Wettability alteration of reservoir rocks to gas wetting condition: A comparative study

Erfani, Hamidreza; Ghazanfari, Mohammad Hossein; Malekabadi, Farzan Karimi

doi:10.1002/cjce.23023

Cited by 24 publications

(10 citation statements)

References 45 publications

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“…In the recent decade, it was demonstrated that some chemical agents could change the rock surface wettability (Dehghan Monfared et al 2016;Azadi Tabar et al 2019a;Arabloo et al 2016;Erfani Gahrooei et al 2017;Gahrooei and Ghazanfari 2017a, b;Maghzi et al 2011Maghzi et al ,2012Mohammadi et al 2012;Gahrooei et al 2017;Sadatshojaei et al 2016;Roustaei et al 2013). Usually, chemical consolidator/stabilizer agents could be adsorbed or glued onto the surface of reservoir rock, and such phenomena might change the inherent wettability of the treated region (around the wellbore) (El-Hoshoudy et al 2017;Failed 2017).…”

Section: Wettability Variationmentioning

confidence: 99%

“…Well productivity of oil and gas reservoirs can be severely impaired by wettability variation around the wellbore. For example, in gas condensate reservoirs, many studies focused on modification of phase mobility by wettability alteration to gas-wet around wellbore (Erfani Gahrooei et al 2017;Gahrooei and Ghazanfari 2017a, b;Gahrooei et al 2017;Azadi Tabar et al 2019c). Typically, these reservoirs are initially single-phase gas, but after pressure decline below the dew point pressure because of gas production, a trapped condensate liquid phase by capillary forces is formed (Aminnaji et al 2015).…”

Section: Future Studiesmentioning

confidence: 99%

See 1 more Smart Citation

A comprehensive research in chemical consolidator/stabilizer agents on sand production control

Tabar¹,

Bagherzadeh²,

Shahrabadi³

et al. 2021

J Petrol Explor Prod Technol

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Sand or fine is a typical product in many processing of oil production from unconsolidated and weakly consolidated formations. High variation of in situ stress, fluid production rate above maximum sand-free rate, and water production are main primary sources of the sand production. Sand production can cause hazardous operational problems to the facilities, pipes, and wellbore. Hence, it is a significant problem that requires to be managed and studied. To minimize the operational impacts of particle migration, chemical consolidators/stabilizers can be utilized to alter surface properties of sand and formation particles. The decreasing zeta potential besides increasing the cohesion between sand and formation particles could result in controlled sand production. However, understanding the mechanism and application of chemical methods to alleviate sand production is not well-discussed. This study presents and discusses chemical consolidator/stabilizer agents, which may be applied for managing sand production in the petroleum industry. This was achieved through a comprehension review of the literature and the application of chemical consolidators/stabilizers in other fields such as bauxite residue (red mud and red sand) control, desert sand, mine reclamation, wind erosion control, unpaved road modification, and enhancement of water retention and soil infiltration properties that are similar to formation sand. Standard experimental methods in various fields, for performance analysis of chemical consolidator/stabilizer agents, are compared and summarized. The consolidation/stabilization mechanisms of various types of chemical consolidator/stabilizer agents are discussed and compared. This review potentially can be used to inhibit blind usage of chemicals and functions as a reference to additional research in sand production control in petroleum engineering. The results are appropriate for extending quantitative approaches for performance evaluation of sand consolidator/stabilizer agents.

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Section: Wettability Variationmentioning

confidence: 99%

Section: Future Studiesmentioning

confidence: 99%

A comprehensive research in chemical consolidator/stabilizer agents on sand production control

Tabar¹,

Bagherzadeh²,

Shahrabadi³

et al. 2021

J Petrol Explor Prod Technol

View full text Add to dashboard Cite

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“…Recently, nanoparticles were used to alter the rock wettability for both carbonate and sandstone formations [37,[42][43][44][45][46]. Aminnaji et al [42] and Erfani Gahrooei et al [43] found that nanofluid can considerably change the wettability of carbonate and sandstone rocks to preferentially gas wet by aging the rocks for around one day. They mentioned that the gas wetting surface could be achieved by increasing the surface roughness and decreasing surface free energy.…”

Section: Introductionmentioning

confidence: 99%

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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“…Several mechanisms are proposed to explain the incremental oil recovery associated with MEOR, among which are the reduction in the oil-water IFT and changes in the wettability of the system and selective plugging mechanism [10][11][12][13]. Numerous experimental and numerical studies have been conducted to understand the impact of wettability alteration and IFT reduction [14][15][16][17][18][19][20][21][22][23][24]. Kowalewski et al [25] showed that the bacterial growth could both reduce IFT and alter the wettability state toward less oil-wet conditions.…”

Section: Introductionmentioning

confidence: 99%

Pore-scale investigation of selective plugging mechanism in immiscible two-phase flow using phase-field method

Sabooniha

Rokhforouz

Ayatollahi

2019

Oil Gas Sci. Technol. – Rev. IFP Energies nouvelles

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Biotechnology has had a major effect on improving crude oil displacement to increase petroleum production. The role of biopolymers and bio cells for selective plugging of production zones through biofilm formation has been defined. The ability of microorganisms to improve the volumetric sweep efficiency and increase oil recovery by plugging off high-permeability layers and diverting injection fluid to lower-permeability was studied through experimental tests followed by multiple simulations. The main goal of this research was to examine the selective plugging effect of hydrophobic bacteria cell on secondary oil recovery performance. In the experimental section, water and aqua solution of purified Acinetobacter strain RAG-1 were injected into an oil-saturated heterogeneous micromodel porous media. Pure water injection could expel oil by 41%, while bacterial solution injection resulted in higher oil recovery efficiency; i.e., 59%. In the simulation section, a smaller part of the heterogeneous geometry was employed as a computational domain. A numerical model was developed using coupled Cahn–Hilliard phase-field method and Navier–Stokes equations, solved by a finite element solver. In the non-plugging model, approximately 50% of the matrix oil is recovered through water injection. Seven different models, which have different plugging distributions, were constructed to evaluate the influences of selective plugging mechanism on the flow patterns. Each plugging module represents a physical phenomenon which can resist the displacing phase flow in pores, throats, and walls during Microbial-Enhanced Oil Recovery (MEOR). After plugging of the main diameter route, displacing phase inevitably exit from sidelong routes located on the top and bottom of the matrix. Our results indicate that the number of plugs occurring in the medium could significantly affect the breakthrough time. It was also observed that increasing the number of plugging modules may not necessarily lead to higher ultimate oil recovery. Furthermore, it was shown that adjacent plugs to the inlet caused flow patterns similar to the non-plugging model, and higher oil recovery factor than the models with farther plugs from the inlet. The obtained results illustrated that the fluids distribution at the pore-scale and the ultimate oil recovery are strongly dependent on the plugging distribution.

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Wettability alteration of reservoir rocks to gas wetting condition: A comparative study

Cited by 24 publications

References 45 publications

A comprehensive research in chemical consolidator/stabilizer agents on sand production control

A comprehensive research in chemical consolidator/stabilizer agents on sand production control

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

Pore-scale investigation of selective plugging mechanism in immiscible two-phase flow using phase-field method

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