Nanoparticles in Chemical EOR: A Review on Flooding Tests
Abstract
:1. Introduction
2. Review
2.1. Nanoparticles
2.2. Functionalised Nanoparticles
2.3. Alcohol + Nanoparticles
2.4. Surfactant + Nanoparticles
2.5. Polymer + Nanoparticles
2.6. Surfactant + Polymer + Nanoparticles
3. Conclusions
- The literature on the topic is sometimes confusing. Many tests (stability, rheology, IFT, contact-angle, etc.) are carried out, sometimes in the absence of salts and other times in their presence, before the final flooding experiments. As a consequence, the exact composition of the formulation tested in these studies is frequently unclear, especially regarding the presence of salts in the nanofluids. Future works should clearly define the formulation used in oil recovery studies.
- The greatest challenge for EOR in general, and for nano-EOR in particular, is the design of a stable formulation at harsh conditions (temperature and salinity) also considering the presence of divalent ions. This is a difficult task common to all EOR methods, but it is likely more difficult in the presence of nanoparticles. Very few works address the whole problem.
- The simplest and most cost-effective nano-EOR method involves the use of nanofluids consisting only of water or brine and common nanoparticles. Additional oil recoveries achieved with these systems are comparable to those achieved with other EOR methods and justify, in principle, their use to promote oil recovery.
- Even though the number of papers published with simple nanofluids is rather significant, there is not enough information to select the best type and size of nanoparticles according to the application (type of rock, permeability, formation brine, reservoir conditions, etc.). Critically, the number of studies in carbonate rocks is very limited.
- Size and more importantly concentration are key factors that seem to be more critical than the type of nanoparticle for success in practice. The nanofluid concentration must be optimised according to core permeability. Excessive concentration generates aggregation and blocking problems, thus limiting oil extraction and creating pressure problems. Nanoparticle concentration higher than 0.2 wt% is rarely recommended.
- SiO2 nanoparticles are cost-effective and are consequently the most often proposed for the application. Colloidal are preferred to fumed nanoparticles in order to avoid aggregation problems. Al2O3 is sometimes proposed for harsh environments.
- Many experimental studies have confirmed significant adsorption of nanoparticles onto the rock surface during the flooding process. This presents a challenge to nano-EOR due to the associated environmental hazards and operation costs.
- According to several studies, the performance of nanofluids is better when applied as a secondary rather than tertiary EOR method. However, the cost of this injection method is a limiting factor.
- Nanofluid stability is a bottle-neck that sometimes can only be improved using dispersions in alcohols or via the use of different stabilizers.
- Nanoparticles favour disjoining pressure to sweep the oil droplets from rock surfaces. According to the studies presented, the main mechanism is wettability alteration. In certain cases, a reduction in water–oil IFT is also found. However, the addition of a surfactant to the nanofluid drastically enhances this reduction, at the same time as improving or worsening the stability of the nanoparticles.
- To avoid excessive adsorption, cationic surfactants are recommended for carbonate and anionic ones for sandstone rocks. However, a general rule cannot be established regarding the best type of nanoparticles according to surfactant type. More work is required in this line of research.
- Polymers, mixed with nanoparticles or used to functionalise them, are usually employed to improve the stability of nanofluids. Nanoparticles help the polymer to increase aqueous viscosity but also reduce apparent oil viscosity and improve its rheological behaviour.
- The synergy of combining nanoparticles, polymers and surfactants leads to promising formulations for EOR. However, designed formulations are complicated and involve high costs. Moreover, the protocol used to prepare the mixtures, especially in the presence of salts, has to be clearly defined.
- The combination of SAILs with nanoparticles is a niche that must be further explored.
- The flooding equipment used in the tests, as well as the type of core and initial conditions, drastically affect oil recoveries with nanofluids, sometimes leading to very optimistic numbers that should be verified.
- A striking absence of information regarding the costs of nano-EOR methods per incremental bbl, a decisive factor for industrial applications, was noted and needs to be addressed.
- Despite the significant number of laboratory studies carried out, the Technology Readiness Level of nano-EOR is still very low; thus, a lot of effort needs to be made to prove the current system in operational environments.
- In summary, there still exists a need for systematic and rigorous works on EOR with nanoparticles, in order to establish general rules for the best design of nanofluids for practical applications.
Author Contributions
Funding
Acknowledgments
Conflicts of Interest
Nomenclature
AOR | Additional oil recovery |
AOS | Alpha olefin sulfonate |
API | American Petroleum Institute |
CAPD | Cocamido propyl betaine |
CMC | Carboxy methyl cellulose |
CNT | Carbon nanotubes |
CTAB | Hexadecyltrimethylammonium bromide |
DTAB | Dodecyltrimethylammonium bromide |
EOR | Enhanced oil recovery |
GA | Gum Arabic |
HAHPAM | Hydrophobic association of partially hydrolysed polyacryamide |
HPAM | Hydrolysed polyacrylamide |
IFT | Interfacial tension |
JGO | Janus graphene oxide |
MWCNTs | Multi-wall carbon nanotubes |
OOIP | Original oil in place |
PAM | Polyacrylamide |
PSP | Potato peel starch |
PVP | Polyvinylpyrrolidone |
r.t. | Room temperature |
SAILs | Surface-active ionic liquids |
SEM | Scanning electron microscopy |
SDBS | Sodium dodecylbenzene sulfonate |
SDS | Sodium dodecyl sulphate |
SSW | Synthetic sea water |
SW | Sea water |
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Nanoparticles | Concentration (wt%) | T (°C) | Dispersion Media | Oil | Rock Type | Rock Properties | AOR (%OOIP) | Ref |
---|---|---|---|---|---|---|---|---|
SiO2 | 0.01–0.1 | 20 | 3.0 wt% NaCl | North Sea | Berea sandstone (low-permeability) | Ø: 13.93–15.02% µ: 9–35 mD | 0–6.14 | [18] |
SiO2 | 0.01–0.1 | 20 | 3.0 wt% NaCl | North Sea | Berea sandstone (high-permeability) | Ø: 20.01–23.20% µ: 156–392 mD | 4.26–5.32 | [18] |
SiO2 | 0.05 | 25 50 80 | 3.0 wt% NaCl | Light | Berea sandstone | Ø: 15–19% µ: 100–600 mD | 0.81–5.86 1 3.91–10.87 1 6.02–10.11 1 | [19] |
SiO2 | 0.05 | r.t. | SSW | North Sea | Berea sandstone | Ø: 15–17 % µ: 100–600 mD | 1.98–18.52 1 | [20] |
SiO2 | 0.01–0.5 | r.t. | 3.0 wt% NaCl | North Sea | Sandstone | Ø: 19.4–21.7 % µ: 285–587 mD | ≤13.3 | [21] |
SiO2 | 5 × 10−4–0.003 | 50 | 7500 mg/L NaCl | Shengli oilfield | Feldspar (53%) | Ø: 9.35−11.95% µ: 0.68−0.95 mD | 4.48–10.33 1 | [22] |
SiO2 | 0.02–0.1 | r.t. | 2–4 wt% NaCl | Paraffin | Sandstone | Ø: 20.72–27.65% µ: 465–603 mD | 6.58–11.2 | [24] |
SiO2 | 0.01–0.1 | r.t. | 3 wt% NaCl | North Sea | Sandstone | Ø: 20.01–23.20% µ: 156–392 mD | 4.26–5.32 | [41] |
SiO2 Fumed/colloidal | 0.01–0.1 | r.t. | Synthetic North Sea brine 3 | North Sea | Sandstone | Ø: 17.8–20.8% µ: 285–438 mD | 2.36–11.76 | [42] |
SiO2 | 0.01–3 | r.t. | Water 4 | Mineral oil | Bahariya sandstone | Ø: 26% µ: 378.73 mD | 40–79 2 | [43] |
SiO2 | 0.1 | r.t. | Water 4 | Mineral oil | Sandstone | Ø: 29.87–30.75% µ: 575.82–642.65 mD | 65.36–77.94 2 | [44] |
SiO2 | 0.01–0.1 | r.t. | 3 wt% NaCl | Heavy | Berea sandstone | Ø: 17.4–20.3% µ: 60 mD | 28.56–38.57 2 | [45] |
SiO2 Aerosil 200 | 0.05–1 | 100 | Water 4 | Iranian | Carbonate | Ø: 14.379–15.823% µ: 1.0119–1.9552 mD | 57.23–65.23 2 | [26] |
SiO2 Aerosil R 816 | 0–1 | 100 | Water 4 | Iranian | Carbonate | Ø: 13.268–14.949% µ: 1.0347–1.2446 mD | 55.45–80.2 2 | [27] |
SiO2 | 0.005 | 26 40 50 60 | Water 4 | Malaysian | Limestone grains | Ø: 41.1–43.2%. µ: 220–240 mD | 2.0 2.5 2.8 2.9 | [35] |
TiO2 Anatase | 0.01 | 75 | 5000 ppm NaCl | Heavy | Sandstone | Ø: 23.7 % µ: 84 mD | 80 2 | [30] |
TiO2 Rutile | 0–0.05 | r.t. | 0.1 mol/dm 3 NaCl | Mineral oil | Berea sandstone | Ø: 20.82–21.20% µ: 98.73–195.46 mD | 30.3–41.8 2 | [31] |
TiO2 | 0.01–0.1 | r.t. | 3 wt% NaCl | Heavy | Berea sandstone | Ø: 20.0–24.0% µ: 60 mD | 15.69–34.42 2 | [45] |
TiO2 | 0.005 | 26 40 50 60 | Water4 | Malaysian | Limestone grains | Ø: 42.3–43.3%. µ: 203–236 mD | 3.0 4.1 5.2 6.6 | [35] |
Aluminosilicate | 10−4–0.002 | 60 | Formation brine Langgak field | Indonesia | Bentheimer sandstone | Ø: 19.33–20.37% µ: 316.93–633.76mD | 4.44–15.59 | [32] |
Al2O3 | 0.01–0.1 | r.t. | 3 wt% NaCl | Heavy | Berea sandstone | Ø: 19.7–20.4% µ: 60 mD | 32.32–38.70 2 | [45] |
γ-Al2O3 | 0.5 | r.t. | Water 4 | Ahwaz oilfield | Carbonate | Ø: 17.3% µ: 0.807 mD | 11.25 | [33] |
Al2O3 | 0.005 | 26 40 50 60 | Water 4 | Malaysian | Limestone grains | Ø: 41.8–43.1%. µ: 205–230 mD | 4.5 5.4 7.0 9.9 | [35] |
SnO2 | 0–0.5 | r.t. | SSW | Ahwaz oilfield | Carbonate | Ø: 18% µ: 0.22 mD | 39–61 1,2 | [34] |
NiO | 0.01– 0.1 | r.t. | 3 wt% NaCl | Heavy | Berea sandstone | Ø: 19.0–21.8% µ: 60 mD | 31.45–36.20 2 | [45] |
SiO2 + Al2O3 (50 wt%) | 0.01– 0.1 | r.t. | 3 wt% NaCl | Heavy | Berea sandstone | Ø: 20.2–20.6% µ: 60 mD | 24.85–42.29 2 | [45] |
SiO2 + Al2O3 (50 wt%) | 0.05 | r.t. 80 | 16 wt% NaCl | Heavy | Berea sandstone | Ø: 16.1–20.7% µ: 60 mD | 29.36 2 56.72 2 | [45] |
Magnetite +Magnetic Field | 0.8 | r.t. | 5000 ppm NaCl3 | Van Gogh/Kuwait | Berea sandstone | Ø: 18.94–21.51%. µ: 60–82 mD | 6.32–15.38 1 8.57–16.20 1 | [37] |
Fe3O4 +Magnetic Field | 0.05 | r.t. | 11,000 ppm NaCl | Light | Berea sandstone | 15.8 29.4 | [38] | |
SiO2 +Smart Water | 0.1 | 85 | Formation brine + SO42− | Iranian | Carbonate (Dolomite) | Ø: 19.69% µ: 1.0 mD | ~11.3 | [39] |
SiO2 +Smart Water | 0.05 | 60 | Water + MgCl2 + CaCl2 + Na2SO4 | Iranian (asphaltenic) | Carbonate | 45.6 | [40] |
Nanoparticles | Concentration (wt%) | T (°C) | Dispersion Media | Oil | Rock Type | Rock Properties | AOR (%OOIP) | Ref |
---|---|---|---|---|---|---|---|---|
Nano-hybrid SiO2-HAHPAM | 0.5 HAHPAM/ 0.5 Silica | 85 | Synthetic brine with divalent ions | Shengli | Silica sand | Ø: 32.6 % µ: 1498 mD | 10.57 | [46] |
Pyroxenes | 0.005 | 60 | 2 wt% NaCl | Canada | Berea sandstone | Ø: 19.2 % µ: 63 mD | 10.57 | [47] |
Amphiphilic silica | 0.1 | 90 | Water 1 | Paraffin:Kerosene 10:3 | Sandstone | Ø: 20.7–21.4 % µ: 50–800 mD | 2.6–10.3 | [48] |
SiO2@Montmorilant @Xanthan | 0.1 | 60 | Water 1 | Gachsaran oilfield | Sandstone | Ø: 15.32 % µ: 30 mD | 15.79 | [49] |
SiO2@Montmorilant @Xanthan | 0.025 | 60 | Water 1 | Gachsaran oilfield | Carbonate | Ø: 12.82 % µ: 8.23 mD | 11.72 | [49] |
ZnO/SiO2/ Xanthan | 0.2 | 75 | Dilute SW | Medium | Carbonate | Ø: 16.85 % µ: 13.15 mD | 19.28 | [50] |
Fe3O4@Chitosan | 0–0.03 | r.t. | SW 2 | Iranian | Carbonate sand | 56.7–67.5 3 | [51] | |
Polymer-citrate-coated Fe3O4 | 0.02–0.04 | 85 | SSW (mixture of formation water and SW) | Iranian | Silane glass beads | Ø: 23–25% µ: 320–340 mD | 12.2–19.7 | [52] |
Polymer-citrate-coated Fe3O4 | 0.04 | 85 | SSW (mixture of formation water and SW) | Iranian | Carbonate | Ø: 17.8% µ: 34.12 mD | 28 | [52] |
KH550-MoS2 | 0.005 | 55 | Synthetic formation brine | Changqing oilfield | Chloritization and illite | Ø: 36.22–38.1% µ: 7.8–8.4 mD | 14 | [53] |
Graphene-based amphiphilic Janus Nanosheets | 0.005–0.01 | r.t. | 4 wt% NaCl + 1 wt% CaCl2 | China oilfield | Sandstone sand-packs | Ø: 24.8–27.9% µ: 44.5–132 mD | 6.7–15.2 | [54] |
Amine/organosiloxane @Al2O3/SiO2 + Smart Water | 0.005 | r.t. | SSW +Ca2+/SO42− | Medium | Carbonate | Ø: 8.57−11.50% µ: 0.54−0.59 mD | 3–7.5 | [55] |
Nanoparticles | Concentration (g/L) | Dispersion Media | T (°C) | Oil | Rock Type | Rock Properties | AOR (%OOIP) | Ref |
---|---|---|---|---|---|---|---|---|
SiO2 Aerosil R 816 | 3 | Ethanol | r.t. | Light Intermediate | Sandstone | Ø: 18.5% µ: 102 mD | 25.43 14.55 | [57] |
Hydrophobic polysilicon | 3 | Ethanol | r.t. | Light Intermediate | Sandstone | Ø: 31.29–31.64% µ: 513.59–1476.18 mD | 36.67 29.01 | [58] |
Hydrophobic polysilicon | 4 | Ethanol | r.t. | Iranian | Sandstone | Ø: 17% µ: 186 mD | 32.20 | [59] |
Neutrally wet polysilicon | 3 | Ethanol | r.t. | Light Intermediate | Sandstone | Ø: 30.88–31.78% µ: 791.23–939.24 mD | 38.75 29.23 | [58] |
Neutrally wet polysilicon | 4 | Ethanol | r.t. | Iranian | Sandstone | Ø: 17% µ: 186 mD | 28.57 | [59] |
SiO2 -treated by silane | 1.5 | Propanol | r.t. | Iranian | Sandstone | Ø: 17.34% µ: 108.21 mD | 22.5 | [60] |
Al2O3 | 1.5 | Propanol | r.t. | Iranian | Sandstone | Ø: 17.45% µ: 110.40 mD | 20.2 | [60] |
Fe2O3 | 1.5 | Propanol | r.t. | Iranian | Sandstone | Ø: 18.12% µ: 109.32 mD | 17.3 | [60] |
Nanofluid | T (°C) | Dispersion Media | Oil | Rock Type | Rock Properties | AOR (%OOIP) | Ref |
---|---|---|---|---|---|---|---|
0.1 wt% SiO2 2150 ppm SDS | 30 | Diluted reservoir brine 2000 ppm 1 | Iranian | Sandstone | Ø: 20% µ: 200 mD | 80 2 | [61] |
0.1 wt% SiO2 (Aerosil 200) 2500 ppm SDS | 38 | Water | Iranian | Sandstone | Ø: 15–16% µ: 40-60 mD | 94.7 2 | [62] |
0.2 wt% SiO2 0.2 wt% SDS | 20 | Water | Tahe oilfield | Sandstone | Ø: µ: 0.051 μm 2 | 9.11 3 | [63] |
0.2 wt% SiO2 (Aerosil 300) 400 ppm SDS | 26 | Synthetic brine with divalent ions | Azadeghan | Sandstone | Ø: 18.2 µ: 158.35 mD | 14.5 | [64] |
2000–5000 ppm SiO2 (Aerosil 300) 2000 mg/L SDS | r.t. | Water | 26 cp (25 °C) | Sandstone sand-packs | Ø: 21.34 µ: 367.96 mD | 15.86–17.87 3,4 | [65] |
2000–10000 ppm SiO2 (Aerosil R 816) 2000 mg/L SDS | r.t. | Water | 26 cp (25 °C) | Sandstone sand-packs | Ø: 21.34 µ: 367.96 mD | 18.26–20.41 3,4 | [65] |
0.5 wt% Nano-clay 1800 ppm SDS | r.t. | Water 5 | Iranian | Sandstone | Ø: 18.3–18.5 µ: 281-285 mD | 52.3 2 | [66] |
0.05 wt% ZnO 0.2 wt% SDS | r.t. | Water | Dodecane | Sandstone | Ø: 26.65 µ: 15.74 mD | ~15 | [67] |
100 mg/L Janus graphene oxide (400) 1000 mg/L DTAB | 60 | Formation brine | Bohai oilfield | Artificial core | Ø: 37.02 µ: 506 mD | 19.5 3 | [68] |
1000 ppm SiO2 5 wt% Cedr extract | 25 | 100,000 ppm NaCl | Reservoir | Sandstone | Ø: 15.4 µ: 1.9 mD | 74 2 | [69] |
97.5 ppm SiO2 110.8 ppm Rhamnolipid | 80 | 1.17 wt% NaCl 1 | North Azadegan oilfield | Carbonate | Ø: 14.1 µ: 1.45 mD | 5.1 | [70] |
10–500 mg/L SiO2 10–40 mg/L Rhamnolipid | 55 | 3 wt% NaCl | Xinjiang oilfield | Berea sandstone | Ø: 16.45–19.87 µ: 0.0053-3.19 mD | 4–25 | [71] |
0.05 wt% SiO2-NH2 0.2 wt% Soloterra 964 | 65 | 15 wt% NaCl | Bakken | Berea sandstone | Ø: 18.96 µ: 0.091 μm 2 | 22.37 3 | [72] |
500 mg/L Amine-terminated SiO2 4000 mg/L Laurel anolamide | 30 | Formation brine | Xinjiang Oilfield | Three-layer artificial | Ø: 17.6 µ: 100/200/500 mD 50/100/300 mD | 26.4–29.2 3 | [73] |
0.01 wt% SiO2 0.01 wt% Alpha olefin sulfonate | r.t. | 18 wt% NaCl | Iranian | Carbonate | Ø: 13.48-15.73 µ: 1.05-1.51 mD | 2.5–8.6 3 | [75] |
0.1 wt% SiOx 0.1 wt% Linear alcohol, C9-11, ethoxylate | 60 | 1mM NaCl | Crude oil | Berea Sandstone | Ø: 23.6 µ: 173.2 mD | ~55 2 | [76] |
0.1 wt% SiOx 0.1 wt% Linear alcohol, C9-11, ethoxylate | 60 | 1mM NaCl | Crude oil | Edward carbonate | Ø: 24.23 µ: 23.61 mD | ~29 2,6 | [76] |
1000 ppm SiO2 2000 ppm Lauroyl-arginine | Water 5 | Kupal oilfield | Carbonate | Ø: 13.16 µ: 10.88 mD | 13.1 | [77] | |
1000 ppm SiO2 4500 ppm Lauroyl-cysteine | Water 5 | Kupal oilfield | Carbonate | Ø: 9.38 µ: 8.28 mD | 12.7 | [77] | |
1000 ppm SiO2 250 ppm Cocamido propyl betaine | r.t. | 19.8 wt% NaCl | Iranian | Carbonate (Dolomite) | Ø: 19.4 µ: 8.4 mD | 12.2 | [78] |
0.1 wt% SiO2 0.03 wt% Linear alkylbenzene sulfonic acid | r.t. | 20 wt% NaCl | Iranian | Carbonate | Ø: 19-23 µ: 13-16 mD | ~ 4.3–5 | [79] |
1 wt% Lysine-grafted silica 8000 ppm Jatropha oil derived 7 | 75 | 2 wt% NaCl | Crude oil | Sand-packs | Ø: 28.55–31.21 µ: 1.16-1.56 mD | 33.6 3 | [80] |
1 wt% Aluminium oxide hydroxide 3mM Sodium dodecylbenzene sulfonate Water:dodecane ratio 1:1 7 | 60 | Water 5 | Jidong oilfield | Artificial core | Ø: 36–42 µ: ~500 mD | 33 3 | [81] |
0.4 wt% SiO2 0.1 wt% Hexadecyltrimethylammonium bromide Water:biodiesel ratio 9:1 7 | 50 | 0.5 wt% NaCl | Shengli oilfield | Man-made | Ø: 18.1-24.6 µ: 100-1100 mD | 17.40-50.01 | [82] |
0.01 wt% SiO2 Triton X-100: n-dodecul β-d-maltoside: d-limonene:2-propanol 2:2:2:0.8 7 | 60 | 1M CaCl2 | Gibbs oilfield | Arkose sandstone | Ø: 16.8–17 µ: 26-32 mD | 34.3 | [84] |
0.1 wt% ZnO 0.025 wt% Sodium dodecylbenzene sulfonate + Magnetic Field | 95 | 3 wt% NaCl | Tapis oilfield | Sandstone sand-packs | Ø: 35.40–37.37 µ: 267–284 mD | 13.82–15.25 3 13.98–16.05 3 | [86] |
Nanofluid | T (°C) | Dispersion Media | Oil | Rock Type | Rock Properties | AOR (%OOIP) | Ref |
---|---|---|---|---|---|---|---|
0.1 wt% SiO2 0.2 wt% HPAM | 90 | Water 1 | Sarawak oilfield | Sandstone | Ø: 15.25–15.31% µ: 165.6–169.1 mD | 33 2 | [87] |
0.05–0.1 wt% SiO2 0.2 wt% HPAM | r.t. | Water 1 | Iranian | Sandstone | Ø: 18.65–19.30% µ: 10.21–12.90 mD | 6.28–7.97 | [89] |
0.1 wt% Al2O3 0.2 wt% HPAM | 90 | 3.41 wt% NaCl | Sarawak oilfield | Sandstone | Ø: 15.25–15.31% µ: 165.6-169.1 mD | 37.6 2 | [87] |
1.9–2.5 wt% TiO2 3150 ppm HPAM | r.t. | Water 1 | Iranian | Sandstone | Ø: 18.2–18.4% µ: 281–283 mD | 40.4–43.3 2 | [90] |
0.9 wt% Nano-clay 3150 ppm HPAM | r.t. | Water 1 | Iranian | Sandstone | Ø: 18.7% µ: 284 mD | ~42 | [91] |
1000 ppm MWCNTs 1000 ppm Acrylamide co/terpolymers | 85 | API Alkaline pH | Mineral oil | Ottawa sand-pack | Ø: 38.28% µ: 95 mD | 14.8 10.8 | [92] |
0.1 wt% Amino-modified SiO2/Acrylamide copolymer nanocomposite | 85 | API Formation brine | Mineral oil | Ottawa sand-pack | Ø: 37.9% µ: 95 mD | 17.46 2 16.20 2 | [93] |
0.05 wt% Al2O3 1 wt% Polyvinylpyrrolidone | r.t. | 3 wt% NaCl | North Sea | Berea sandstone | Ø: 14.71% µ: 330 mD | 13.34 2 | [94] |
0.05 wt% TiO2 1 wt% Polyvinylpyrrolidone | r.t. | 3 wt% NaCl | North Sea | Berea sandstone | Ø: 14.96 % µ: 118 mD | 20.00 2 | [94] |
0.5–1.5 wt% Al2O3 5.0 wt% Potato peel starch | r.t. | Water 1 | Niger Delta | Niger Delta Berea sandstone | Ø: 22.58–26.70% µ: 291.3–293.1 mD | 10.22–12.44 3 | [95] |
1.33 wt% Al2O3 3.0–5.0 wt% Gum Arabic | r.t. | Water 1 | Niger Delta | Niger Delta Berea sandstone | Ø: 17.89–18.56% µ: 251.7–278.8 mD | 5.61-7.81 | [95] |
0.1–0.5 wt% SiO2 1000–5000 ppm Xanthan gum | 30 80 | Synthetic formation brine | Heavy | Berea sandstone | Ø: 25.1–26.5% µ: 746–1002 mD | 16.29-20.82 2 18.44 2 | [96] |
0.2 wt% SiO2 4000 ppm Guar gum | 50 | Water 1 | Light | Sandstone | Ø: 16.3% µ: 204 mD | 44.3 2 | [97] |
0.1 wt% Surface-modified montmorillonite 2000 ppm HPAM | r.t. | Water 1 | Darquain oilfield | Carbonate sand-pack | Ø: 23.3% µ: 294 mD | 33 4 | [99] |
500–1500 ppm of TiO2/SiO2/poly(acrylamide) nanocomposite + Smart Water | 75 | Different smart waters | Iranian | Carbonate | Ø: 7.75–9.65% µ: 3.60–4.20 mD | 7.4–10.5 | [100] |
Nanofluid | T (°C) | Dispersion Media | Oil | Rock Type | Rock Properties | AOR (%OOIP) | Ref |
---|---|---|---|---|---|---|---|
0.5–2.0 wt% SiO2 0.14 wt% SDS 1000 ppm HPAM | 30 90 | Water 1 | Medium | Silica sand-pack | Ø: 29.77 ± 1.34% µ: 1006±86.50 mD | 19.25–24.68 2 21.82 2 | [101] |
0.2–0.4 wt% PAM-grafted TiO2 0.1 wt% SDS 0.4 wt% HPAM | 25 | 0–3 wt% NaCl | Heavy | Sand-pack | Ø: 34–37% µ: 5276.4–6111.1 mD | ~69–86 2,3 | [102] |
0.5 wt% Colloidal SiO2 0.1 wt% 3-(N,N-dimethylmyristylammonio)propanesulfonate 0.5 wt% PSS-co-MA | 25 | 3 wt% NaCl | Silicone | Sandstone | Ø: 19–22% µ: 138-154 mD | 74.2–78.2 3 | [103] |
0.08 wt% Polymer nanoparticles 0.1 wt%Betaine surfactant | 80 | Synthetic formation brine | Bakken | Berea sandstone | Ø: 19.22 % µ: 0.08859 μm 2 | 19.95 2 | [104] |
1.0 wt% SiO2 1.0 wt% PAM 0.22 wt% SDS-Detergent Water:oil ratio 3:1 4 | 40–90 | Water 1 | Tarapur oilfield | Berea sandstone | Ø: 20.04–22.85 % µ: 498–632 mD | 17.49–21 2 | [105] |
1.0 wt% Clay 1.0 wt% PAM 0.22 wt% SDS-Detergent Water:oil ratio 3:1 4 | 40–90 | Water 1 | Tarapur oilfield | Berea sandstone | Ø: 20.17–23.05 % µ: 584–703 mD | 17.25–20.12 2 | [105] |
0.25 wt% SiO2 1.5 wt% Carboxy methyl cellulose 825 ppm SDBS Water:oil ratio 9:1 4 | r.t. | Water 1 | Light mineral | Sand pack | Ø: 31.48% µ: 1247 mD | 24.81 2 | [106] |
0.025 wt% SiO2 0.05 wt% HPAM 0.1 wt% N,N′-bis((dimethyltetradecyl)-1,6-hexanediammonium bromide) Water:heptane ratio 9:1 4 | r.t. | Water 1 | Ahmedabad oilfield | Sandstone | Ø: 17–18% µ: 350-400 mD | 26.25 2 | [107] |
0.05 wt% Al2O3 0.5 wt% 1-Dodecylpyridinium chloride 1 wt% Polyvinylpyrrolidone | r.t. | 0.5 wt% NaCl | Light | Carbonate | Ø: 18.08% µ: 22.02 mD | 11.96 | [110] |
0.05 wt% Al2O3 0.05 wt% 1-dodecyl-3-methylimidazolium chloride 1 wt% Polyvinylpyrrolidone | r.t. | 5 wt% NaCl | Light | Carbonate | Ø: 14.57% µ: 13.97 mD | 14.8 | [111] |
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Al-Asadi, A.; Rodil, E.; Soto, A. Nanoparticles in Chemical EOR: A Review on Flooding Tests. Nanomaterials 2022, 12, 4142. https://doi.org/10.3390/nano12234142
Al-Asadi A, Rodil E, Soto A. Nanoparticles in Chemical EOR: A Review on Flooding Tests. Nanomaterials. 2022; 12(23):4142. https://doi.org/10.3390/nano12234142
Chicago/Turabian StyleAl-Asadi, Akram, Eva Rodil, and Ana Soto. 2022. "Nanoparticles in Chemical EOR: A Review on Flooding Tests" Nanomaterials 12, no. 23: 4142. https://doi.org/10.3390/nano12234142