Wettability modification by fluoride and its application in aqueous phase trapping damage removal in tight sandstone reservoirs

Liu, Xuefen; Kang, Yili; Luo, Pingya; You, Lijun; Tang, Yun; Kong, Lie

doi:10.1016/j.petrol.2015.06.013

Cited by 63 publications

(23 citation statements)

References 38 publications

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“…The accumulation of condensate liquid poses a serious formation damage problem and thus may reduce gas productivity significantly [7][8][9]. The formation damage becomes more serious in tight reservoirs, where the condensate bank becomes immobile and blocks the gas flow [3,10,11]. Figure 1 illustrates a schematic diagram of the condensate bank in the near-wellbore region.…”

Section: Introductionmentioning

confidence: 99%

“…where the condensate bank becomes immobile and blocks the gas flow [3,10,11]. Figure 1 illustrates a schematic diagram of the condensate bank in the near-wellbore region.…”

Section: Introductionmentioning

confidence: 99%

“…The solvent injection is used to decrease the interfacial tension at the gas/condensate interface and hence improve the condensate mobility [30,31]. Wettability alteration chemicals are injected to change the rock wettability to less liquid-wet state, thereby preventing the liquid accumulation [10,23,28,32]. Extensive laboratory experiments and numerical modeling have been conducted to evaluate the efficiency of wettability alteration treatments on mitigating the condensate bank [7,11,23,26,28,[33][34][35][36].…”

Section: Introductionmentioning

confidence: 99%

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Novel Treatment for Mitigating Condensate Bank Using a Newly Synthesized Gemini Surfactant

et al. 2020

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Condensate accumulation in the vicinity of the gas well is known to curtail hydrocarbon production by up to 80%. Numerous approaches are being employed to mitigate condensate damage and improve gas productivity. Chemical treatment, gas recycling, and hydraulic fracturing are the most effective techniques for combatting the condensate bank. However, the gas injection technique showed temporary condensate recovery and limited improvement in gas productivity. Hydraulic fracturing is considered to be an expensive approach for treating condensate banking problems. In this study, a newly synthesized gemini surfactant (GS) was developed to prevent the formation of condensate blockage in the gas condensate reservoirs. Flushing the near-wellbore area with GS will change the rock wettability and thereby reduce the capillary forces holding the condensate due to the strong adsorption capacity of GS on the rock surface. In this study, several measurements were conducted to assess the performance of GS in mitigating the condensate bank including coreflood, relative permeability, phase behavior, and nuclear magnetic resonance (NMR) measurements. The results show that GS can reduce the capillary pressure by as much as 40%, increase the condensate mobility by more than 80%, and thereby mitigate the condensate bank by up to 84%. Phase behavior measurements indicate that adding GS to the oil–brine system could not induce any emulsions at different salinity levels. Moreover, NMR and permeability measurements reveal that the gemini surfactant has no effect on the pore system and no changes were observed in the T2 relaxation profiles with and without the GS injection. Ultimately, this work introduces a novel and effective treatment for mitigating the condensate bank. The new treatment showed an attractive performance in reducing liquid saturation and increasing the condensate relative permeability.

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Section: Introductionmentioning

confidence: 99%

“…where the condensate bank becomes immobile and blocks the gas flow [3,10,11]. Figure 1 illustrates a schematic diagram of the condensate bank in the near-wellbore region.…”

Section: Introductionmentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

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Novel Treatment for Mitigating Condensate Bank Using a Newly Synthesized Gemini Surfactant

et al. 2020

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“…This behavior can reduce the gas flow channel, and cause aqueous phase trapping (APT), which will influence the natural gas exploitation [7,8]. Usually, through quick and effective flowback to reduce the soaking time and liquid filtration distance, the APT damage can be relieved [9], and some chemical treatments for improving the flowback rate of the aqueous phase have been widely investigated [10][11][12][13][14][15]. Some equations have been proposed to evaluate the APT damage.…”

Section: Introductionmentioning

confidence: 99%

The Effect of Fracturing Fluid Saturation on Natural Gas Flow Behavior in Tight Reservoirs

Meng

Shen

et al. 2020

Energies

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Hydraulic fracturing becomes an essential method to develop tight gas. Under high injection pressure, fracturing fluid entering into the formation will reduce the flow channel. To investigate the influence of water saturation on gas flow behavior, this study conducted the gas relative permeability with water saturation and the flow rate with the pressure gradient at different water saturations. As the two dominant tight gas-bearing intervals, the Upper Paleozoic Taiyuan and Shihezi Formations deposited in Ordos Basin were selected because they are the target layers for holding vast tight gas. Median pore radius in the Taiyuan Formation is higher than the one in the Shihezi Formation, while the most probable seepage pore radius in the Taiyuan Formation is lower than the one in the Shihezi Formation. The average irreducible water saturation is 54.4% in the Taiyuan Formation and 61.6% in the Shihezi Formation, which indicates that the Taiyuan Formation has more movable water. The average critical gas saturation is 80.4% and 69.9% in these two formations, respectively, which indicates that the Shihezi Formation has more movable gas. Both critical gas saturation and irreducible water saturation have a negative relationship with porosity as well as permeability. At the same water saturation, the threshold gradient pressure of the Taiyuan Formation is higher than the one in the Shihezi Formation, which means that water saturation has a great influence on the Taiyuan Formation. Overall, compared with the Shihezi Formation, the Taiyuan Formation has a higher median pore size and movable water saturation, but water saturation has more influence on its gas flow capacity. Our research is conducive to understanding the effect of fracturing fluid filtration on the production of natural gas from tight reservoirs.

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“…25 The success of this experimental study of spontaneous capillary water imbibition and the advances of gas permeability measurements has resulted in WPT damage evaluation becoming a topic of considerable interest in tight gas reservoir research. Other work on WPT has focused on examining the effects of rock permeability, 17 wettability, 26,27 interfacial tension, 5 capillary force, [14][15][16] water saturation, 5,28,29 invasion depth, [14][15][16] formation temperature, and formation pressure, 5,13,30 all with the aim of reducing or eliminating the damage more effectively.…”

Section: Introductionmentioning

confidence: 99%

Investigation of the controlling rock petrophysical factors on water phase trapping damage in tight gas reservoirs

Tian

Kang

Jia

et al. 2019

Energy Science & Engineering

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This paper presents an investigation into the effect of rock physical parameters on water phase trapping (WPT) damage in tight gas reservoirs. The investigation involved water imbibition and drainage experiments that were performed to simulate the WPT formation process. Gas permeability was measured before and after WPT, and an empirical formula was used to determine water film thickness in order to examine the influence of WPT on effective gas flow channel. Results showed that the average water saturation of 15 tight core samples increased from 19.41% to 44.76% during water imbibition and declined to 38.72% after drainage. Increments in water saturation caused a degree of damage to gas permeability in the 36.03%‐78.10% range with an average value of 59.31%. Comparative analysis showed that the dominant factors affecting WPT were average pore throat radius followed by rock permeability and porosity. Meanwhile, calculations showed that water film thickness in the 21.22‐38.18 nm range correlated to a reduced effective gas flow channel of 20.20‐45.15 nm caused by WPT, which suggests that tight rocks with smaller pore throats may be particularly sensitive to WPT damage. The relative size of the water film filling the pore throat, trapping gas, and reducing the effective gas flow channel together with the size of the pore throat itself were found to be the most common damage mechanisms of WPT and have proven to be fundamentally beneficial in understanding the controlling factors of these damage mechanisms.

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Wettability modification by fluoride and its application in aqueous phase trapping damage removal in tight sandstone reservoirs

Cited by 63 publications

References 38 publications

Novel Treatment for Mitigating Condensate Bank Using a Newly Synthesized Gemini Surfactant

Novel Treatment for Mitigating Condensate Bank Using a Newly Synthesized Gemini Surfactant

The Effect of Fracturing Fluid Saturation on Natural Gas Flow Behavior in Tight Reservoirs

Investigation of the controlling rock petrophysical factors on water phase trapping damage in tight gas reservoirs

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