. 97 Moreover, formation damage caused by the flowback process has been noticed by many researchers in the recent past. Lu et al 98 pointed out that excessive drawdown pressure during the flowback process causes formation damage, such as fracture closure and proppant mobility within the fracture.…”

Section: Significance Of Zfr Of Hffmentioning

confidence: 99%

“…Adding a surfactant into the fracturing fluid is a common way to reduce the surface tension of the fracturing fluid, obtaining an increased flowback rate , to mitigate the water blocking damage. However, salting out by incompatible surfactant causes solid plugging, leading to a permeability reduction . Moreover, formation damage caused by the flowback process has been noticed by many researchers in the recent past.…”

Section: Significance Of Zfr Of Hffmentioning

confidence: 99%

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Zero Flowback Rate of Hydraulic Fracturing Fluid in Shale Gas Reservoirs: Concept, Feasibility, and Significance

et al. 2021

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A high flowback rate of hydraulic fracturing fluid (HFF) yields a high gas production rate in a tight sand gas reservoir. This idea is well followed when it comes to the hydraulic fracturing of a shale gas well. Therefore, numerous studies have focused on increasing the flowback rate of HFF in shale gas reservoirs to mitigate the water blocking damage. Yet, only a small portion of the injected fluid (less than 20%) could be recovered during flowback operation. Moreover, there is no good correlation between the gas production rate and flowback rate for shale gas wells. Surprisingly, a phenomenon that a low flowback rate of HFF usually yields a high gas production rate is found recently by field data studies. In this case, the authors investigated the reasons for this abnormal phenomenon and believed that reducing the flowback rate of HFF in a shale gas reservoir could be a new strategy for dealing with the injected HFF. Therefore, a new concept called zero flowback rate (ZFR) of HFF is put forward to serve as an unconventional way to manage the high volume of HFF. ZFR of HFF is a concept compared with the flowback rate of the fracturing fluid for a conventional reservoir. It is worth noting that zero in the ZFR concept does not stand for the absolute number 0. It means that reducing the flowback rate of HFF is the goal of the ZFR strategy. To analyze the feasibility of realizing ZFR, the geological conditions of gas shale and engineering conditions of hydraulic fracturing were evaluated by comparing the relative studies. It showed that gas shale has the potential to imbibe most of the HFF and retain the imbibed fluid without contaminating the groundwater. ZFR can be realized by extending the shut-in time or adjusting the properties of HFF. Compared with the conventional idea of increasing the flowback rate of HFF, ZFR is of great significance. It does not only recover the relative gas permeability of the shale reservoir by redistributing the liquid phase from the fractures into the shale matrix but also enhances it by creating new microfractures. ZFR is cost-saving and environmentally friendly by dealing with a reduced volume of flowback HFF. ZFR has a high potential of becoming a viable strategy for the development of shale gas reservoirs.

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Section: Significance Of Zfr Of Hffmentioning

confidence: 99%

Section: Significance Of Zfr Of Hffmentioning

confidence: 99%

Zero Flowback Rate of Hydraulic Fracturing Fluid in Shale Gas Reservoirs: Concept, Feasibility, and Significance

et al. 2021

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“…A large amount of studies indicates that the composition, distribution, and content of clay minerals in the reservoirs have a great influence on the pore structure and physical properties (e.g., porosity and permeability), which will directly affect the oil production efficiency (Chen et al, 2016;Zhao et al, 2017;Zhu et al, 2021). There are many physical and chemical reactions between pore fluids and rock components in the formation during ASP flooding (Song et al, 2011;Wu et al, 2015a;Song et al, 2015;Sheng., 2016), especially the strong water-rock reaction of clay minerals. Pore structure and physical properties in reservoirs change under the chemical dissolution of rock minerals and the precipitation and agglomeration of clay mineral particles in the pore fluid because of the adsorptionflocculation of the polymer (Kazempour et al, 2013;Huang et al, 2020).…”

Section: Introductionmentioning

confidence: 99%

Response to the Variation of Clay Minerals During ASP Flooding in the Saertu Oilfield in the Songliao Basin

Liang

Wenfu

et al. 2021

Front. Earth Sci.

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In this paper, the variation of clay minerals and their influence on reservoir physical properties and residual oil before and after ASP flooding are analyzed. The results show that the total amount of clay minerals in reservoirs decreases after ASP flooding in the ultra-high-water-cut-stage reservoirs of the Naner Zone in the Saertu Oilfield, Songliao Basin. Therein, the illite content reduces, while the content of illite smectite mixed-layer and chlorite increases. The content of kaolinite varies greatly. The content of kaolinite decreases in some samples, while it increases in other samples. The clay minerals block the pore throat after ASP flooding. As a result, the pore structure coefficient and the seepage tortuosity increase, the primary intergranular pore throat shrinks, and the pore–throat coordination number decreases. Nevertheless, the dissolution of clay minerals reduces the pore–throat ratio and increases porosity and permeability. The variation of clay minerals after ASP flooding not only intensifies the reservoir heterogeneity but also affects the formation and distribution of residual oil. The residual oil of the oil–clay mixed adsorption state is a newly formed residual oil type related to clay, which accounts for 44.2% of the total residual oil reserves, so it is the main occurrence form of the oil in reservoirs after ASP flooding. Therefore, the exploitation of this type of residual oil has great significance to enhance the oil recovery in ultra-high-water-cut-stage reservoirs.

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“…In all aforementioned cases, the stimulation (injection) fluid is a crucial element and must meet special requirements depending on the goal of the application [13,14,15]. After stimulation treatment, a part of this fluid remains within fractures, causing damage to the formation and reducing the stimulation effectiveness [16,17,18]. Therefore, attention has been drawn to the possibility of the application of fluids energized with gases with the addition of nanoparticles, thereby reducing the water content in the injection fluid and also increasing the stabilization of the process fluid during stimulation treatments [19,20,21,22,23].…”

Section: Introductionmentioning

confidence: 99%

Impact of Nitrogen Foamed Stimulation Fluids Stabilized by Nanoadditives on Reservoir Rocks of Hydrocarbon Deposits

2019

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The first objective of this experiment was to improve the stabilization of N2 based foam with nanoparticles as an alternative to typical fracturing fluid, which consists of a gelling agent (HPG—hydroxypropyl guar). The second objective of the project was to investigate the damage caused by nanoparticle–based nitrogen foamed fracturing fluids (F.F) on a reference sandstone, using permeability and porosity tests, optical microscope with a Profilometer, and a scanning electron microscope (SEM). The properties of F.F with two types of SiO2 nanoparticles (hydrophilic fumed silica Areosil 300 and silica sol U-2 obtained by the sol-gel method), such as rheology and core damage, were investigated. The discussion of this research results is based on the stability tests carried out with the use of rheology and the foam half-life, formation damage ratio, and observation of exposed samples using SEM and the Profilometer. The permeability and porosity damage ratios of the damaged core samples were found to decrease when nitrogen foamed fluids were used. These results were confirmed with the Profilometer and SEM images. The experimental data showed that the foam stability increased when silica (SiO2) nanoparticles were added. SiO2 nanoparticle-surfactant-stabilized foam for fracturing is superior to traditional water-based fracturing fluids and causes lower core permeability damage than a traditional F.F.

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Formation damage in chemical enhanced oil recovery processes

Cited by 27 publications

References 76 publications

Zero Flowback Rate of Hydraulic Fracturing Fluid in Shale Gas Reservoirs: Concept, Feasibility, and Significance

Zero Flowback Rate of Hydraulic Fracturing Fluid in Shale Gas Reservoirs: Concept, Feasibility, and Significance

Response to the Variation of Clay Minerals During ASP Flooding in the Saertu Oilfield in the Songliao Basin

Impact of Nitrogen Foamed Stimulation Fluids Stabilized by Nanoadditives on Reservoir Rocks of Hydrocarbon Deposits

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