scholarly journals Synergistic Effect of Nanofluids and Surfactants on Heavy Oil Recovery and Oil-Wet Calcite Wettability

Nanomaterials ◽  
2021 ◽  
Vol 11 (7) ◽  
pp. 1849
Author(s):  
Jinjian Hou ◽  
Lingyu Sun
Keyword(s):  
Synergistic Effect ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Interaction Force ◽  
Hot Water ◽  
Wettability Alteration ◽  
Heavy Oil Recovery ◽  
Optimal Salinity ◽  
Synergistic Mechanism ◽  
Enhance Oil Recovery

In recent years, unconventional oils have shown a huge potential for exploitation. Abundant reserves of carbonate asphalt rocks with a high oil content have been found; however, heavy oil and carbonate minerals have a high interaction force, which makes oil-solid separation difficult when using traditional methods. Although previous studies have used nanofluids or surfactant alone to enhance oil recovery, the minerals were sandstones. For carbonate asphalt rocks, there is little research on the synergistic effect of nanofluids and surfactants on heavy oil recovery by hot-water-based extraction. In this study, we used nanofluids and surfactants to enhance oil recovery from carbonate asphalt rocks synergistically based on the HWBE process. In order to explore the synergistic mechanism, the alterations of wettability due to the use of nanofluids and surfactants were studied. Nanofluids alone could render the oil-wet calcite surface hydrophilic, and the resulting increase in hydrophilicity of calcite surfaces treated with different nanofluids followed the order of SiO2 > MgO > TiO2 > ZrO2 > γ-Al2O3. The concentration, salinity, and temperature of nanofluids influenced the oil-wet calcite wettability, and for SiO2 nanofluids, the optimal nanofluid concentration was 0.2 wt%; the optimal salinity was 3 wt%; and the contact angle decreased as the temperature increased. Furthermore, the use of surfactants alone made the oil-wet calcite surface more hydrophilic, according to the following order: sophorolipid (45.9°) > CTAB (49°) > rhamnolipid (53.4°) > TX-100 (58.4°) > SDS (67.5°). The elemental analysis along with AFM and SEM characterization showed that nanoparticles were adsorbed onto the mineral surface, resulting in greater hydrophilicity of the oil-wet calcite surface, and the roughness was related to the wettability. Surfactant molecules could aid in the release of heavy oil from the calcite surface, which exposes the uncovered calcite surface to its surroundings; additionally, some surfactants adsorbed onto the oil-wet calcite surface, and the combined role made the oil-wet calcite surface hydrophilic. In conclusion, the study showed that hybrid nanofluids showed a better effect on wettability alteration, and the use of nanofluids and surfactants together resulted in synergistic alteration of oil-wet calcite surface wettability.

Low Salinity Hot Water Injection With Addition of Nanoparticles for Enhancing Heavy Oil Recovery

2019 ◽  
Vol 141 (7) ◽  
Author(s):  
Yanan Ding ◽  
Sixu Zheng ◽  
Xiaoyan Meng ◽  
Daoyong Yang
Keyword(s):  
Thermal Energy ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Water Injection ◽  
Operating Conditions ◽  
Hot Water ◽  
Wettability Alteration ◽  
Heavy Oil Recovery ◽  
Oil Saturation ◽  
Low Salinity

In this study, a novel technique of low salinity hot water (LSHW) injection with addition of nanoparticles has been developed to examine the synergistic effects of thermal energy, low salinity water (LSW) flooding, and nanoparticles for enhancing heavy oil recovery, while optimizing the operating parameters for such a hybrid enhanced oil recovery (EOR) method. Experimentally, one-dimensional displacement experiments under different temperatures (17 °C, 45 °C, and 70 °C) and pressures (about 2000–4700 kPa) have been performed, while two types of nanoparticles (i.e., SiO2 and Al2O3) are, respectively, examined as the additive in the LSW. The performance of LSW injection with and without nanoparticles at various temperatures is evaluated, allowing optimization of the timing to initiate LSW injection. The corresponding initial oil saturation, production rate, water cut, ultimate oil recovery, and residual oil saturation profile after each flooding process are continuously monitored and measured under various operating conditions. Compared to conventional water injection, the LSW injection is found to effectively improve heavy oil recovery by 2.4–7.2% as an EOR technique in the presence of nanoparticles. Also, the addition of nanoparticles into the LSHW can promote synergistic effect of thermal energy, wettability alteration, and reduction of interfacial tension (IFT), which improves displacement efficiency and thus enhances oil recovery. It has been experimentally demonstrated that such LSHW injection with the addition of nanoparticles can be optimized to greatly improve oil recovery up to 40.2% in heavy oil reservoirs with low energy consumption. Theoretically, numerical simulation for the different flooding scenarios has been performed to capture the underlying recovery mechanisms by history matching the experimental measurements. It is observed from the tuned relative permeability curves that both LSW and the addition of nanoparticles in LSW are capable of altering the sand surface to more water wet, which confirms wettability alteration as an important EOR mechanism for the application of LSW and nanoparticles in heavy oil recovery in addition to IFT reduction.

Tertiary Recovery Improvement of Steam Injection Using Chemical Additives: Pore Scale Understanding of Challenges and Solutions Through Visual Experiments

2021 ◽  
Author(s):  
Randy Agra Pratama ◽  
Tayfun Babadagli
Keyword(s):  
Porous Media ◽  
Phase Change ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Phase Distribution ◽  
Steam Injection ◽  
Hot Water ◽  
Heavy Oil Recovery ◽  
Residual Oil ◽  
Tertiary Recovery

Abstract Our previous research, honoring interfacial properties, revealed that the wettability state is predominantly caused by phase change—transforming liquid phase to steam phase—with the potential to affect the recovery performance of heavy-oil. Mainly, the system was able to maintain its water-wetness in the liquid (hot-water) phase but attained a completely and irrevocably oil-wet state after the steam injection process. Although a more favorable water-wetness was presented at the hot-water condition, the heavy-oil recovery process was challenging due to the mobility contrast between heavy-oil and water. Correspondingly, we substantiated that the use of thermally stable chemicals, including alkalis, ionic liquids, solvents, and nanofluids, could propitiously restore the irreversible wettability. Phase distribution/residual oil behavior in porous media through micromodel study is essential to validate the effect of wettability on heavy-oil recovery. Two types of heavy-oils (450 cP and 111,600 cP at 25oC) were used in glass bead micromodels at steam temperatures up to 200oC. Initially, the glass bead micromodels were saturated with synthesized formation water and then displaced by heavy-oils. This process was done to exemplify the original fluid saturation in the reservoirs. In investigating the phase change effect on residual oil saturation in porous media, hot-water was injected continuously into the micromodel (3 pore volumes injected or PVI). The process was then followed by steam injection generated by escalating the temperature to steam temperature and maintaining a pressure lower than saturation pressure. Subsequently, the previously selected chemical additives were injected into the micromodel as a tertiary recovery application to further evaluate their performance in improving the wettability, residual oil, and heavy-oil recovery at both hot-water and steam conditions. We observed that phase change—in addition to the capillary forces—was substantial in affecting both the phase distribution/residual oil in the porous media and wettability state. A more oil-wet state was evidenced in the steam case rather than in the liquid (hot-water) case. Despite the conditions, auspicious wettability alteration was achievable with thermally stable surfactants, nanofluids, water-soluble solvent (DME), and switchable-hydrophilicity tertiary amines (SHTA)—improving the capillary number. The residual oil in the porous media yielded after injections could be favorably improved post-chemicals injection; for example, in the case of DME. This favorable improvement was also confirmed by the contact angle and surface tension measurements in the heavy-oil/quartz/steam system. Additionally, more than 80% of the remaining oil was recovered after adding this chemical to steam. Analyses of wettability alteration and phase distribution/residual oil in the porous media through micromodel visualization on thermal applications present valuable perspectives in the phase entrapment mechanism and the performance of heavy-oil recovery. This research also provides evidence and validations for tertiary recovery beneficial to mature fields under steam applications.

Research Status and Prospect of Heavy Oil Recovery Technology

2021 ◽  
Vol 888 ◽  
pp. 111-117
Author(s):  
Yi Zhao ◽  
De Yin Zhao ◽  
Rong Qiang Zhong ◽  
Li Rong Yao ◽  
Ke Ke Li
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Development Trend ◽  
Thermal Recovery ◽  
Hot Water ◽  
Water Flooding ◽  
Oil Reservoir ◽  
Heavy Oil Recovery ◽  
Steam Flooding ◽  
Heavy Oil Reservoir

With the continuous exploitation of most reservoirs in China, the proportion of heavy oil reservoirs increases, and the development difficulty is greater than that of conventional reservoirs. In view of the important subject of how to improve the recovery factor of heavy oil reservoir, the thermal recovery technology (hot water flooding, steam flooding, steam assisted gravity drainage SAGD and steam huff and puff) and cold recovery technology (chemical flooding, electromagnetic wave physical flooding and microbial flooding) used in the development of heavy oil reservoir are summarized. The principle of action is analyzed, and the main problems restricting heavy oil recovery are analyzed The main technologies of heavy oil recovery are introduced from the aspects of cold recovery and hot recovery. Based on the study of a large number of literatures, and according to the development trend of heavy oil development, suggestions and prospects for the future development direction are put forward.

Heavy-Oil-Recovery Enhancement With Choline Chloride/Ethylene Glycol-Based Deep Eutectic Solvent

SPE Journal ◽  
2014 ◽  
Vol 20 (01) ◽  
pp. 79-87 ◽  
Author(s):  
S.M.. M. Shuwa ◽  
B.Y.. Y. Jibril ◽  
Y.M.. M. Al-Wahaibi ◽  
R.S.. S. Al-Hajri
Keyword(s):  
Ethylene Glycol ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Energy Demand ◽  
Choline Chloride ◽  
Deep Eutectic Solvent ◽  
Wettability Alteration ◽  
Formation Damage ◽  
Heavy Oil Recovery ◽  
Brine Solution

Summary Because of increasing energy demand, unconventional resources such as heavy oil are being explored and recovered. Enhanced-oil-recovery (EOR) methods such as surfactants and polymer flooding must be optimized and new chemicals must be designed to produce more oil. This paper introduces a new deep eutectic solvent (DES) that is based on choline chloride/ethylene glycol for EOR. As preliminary investigations revealed, different concentrations of DES solutions in brine (0 to 100 vol%) were characterized by measuring density, viscosity, conductivity, surface tension, and refractive index at different temperatures (25 to 55°C). Then, the effects of the DES/brine solutions on emulsification with oil phase, wettability alteration, oil/solvent interfacial tension (IFT), formation damage, and tertiary heavy-oil recovery were studied. Potential of the DES solution on enhancing heavy-oil recovery was explored by use of coreflood experiments. This was performed at reservoir condition (pressure = 1,200 psi, temperature = 45 to 80°C) with Berea sandstone core samples and fluids from the field of interest (formation brine and crude oil). An increase in IFT rather than a decrease was observed between the DES/brine solution and the oil. The spontaneous-water-imbibition tests suggested that a decrease in oil-wetness led to an increase in oil production. Approximately 52% of residual oil after waterflooding was recovered with the DES from the coreflooding. The results show an increase in oil recovery with reservoir temperature (6, 13, and 16% on the basis of initial oil in place at 45, 60 and 80°C, respectively). The interaction of the DES with the core materials did not lead to formation damage, as demonstrated by the permeability measurements of the DES/brine solution before and after injection. Viscous forces and wettability alteration were found to be the dominant mechanisms for the tertiary oil-recovery enhancement.

Improving heavy oil recovery using a top-driving, CO2-assisted hot-water flooding method in deep and pressure-depleted reservoirs

2019 ◽  
Vol 173 ◽  
pp. 922-931 ◽  
Author(s):  
Lanxiang Shi ◽  
Peng Liu ◽  
Dehuang Shen ◽  
Pengcheng Liu ◽  
Changfeng Xi ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Hot Water ◽  
Water Flooding ◽  
Heavy Oil Recovery

scholarly journals Experimental study of combination emission gas and hot water from power plant for enhanced heavy oil recovery

2020 ◽  
Vol 6 ◽  
pp. 183-188
Author(s):  
Bingbing Han ◽  
WenJun Li ◽  
Meng Li ◽  
Lei Liu ◽  
Junfeng Song
Keyword(s):  
Experimental Study ◽  
Power Plant ◽  
Oil Recovery ◽  
Heavy Oil ◽  
Hot Water ◽  
Heavy Oil Recovery

A visual investigation of enhanced heavy oil recovery by foam flooding after hot water injection

2016 ◽  
Vol 147 ◽  
pp. 361-370 ◽  
Author(s):  
Zhengbin Wu ◽  
Huiqing Liu ◽  
Zhanxi Pang ◽  
Yalong Wu ◽  
Xue Wang ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Water Injection ◽  
Hot Water ◽  
Heavy Oil Recovery ◽  
Foam Flooding

Heavy-Oil Recovery by Combined Hot Water and Alkali/Cosolvent/Polymer Flooding

SPE Journal ◽  
2016 ◽  
Vol 21 (01) ◽  
pp. 74-86 ◽  
Author(s):  
M.. Tagavifar ◽  
R.. Fortenberry ◽  
E.. de Rouffignac ◽  
K.. Sepehrnoori ◽  
G. A. Pope
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Oil Field ◽  
Hot Water ◽  
Mobility Control ◽  
Heavy Oil Recovery ◽  
Oil Viscosity ◽  
Polymer Flood ◽  
Low Interfacial Tension ◽  
Combined Strategy

Summary A hybrid process is developed and optimized for heavy-oil recovery that combines moderate reservoir heating and chemical enhanced oil recovery in the form of alkali/cosolvent/polymer flood. The process is simulated by use of a model derived from existing laboratory and pilot data of a 5,000-cp heavy-oil field. It is found that hot waterflooding is efficient in heating the reservoir only when high early injectivity is achievable. This may not be the case if incipient fluid injectivity is low and/or long, continuous, horizontal shale baffles are present. To remedy the former, an electrical-preheating period is devised, whereas switching to a horizontal flood could overcome the latter. Once the reservoir temperature is raised sufficiently, a moderately unstable alkali/cosolvent/polymer flood is capable of mobilizing and displacing oil. A best combined strategy for efficient reservoir heating, high oil recovery, and cost effectiveness is found to involve reducing the oil viscosity to values of approximately 300–500 cp and combining a degree of mobility control and low interfacial tension as recovery mechanisms.

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