1 Introduction
Though renewable energy is developing rapidly, fossil energy remains to be the most important source of energy and global oil consumption would keep rising to meet the needs of social development by 2040 (). Confronted with the situation that “easy oil” is depleting and new oilfield exploration is plummeting, increasing attention has been paid to the high-efficient exploitation and development of unconventional oil resources. Tight oil mainly occurs in tight sandstone, carbonate, or other reservoirs with overlaid matrix permeability less than 0.2 mD or air permeability less than 2 mD (Standard SY/T 6943-2013). The preliminarily proved tight oil geological reserves in China are about 125 × 108 tons (; ) and about 40% of the national recoverable reserves are tight oil. The effective development of tight oil is vital to improving China’s energy structure and ensuring national energy security.
Natural microfractures are ubiquitous in tight oil reservoirs, but the pores/throats are narrow, connectivity is poor, and the formation energy is low, thus, the primary oil recovery of tight reservoirs is generally below 10% (; ). And the advancements in multi-stage horizontal well fracturing technologies have offered some new opportunities to partially relieve these problems (; ). In matrix-fracture dual-permeability media, spontaneous imbibition through which a non-wetting phase is displaced by a wetting phase is regarded as the most probable matrix-fracture transfer mechanism that plays a key role in unlocking the tight oil potentials (). In general, original tight rocks are water-wet, but can be changed to oil-wet after a long time contacting with crude oil when asphaltenes deposit, calcite, and dolomite adsorb organic acids or resin acids and quartz and clay adsorb organic bases and aromatics (). To ensure the occurrence of effective spontaneous imbibition in mix-wet or oil-wet tight reservoirs, the wettability of porous media should always be altered water-wet, and adding chemical agents is indispensable. Surfactants, nanomaterials, and inorganic salts are extensively used to enhance the imbibition rate and boost the oil recovery factor. However, challenges usually coexist with opportunities. In this paper, the potential risks associated with surfactants, nanomaterials, and inorganic salts usage in tight formations are highlighted, and the possible directions for future studies were discussed to guide the effective design of EOR scenarios in tight oil reservoirs.
2 Surfactants
Surfactants with different structures can alter wettability through different means, including ion-pairing, hydrophobic interactions, solubilization, polarization of electrons, etc., (
;
) Numerous studies have been conducted, and the potentials of different types of surfactants to promote spontaneous imbibition in tight formations were verified. For example, cationic surfactant CTAB could extract additional 2.5% OOIP and 7.5% OOIP after brine imbibition from 0.11 mD (water-wet) and 0.018 mD (mix-wet) tight cores, respectively (
). Anionic surfactant petroleum sulfonate could yield an oil recovery of 35.9% from 1 mD tight cores, which was 21.7% higher than brine (
). Nonionic surfactant APG could recover 27.02% OOIP from 0.26–0.31 mD tight sandstone cores, which was 21.02% higher than brine (
). However, there are still many problems to be solved before extending to field tests, such as.
1) Tight formations are abundant in narrow pores and throats, and the clay content can be higher than 15%. The large specific surface area will result in a significant surfactant retention density of 10–30 mg/g (; ), which greatly limits surfactant penetration depth and efficiency. However, the contribution of surfactant adsorption to wettability alteration is also substantial, therefore, the economic and optimal adsorption density, as well as adsorption rate should be better clarified. Moreover, dynamic adsorption tests instead of static adsorption tests based on intact tight cores rather than rock powders should be conducted to mimic the real situations.
2) Surfactant penetration speed and depth are key parameters necessary for surfactant EOR modeling and are important to guide the scaling up of laboratory findings for field operation design (; ). But there is scarce information on the direct measurements of surfactant dispersion coefficient in tight rocks, and the accuracy of numerical models can hardly be verified. Therefore, more laboratory evidence is necessary to increase the robustness and reliability of numerical simulations.
3) Normal surfactants usually undergo either phase change or separation in high temperature and high salinity (HTHS) conditions (; ). Anionic-nonionic, zwitterionic and Gemini surfactants show high salt and thermal tolerance, but their functional mechanisms to induce wettability alteration remain elusive and further research is desperately needed.
4) The cost of surfactants especially novel surfactants is still relatively high. Though the advances in natural surfactants may help to relieve this problem, the industrialization production of natural surfactants still faces many challenges.
5) The current method to screen surfactants for tight formations mainly borrows from conventional reservoirs, without fully considering the specificity of tight formations and the discrepancies in reservoir physical properties. Thus, designing a systematic screening method especially for tight formations is urgent, in which surfactant micelle size, the optimal rock wettability, the adsorption density should be comprehensively considered.
3 Nanomaterials
3.1 Nanoparticles
Nanoparticles (NPs) induce wettability change mainly by forming microstructure formation or imposing structural disjoining pressure, and it is believed that NP adsorption on liquid-liquid/liquid-solid interfaces can increase the stability of water film adsorbed on rocks (
). A summary of the recent progress of NPs applications in tight reservoirs was provided in
Table 1(Part I). Most research showed that nanofluids with or without surfactants were capable to enhance the oil recovery of spontaneous imbibition by over 10% through wettability alteration. However, there is also still more work that needs to be done, for instance.
1) The optimal NP concentration highly depends on NP type, rock properties, solution environment, etc. reported that the highest efficiency of 38.1% could be obtained with 0.1 wt% SiDots in 1 mD tight cores and a further increase in SiDot concentration to 0.5 wt% would decrease the rate to 22.27% due to intense particle aggregation. They also indicated that the optimal SiO2 NP (15 nm) concentration to be in 0.5 mD tight cores was also around 0.1 wt% (). However, held a different view. They highlighted that though viscosity and asphaltene content of the produced oil would decrease with increasing NP concentration, the silica concentration to be used should be around 10 mg/L in 0.68–0.95 mD tight cores to eliminate pore plugging. Authors tried to use pore plugging in most cases to explain the decrease in recovery when NP concentration increased without even knowing whether the nanofluid can seep into the tight cores or not. Therefore, a comprehensive study on NP transport and retention behaviors in tight porous media should be implemented and the permeability damage caused by NPs should better be quantified.
2) The optimal oil/water interfacial tension of nanofluids for tight formation remains bewilderment. systematically appraised the synergistic effects between surfactants and silica NP and highlighted that the IFT and contact angle should be tailored to higher than 1 mn/m and 140°, respectively to maximize the recovery factor of nanofluid spontaneous imbibition. Similarly, both numerical simulations and experimental studies indicated that the optimal IFT to generate satisfying oil recovery in water-wet tight porous media by surfactant imbibition is between 10–20 mn/m (). However, proposed that by further decreasing IFT to 3.5 × 10–3 mn/m and water contact angle to 48°, AOS-based silica nanofluid could recover 28.5% OOIP from 0.1 mD tight cores, comparing to those of 8.9 and 14.33% OOIP by brine and surfactant, respectively. To clear the confusion, further microscopic mechanism study on how IFT will affect the spontaneous imbibition by increasing the capillary number and/or capillary force is necessary and urgent.
3) The stability of nanofluid is preliminary for its applications and surfactants are generally used to disperse the NP. However, the applications of nanofluids in HTHS conditions are still limited and nanofluids with higher thermal and salt resistance should be developed. To improve the stability of NPs, ligands with dendritic structure or copolymers can be used (; ), but particle size should be carefully screened, and smaller particles are better preferred.
4) Structural disjoining pressure is proposed as the underlying mechanism in most studies to explain the wettability alteration by nanofluids by simply drawing a schematic diagram without compelling substantial evidence. Further study on the microscopic pore-scale wettability alteration mechanisms is required, and dynamic imbibition and pilot field tests should be conducted to convince the efficiency of NPs.
5) The cost of NPs is relatively high and industrial methods to produce functional NPs should be developed. Also, NP toxicity and its adverse impacts should be clearly defined.
TABLE 1
| Part I nanoparticle | |||||||||
|---|---|---|---|---|---|---|---|---|---|
| Nanoparticle | Size, nm | C, mg/L | Additives | k, mD | Solution environment | IFT, mN/m | Contact angle, ° | Recovery incremental, % | Ref |
| Carbon NP | 10 | 500 | — | 0.6 | 3% NaCl, 60°C | 16.4 | 98 (oil) | 22.3 (Imbibition) | |
| SiO2 NP | 19.4 | 10 | — | 0.68–0.95 | 0.75% NaCl, 50°C | — | 90–128 (oil) | 5.32–10.33 (Flooding) | |
| SiO2 NP (Modified) | 10–20 | 10,000 | — | 0.6 | 3% NaCl, 60°C | 7.0 | 142 (oil) | 25.0 (Imbibition) | |
| SiO2 (Modified) | 15 | 1,000 | — | 0.5 | 3% NaCl, 60°C | 12.2 | 120 (oil) | ∼24.5 (Imbibition) | |
| SiO2 (Modified) | — | 5,000 | — | 0.009 | 12.65% brine 25°C | 0.267–0.190 | 57 (water) | — | |
| Silicon dots (Modified) | 3–5 | 1,000 | — | 1.0 | Low salinity, 60 °C | 18.7 | — | 23.9 (Imbibition) | |
| NP | 10–20 | 3,000 | — | 0.013–0.077 | DI, 20°C | 1 | — | — | |
| Carbon NP | 7 | 1,500 | 0.05% Tween-80 | 0.113–0.125 | 3% NaCl, 75°C | 11.2 | 89 (oil) | 13.0 (Imbibition) | |
| SiO2 NP | 20.56 | 100 | 0.05% KD | 0.2–0.3 | 1% NaCl, 90°C | 4 × 10–4 | 140 (oil) | 17.64 (Flooding) | |
| SiO2 NP | 20 | 1,000 | 0.1% AOS | 0.1 | 3% brine, 80°C | 3.5 × 10–3 | 131.8 (oil) | 19.6 (Imbibition) | |
| SiO2 NP | 10 | 500 | 0.1% SLES | 0.072–0.088 | DI | ∼6.0 | 155 (oil) | 28.71 (Imbibition) | (; ) |
| Silicon dots | 5 | 1,200 | 0.1% Betaine | 0.0091 | 15% brine, 80°C | 0.085 | 124.1 (oil) | 13.39 (Imbibition) | |
| Part II Nanoemulsions | |||||||||
| Shell | Kernel | C, mg/L | Size, nm | k, mD | Solution environment | IFT, mN/m | Contact angle, ° | Recovery incremental, % | Ref |
| C8−C12 alkane | Gemini surfactant | 3,000 | <25 | 0.1–0.3 | 0.77% brine, 90°C | 1 × 10–2 | — | 27.5 (Flooding) | |
| Alkanes or olefins | Non-ionic surfactant | 1,000 | 14 | 0.005 | 2% KCl, 85°C | 2.6 | 126.8 (oil) | 30 (Imbibition) | |
| C10−C14 alkane | Diphenyl ether surfactant | 1,000 | 15.7 | 0.1 | 3.08% brine, 70°C | 10–2 | 76.6 (water) | 19.2 (Imbibition) | |
| Cyclooctane | Non-ionic surfactant | 500–3,000 | 10 | 0.0839–0.101 | DI, 60°C | 3.56 | 11.7 (water) | 7.53–24.83 (Imbibition) | |
| N-hexane | Non-ionic, cationic surfactants | 3,000 | 6–11 | 0.1 | 0–1% brine, 60°C | 0.005 | 32.7 (water) | 20.5 (Imbibition) | |
Nanomaterials for tight formation EOR.
3.2 Nano-emulsions
Broadly speaking, nanodroplets such as nanoemulsions with sizes between 10–100 nm can also be identified as nanomaterials (
). Nanoemulsions are generally characterized by a “shell-kernel” structure, in which surfactant functions as an external “shell” and disassociation agents (i.e., alkanes, cycloalkanes, etc.,) form the kernel (
). Compared to NPs mentioned in
Section 3.1, nanoemulsions are kinetically stable and may be deformable (
). By splitting the crude oil into “nanosized oil droplets”, reducing IFT, alternating wettability, and increasing sweep efficiency, the average recovery incremental by nano emulsions over brine imbibition was higher than 20% (
Table 1, Part II), indicating huge EOR potential. However, the large-scale applications of nano-emulsions still face many challenges, such as.
1) Preparing nano emulsions consumes tremendous amounts of chemicals including surfactants, co-surfactants, organic solvents, etc., and the substantial energy might be required to promote the emulsification process, which greatly increases the cost. Thus, high-efficiency chemicals with lower costs and more economic emulsification methods should be developed.
2) Nanoemulsions are thermodynamically unstable and phase separation is unavoidable, but the influence laws of temperature, salinity, formula composition, and other factors and their transport behaviors in the complex porous media are not well comprehended, and extensive lab-scale and pilot tests are necessary.
4 Inorganic salts
Low salinity water (LSW) EOR has received considerable attention in recent decades thanks to its environmental-friendly and economical nature. The wettability alteration mechanisms of LSW include multi-ionic exchange, electrical double-layer effect, fine release, etc., and its effectiveness to enhance oil recovery has been widely confirmed through both laboratory and field scale tests (
;
;
). For instance, an incremental spontaneous imbibition oil recovery of 4.5% OOIP was reported by
when a brine with 0.21% TDS was applied in 0.3 mD tight cores.
revealed that an incremental recovery of over 10% could be obtained in 1.56 mD chalk cores by diluted seawater at the second stage compared to seawater.
noticed a 25–50% reduction in residual oil saturation near the well region in a field-scale LSW flooding test. Overall, the research on LSW spontaneous imbibition in tight formations is relatively less common than surfactants or nanomaterials. The potential reasons may include.
1) LSW is viewed as an immature EOR technique with complicated EOR mechanisms, and due to the complex oil/brine/rock interactions, there is still no consensus over the dominant mechanisms so far. Also, though synergisms between LSW and surfactant/NPs to facilitate the spontaneous imbibition rate have been reported, their interactions, as well as the synergistic mechanisms are subject to debate.
2) The efficiency of LSW highly depends on brine salinity and composition and is sensitive to connate water saturation/composition, initial rock wettability, clay content, oil composition, etc., therefore, the benefits can hardly be ensured (; ). Meanwhile, higher sulfate concentration is conducive to increased oil recovery but can also cause souring and scaling problems. The effects of fine release induced by LSW remain controversial, either a reduction or an increase in oil recovery is possible and the boundaries are yet to be identified. Also, the adverse impacts of clay expansion in LSW are not fully considered.
3) In most cases, seawater can hardly be used directly for LSW EOR and the compositions of LSW should be tailored by dissolving inorganic salts in freshwater or distilled water. The desalination of seawater usually requires high input, and the efficiency is generally low.
Statements
Author contributions
XZ: conceptualization, supervision, funding acquisition, and writing—original draft, review and editing. GS: conceptualization, supervision, funding acquisition, and writing—review and editing, XC: funding acquisition and investigation. YW, SZ, and LZ: investigation and editing.
Funding
This work was supported by the Natural Science Foundation of China (NSFC) (Grant No.52104019), the Open Fund of Hubei Key Laboratory of Drilling and Production Engineering for Oil and Gas (Yangtze University) (Grant No. YQZC202203) and the Innovation and Entrepreneurship Training program for College Students of Yangtze University (Grant No. Yz2021238).
Conflict of interest
The authors declare that the research was conducted in the absence of any commercial or financial relationships that could be construed as a potential conflict of interest.
Publisher’s note
All claims expressed in this article are solely those of the authors and do not necessarily represent those of their affiliated organizations, or those of the publisher, the editors and the reviewers. Any product that may be evaluated in this article, or claim that may be made by its manufacturer, is not guaranteed or endorsed by the publisher.
References
1
AljabriN. M.NanS.AdrianC. (2021). Nanoemulsion: An emerging technology for oilfield applications between limitations and potentials. J. Pet. Sci. Eng.208, 109306. 10.1016/j.petrol.2021.109306
2
BidhendiM. M.KazempourM.IbangaU.ArrudaJustinLantzMikeMazonCooperet al (2019). “A set of successful chemical EOR trials in permian basin: Promising field and laboratory results,” in Presented at the SPE/AAPG/SEG unconventional resources technology conference (Denver, CO: Society of Petroleum Engineers). 10.15530/urtec-2019-881
3
DingB.GuanB.LiuW.ChenB.SunJ.LiM.et al (2021). Mechanism of improving water flooding using the nanofluid permeation flooding system for tight reservoirs in Jilin oilfield. Energy fuels.35 (21), 17389–17395. 10.1021/acs.energyfuels.1c02043
4
HarimiB.MasihiM.Mirzaei-PaiamanA.HamidpourE. (2019). Experimental study of dynamic imbibition during water flooding of naturally fractured reservoirs. J. Pet. Sci. Eng.174, 1–13. 10.1016/j.petrol.2018.11.008
5
HouB.WangY.YongH. (2015). Mechanistic study of wettability alteration of oil-wet sandstone surface using different surfactants. Appl. Surf. Sci.330, 56–64. 10.1016/j.apsusc.2014.12.185
6
KatendeA.SagalaF. (2019). A critical review of low salinity water flooding: Mechanism, laboratory and field application. J. Mol. Liq.278, 627–649. 10.1016/j.molliq.2019.01.037
7
LiY.DaiC.ZhouH.WangX.LvW.WuY.et al (2017). A novel nanofluid based on fluorescent carbon nanoparticles for enhanced oil recovery. Ind. Eng. Chem. Res.56 (44), 12464–12470. 10.1021/acs.iecr.7b03617
8
LiY.DaiC.ZhouH.WangX.LvW.ZhaoM. (2018). Investigation of spontaneous imbibition by using a surfactant-free active silica water-based nanofluid for enhanced oil recovery. Energy fuels.32 (1), 287–293. 10.1021/acs.energyfuels.7b03132
9
LiangT.ZhaoX.YuanS.ZhuJ.LiangX.LiX.et al (2021a). Surfactant-EOR in tight oil reservoirs: Current status and a systematic surfactant screening method with field experiments. J. Pet. Sci. Eng.196, 108097. 10.1016/j.petrol.2020.108097
10
LiangX.ZhouF.LiangT.WangR.SuH.YuanS. (2021b). Mechanism of using liquid nanofluid to enhance oil recovery in tight oil reservoirs. J. Mol. Liq.324, 114682. 10.1016/j.molliq.2020.114682
11
LiuZ.ZhaoG.BrewerM.LvQ.SudholterE. J. (2021). Comprehensive review on surfactant adsorption on mineral surfaces in chemical enhanced oil recovery. Adv. Colloid Interface Sci.294, 102467. 10.1016/j.cis.2021.102467
12
LuT.LiZ.ZhouY.ZhangC. (2017). Enhanced oil recovery of low-permeability cores by SiO2 nanofluid. Energy fuels.31 (5), 5612–5621. 10.1021/acs.energyfuels.7b00144
13
LyuC.ZhongL.NingZ.ChenM.ColeD. R. (2022). Review on underlying mechanisms of low salinity waterflooding: Comparisons between sandstone and carbonate. Energy fuels.36 (5), 2407–2423. 10.1021/acs.energyfuels.1c04248
14
MokhtariR.AnabaraonyeB. U.AfroughA.MohammadkhaniS.FeilbergK. L. (2022). Experimental investigation of low salinity water-flooding in tight chalk oil reservoirs. J. Pet. Sci. Eng.208, 109282. 10.1016/j.petrol.2021.109282
15
PatilP. D.RohillaN.KatiyarA.FalconeSusanNelsonChristopherRozowskiPeteret al (2018). “Surfactant based EOR for tight oil reservoirs through wettability alteration: Novel surfactant formulations and their efficacy to induce spontaneous imbibition,” in Presented at the SPE EOR conference at oil and Gas west asia (Muscat, Oman: Society of Petroleum Engineers). 10.2118/190397-MS
16
QiuR.GuC.XueP.XuD.GuM. (2022). Imbibition characteristics of sandstone cores with different permeabilities in nanofluids. Petroleum Explor. Dev.49 (2), 374–381. 10.1016/s1876-3804(22)60031-4
17
QuM.LiangT.XiaoL.HouJ.QiP.ZhaoY.et al (2022). Mechanism study of spontaneous imbibition with lower-phase nano-emulsion in tight reservoirs. J. Pet. Sci. Eng.211, 110220. 10.1016/j.petrol.2022.110220
18
SagalaF.MontoyaT.HethnawiA.VitaleG.NassarN. N. (2019). Nanopyroxene-based nanofluids for enhanced oil recovery in sandstone cores at reservoir temperature. Energy fuels.33, 877–890. 10.1021/acs.energyfuels.8b03749
19
ShenZ.ZhaoZ.KangW. (2012). Colloid and surface chemistry. 4th Edition, 39. Beijing: Chemical Industry Press. 978-7-122-12982-6.
20
ShengJ. J. (2014). Critical review of low-salinity waterflooding. J. Pet. Sci. Eng.120, 216–224. 10.1016/j.petrol.2014.05.026
21
SunL.ZouC.JiaA.WeiY.ZhuR.WuS.et al (2019). Development characteristics and orientation of tight oil and gas in China. Petroleum Explor. Dev.46 (06), 1073–1087. 10.1016/S1876-3804(19)60264-8
22
SunY. P.XinY.LyuF. T.DaiC. L. (2021). Experimental study on the mechanism of adsorption-improved imbibition in oil-wet tight sandstone by a nonionic surfactant for enhanced oil recovery. Pet. Sci.18 (4), 1115–1126. 10.1016/j.petsci.2021.07.005
23
WangF.ChengH.SongK. (2021). A mathematical model of surfactant spontaneous imbibition in a tight oil matrix with diffusion and adsorption. Langmuir37 (29), 8789–8800. 10.1021/acs.langmuir.1c01139
24
WangH.MaF.TongX.LiuZ.ZhangX.WuZ.et al (2016). Assessment of global unconventional oil and gas resources. Petroleum Explor. Dev.43, 925–940. 10.1016/S1876-3804(16)30111-2
25
WangJ.LiuH.QianG.YongcanP.YangG. (2019). Investigations on spontaneous imbibition and the influencing factors in tight oil reservoirs. Fuel236, 755–768. 10.1016/j.fuel.2018.09.053
26
WangW.ShahvaliM.SuY. (2015). A semi-analytical fractal model for production from tight oil reservoirs with hydraulically fractured horizontal wells. Fuel158, 612–618. 10.1016/j.fuel.2015.06.008
27
WangX.PengX.ZhangS.DuZ.ZengF. (2018). Characteristics of oil distributions in forced and spontaneous imbibition of tight oil reservoir. Fuel224 (15), 280–288. 10.1016/j.fuel.2018.03.104
28
WebbK. J.BlackC. J. J.Al-AjeelH. (2003). “Low salinity oil recovery—log-inject-log,” in Presented at the SPE/DOE symposium on improved oil recovery (Tulsa, Oklahoma: Society of Petroleum Engineers). 10.2118/89379-MS
29
WeiB.WangL.SongT.ZhongM.VarfolomeevM. A. (2021). Enhanced oil recovery by low-salinity water spontaneous imbibition (LSW-SI) in a typical tight sandstone formation of mahu sag from core scale to field scale. Petroleum7 (3), 272–281. 10.1016/j.petlm.2020.09.005
30
XuD.BaiB.MengZ.ZhouQ.LiZ.LuY.et al (2018). “A novel ultra-low interfacial tension nanofluid for enhanced oil recovery in super-low permeability reservoirs,” in Presented at the SPE asia pacific oil and Gas conference and exhibition (Brisbane, QLD: Society of Petroleum Engineers). 10.2118/192113-MS
31
YaoY.WeiM.KangW. (2021). A review of wettability alteration using surfactants in carbonate reservoirs. Adv. Colloid Interface Sci.294, 102477. 10.1016/j.cis.2021.102477
32
YuH.FuW.ZhangY.LuX.ChengS.XieQ.et al (2021). Experimental study on EOR performance of CO2-based flooding methods on tight oil. Fuel290 (15), 119988. 10.1016/j.fuel.2020.119988
33
YuanL.ZhangY.DehghanpourH. (2021). A theoretical explanation for wettability alteration by adding nanoparticles in oil-water-tight rock systems. Energy fuels.35 (9), 7787–7798. 10.1021/acs.energyfuels.1c00001
34
ZhangC.JinX.TaoJ.XiongB.PanZ.MengS.et al (2021). Comparison of nanomaterials for enhanced oil recovery in tight sandstone reservoir. Front. Earth Sci.9, 746071. 10.3389/feart.2021.746071
35
ZhangJ.WangD.OlatunjiK. (2016). “Surfactant adsorption investigation in ultralower permeable rocks,” in Presented at the SPE low perm symposium (Kuala Lumpur, Malaysia: Society of Petroleum Engineers). 10.2118/180214-MS
36
ZhangT.LiZ.GaoM.XuZ.AdenutsiC. D.YouQ. (2022a). New insights into the synergism between silica nanoparticles and surfactants on interfacial properties: Implications for spontaneous imbibition in tight oil reservoirs. J. Pet. Sci. Eng.215, 110647. 10.1016/j.petrol.2022.110647
37
ZhangT.ZhiP.AdenutsiC. D.WeiY. Z.MaZ. F.YouQ. (2022b). Quantitative investigation of nanofluid imbibition in tight oil reservoirs based on NMR technique. Pet. Sci.In Press. 10.1016/j.petsci.2022.04.013
38
ZhaoM.ChengY.WuY.DaiC.GaoM.YanR.et al (2022a). Enhanced oil recovery mechanism by surfactant-silica nanoparticles imbibition in ultra-low permeability reservoirs. J. Mol. Liq.348, 118010. 10.1016/j.molliq.2021.118010
39
ZhaoM.SongX.LvW.WuY.DaiC. (2020). The preparation and spontaneous imbibition of carbon-based nanofluid for enhanced oil recovery in tight reservoirs. J. Mol. Liq.313, 113564. 10.1016/j.molliq.2020.113564
40
ZhaoY.HouJ.QuM.XiaoL.LiuY. (2022b). Performance evaluation and oil displacement mechanism analysis of nano-microemulsion using in tight oil reservoirOilfield Chem.39 (02), 338–342. 10.3760/cma.j.112147-20220225-00152
41
ZhongX.LiC.LiY.PuH.ZhouY.ZhaoJ. X. (2020). Enhanced oil recovery in high salinity and elevated temperature conditions with a zwitterionic surfactant and silica nanoparticles acting in synergy. Energy fuels.34 (3), 2893–2902. 10.1021/acs.energyfuels.9b04067
42
ZhongX.PuH.ZhouY.ZhaoJ. X. (2019). Comparative study on the static adsorption behavior of zwitterionic surfactants on minerals in Middle Bakken formation. Energy fuels.33, 1007–1015. 10.1021/acs.energyfuels.8b04013
43
ZhouB.YouQ.LiY.ChuZ.ZhangL.WangP.et al (2022). Preparation and performance evaluation of an active nanofluid for enhanced oil recovery in ultra-low permeability reservoirs. J. Mol. Liq.347, 118331. 10.1016/j.molliq.2021.118331
44
ZhouH.ZhangQ.DaiC.LiY.LvW.WuY.et al (2019). Experimental investigation of spontaneous imbibition process of nanofluid in ultralow permeable reservoir with nuclear magnetic resonance. Chem. Eng. Sci.201, 212–221. 10.1016/j.ces.2019.02.036
45
ZhouY.WuX.ZhongX.ZhangS.PuH.ZhaoJ. X. (2020). Development of silicon quantum dots based nano-fluid for enhanced oil recovery in tight Bakken cores. Fuel277, 118203. 10.1016/j.fuel.2020.118203
46
ZunigaG. A.GoodsJ. B.CoxJ. R.SwagerT. M. (2016). Long-term high-temperature stability of functionalized graphene oxide nanoplatelets in Arab-D and API brine. ACS Appl. Mat. Interfaces8 (3), 1780–1785. 10.1021/acsami.5b09656
Summary
Keywords
wettability alteration, spontaneous imbibition, tight reservoirs, achievements, limitations, enhanced oil recovery
Citation
Zhong X, Sheng G, Chen X, Wang Y, Zhang S and Zhang L (2022) Wettability alteration agents to promote spontaneous imbibition in tight reservoirs: Achievements and limitations. Front. Earth Sci. 10:1010741. doi: 10.3389/feart.2022.1010741
Received
03 August 2022
Accepted
12 August 2022
Published
08 September 2022
Volume
10 - 2022
Edited by
Qingbang Meng, China University of Geosciences Wuhan, China
Reviewed by
Dezhi Qiu, Guangzhou Marine Geological Survey, China
Xiao Z. Hang, Shandong University, China
Updates
Copyright
© 2022 Zhong, Sheng, Chen, Wang, Zhang and Zhang.
This is an open-access article distributed under the terms of the Creative Commons Attribution License (CC BY). The use, distribution or reproduction in other forums is permitted, provided the original author(s) and the copyright owner(s) are credited and that the original publication in this journal is cited, in accordance with accepted academic practice. No use, distribution or reproduction is permitted which does not comply with these terms.
*Correspondence: Guanglong Sheng, shenggl2019@yangtzeu.edu.cn
This article was submitted to Frontiers in Earth Science, a section of the journal Geochemistry
Disclaimer
All claims expressed in this article are solely those of the authors and do not necessarily represent those of their affiliated organizations, or those of the publisher, the editors and the reviewers. Any product that may be evaluated in this article or claim that may be made by its manufacturer is not guaranteed or endorsed by the publisher.