Wei, Bing (Southwest Petroleum University) | Wang, Yuanyuan (Southwest Petroleum University) | Chen, Shengen (Southwest Petroleum University) | Mao, Runxue (Southwest Petroleum University) | Ning, Jian (Southwest Petroleum University) | Wang, Wanlu (Southwest Petroleum University)
Foams were introduced to enhanced oil recovery (EOR) for the purpose of improving sweep efficiency via mitigating gas breakthrough. In prior works, well-defined nanocellulose-based nanofluids, which can well stabilize foam film as a green alternative to reduce the environmental impact, were successfully prepared in our group. However, due to the costly manufacturing process, its field scale application is restricted. In order to further simply the manufacturing process and minimize the cost, in this study, we proposed another family of functional nanocellulose, in which lignin fraction was remained as well as carboxyl groups. The primary objective of the present work is to investigate the synergism between the lignin-nanocellulose (L-NC) and surfactant in foam film stabilization. Particular attention was placed on the relation between the chemical composition of L-NC and its stabilizing effect. Direct measurements of foamability, drainage half-time, foam morphology, foam decay, etc., were performed. The results showed that after the contents of lignin and carboxyl group were well tailored, the resultant L-NC can significantly improve the stability of foam either in the absence or presence of crude oil. The flooding dynamics observed in core plugs indicated that the L-NC stabilized foams could properly migrate in porous media and generated larger flow resistance accross the cores than surfactant-only foam.
Zhao, Tianhong (Southwest Petroleum University) | Chen, Ying (Southwest Petroleum University) | Pu, Wanfen (Southwest Petroleum University) | Wei, Bing (Southwest Petroleum University) | He, Yi (Southwest Petroleum University) | Zhang, Yiwen (Southwest Petroleum University)
Nanofluid flooding injection technique whereby nanomaterial or nanocomposite fluids for enhanced oil recovery (EOR) have garnered attention. Although a variety of nanomaterials have been used as EOR agents, there are still some defects such as toxicity, high cost and low-efficiency displacement, which restricted the further application of these nanoparticles. Considering these problems mentioned above, it is necessary to search for another nanomaterial which is inexpensive, environmentally friendly and results in high efficiency displacement.
In this work, a natural aluminosilicate nanomaterial halloysite nanotubes (HNTs) was focused. As a new kind of nanomaterial, the effectiveness of halloysite nanotubes (HNTs) in enhancing oil recovery has not been reported yet and it is still in its infancy. The use of pristine halloysite nanotube is at risk of blocking the rock pore channel due to the intrinsic drawback of aggregation, which may be the reason. To prolong the suspension time of fluids during seeping into the small pores of low permeable reservoirs, we have proposed the HNTs/SiO2 nanocomposites. The effect of HNTs/SiO2 nanocomposites-based nanofluids on wettability alteration and oil displacement efficiency was experimentally studied. The HNTs/SiO2 nanocomposites have been prepared by sol-gel method and characterized with X-ray (XRD), Transmission Electron Microscopy (TEM) and Thermal Gravimetric Analysis (TGA). The effect of the chemical modification on the suspension stability was investigated by measuring Zeta potential and dynamic laser scattering. Results show that the HNTs/SiO2 nanofluid could significantly change the water wettability from oil-wet to water-wet condition and enhance oil production. The optimal concentration of HNTs/SiO2 was 500 ppm, which corresponded to the highest ultimate oil recovery of 39%.
Kazemzadeh, Yousef (Department of Petroleum Engineering, Amirkabir University of Technology, Tehran Polytechnic) | Ismael, Ismael (Department of Petroleum Engineering, School of Chemical and Petroleum Engineering, Shiraz University) | Rezvani, Hosein (Department of Mining Engineering, Isfahan University of Technology) | Sharifi, Mohammad (Department of Petroleum Engineering, Amirkabir University of Technology, Tehran Polytechnic) | Riazi, Masoud (Enhanced Oil Recovery, Research Centre, IOR EOR Research Institute, Shiraz University, Shiraz, Iran Department of Petroleum Engineering, School of Chemical and Petroleum Engineering, Shiraz University)
Type of emulsification is dependent on several factors, including chemical composition of crude oil, type of surface active agents, oil and water volume percentages, and type of emulsification. The water present in oil reservoirs, including connate water and injected water, can highly affect the formation and stability of the emulsions. Injection of smart water (water containing certain weight percentage of various ions) and nanofluids (nanoparticles-dispersed water-based fluids) are effective on the emulsion formation and stabilization. NaCl and MgCl2 are among the common irrefutable salts in enhanced oil recovery (EOR) methods. Analysis of the formation and stabilization of emulsions is fulfilled with different methods. Investigation of morphology of water and oil droplets is considered as a static method of analyzing the emulsion stability. In this study, the average area of water droplets in the oil phase has been calculated. The study has been continued with the static analysis of emulsion stability by monitoring the emulsion resistance to phase separation. Regarding increased viscosity with emulsification, the emulsified fluids were developed during tertiary injection of nanofluid and smart water and the ultimate oil recoveries were monitored. The effect of salt type and concentration on the formation and stabilization of emulsions has been also investigated. Based on the previous studies performed by the research group, Fe3O4-based nanocomposites play an important role in the formation and stabilization of emulsions. Accordingly, different concentrations of Fe3O4/Chitosan nanocomposites were used in this study. Finally, an evaluation was performed on comparing the performance of smart water and nanofluid injection at the optimum concentrations. According to the results obtained, 10000 ppm MgCl2 presented the best performance in the formation and stabilization of the emulsions as compared to the other concentrations. The synthesized nanocomposite also showed the best result at 0.05 wt.%. Comparing smart water and nanofluid showed that the emulsions developed during nanofluid injection were more stable and in turn recorded a higher oil recovery.
Al-Anssari, Sarmad (Curtin University, University of Baghdad, Edith Cowan University) | Arain, Zain-UL-Abedin (Curtin University) | Barifcani, Ahmed (Curtin University) | Keshavarz, Alireza (Edith Cowan University) | Ali, Muhammad (Curtin University, Edith Cowan University) | Iglauer, Stefan (Edith Cowan University)
Nanoparticles (NPs) based techniques have shown great promises in all fields of science and industry. Nanofluid-flooding, as a replacement for water-flooding, has been suggested as an applicable application for enhanced oil recovery (EOR). The subsequent presence of these NPs and its potential aggregations in the porous media; however, can dramatically intensify the complexity of subsequent CO2 storage projects in the depleted hydrocarbon reservoir. Typically, CO2 from major emitters is injected into the low-productivity oil reservoir for storage and incremental oil recovery, as the last EOR stage. In this work, An extensive serious of experiments have been conducted using a high-pressure temperature vessel to apply a wide range of CO2-pressure (0.1 to 20 MPa), temperature (23 to 70 °C), and salinity (0 to 20wt% NaCl) during CO2/water interfacial tension (IFT) measurements. Moreover, to mimic all potential scenarios several nanofluids at different and NPs load were used. IFT of CO2/nanofluid system was measured using the pendant drop method as it is convenient and flexible technique, particularly at the high-pressure and high-temperature condition. Experimentally, a nanofluid droplet is allowed to hang from one end of a dispensing needle with the presence of CO2 at the desired pressure and temperature. Regardless of the effects of CO2-pressure, temperature, and salt concentration on the IFT of the CO2/nanofluid system, NPs have shown a limited effect on IFT reduction. Remarkably, increased NPs concentration (from 0.01 to 0.05 wt%) can noticeably reduce IFT of the CO2-nanofluid system. However, no further reduction in IFT values was noticed when the NPs load was ≥ 0.05 wt%. Salinity, on the other hand, showed a dramatic impact on IFT and also on the ability of NPs to reduce IFT. Results showed that IFT increases with salinity particularly at relatively low pressures (≤ 5 MPa). Moreover, increased salinity can eliminate the effect of NPs on IFT. Interestingly, the initial NP size has no influence on the ability of NPs to reduce IFT. Consequently, the potential nanofluid-flooding processes during EOR have no negative effect on the later CO2-geosequestration projects.
It is no secret that drilling fluid is crucial in drilling operations. The main function of drilling fluids is to transport drill cuttings from the bottom of the hole up to the surface. Drill cuttings then will be separated on the surface before the fluid is recycled for further drilling. This is to ensure a smooth drilling operation. A drilling-fluids rheological study is a must when drilling a well.
Xu, Derong (China University of Petroleum Beijing) | Bai, Baojun (China University of Petroleum Beijing, Missouri University of Science and Technology) | Meng, Ziyu (China University of Petroleum Beijing) | Zhou, Qiong (China University of Petroleum Beijing) | Li, Zhe (China University of Petroleum Beijing) | Lu, Yao (China University of Petroleum Beijing) | Wu, Hairong (China University of Petroleum Beijing) | Hou, Jirui (China University of Petroleum Beijing) | Kang, Wanli (China University of Petroleum East China)
The exploration and development of super-low permeability reservoirs have become a global focus in recent years. However, conventional flooding systems commonly face problems of high injection pressure and poor displacement efficiency in super-low permeability reservoirs. Thus, it is imperative to find new flooding agents that tackle such problems.
In this study, a novel ultra-low interfacial tension (IFT) nanofluid was formulated, consisting of surfactants to achieve ultra-low IFT and silica nanoparticles to reduce injection pressure. The compatibility test between the surfactants and silica nanoparticles in 10,000 mg/L NaCl solution at 90 °C was conducted to ensure their adaption to harsh reservoir conditions. Also, the effects of silica nanoparticles on the IFT and emulsion stability of the surfactant solution as well as wettability of reservoir rock were evaluated to determine the optimum concentration of nanoparticles. Finally, oil displacement efficiency of the nanofluid was assessed and compared from respective nanofluid flooding, surfactant flooding and surfactant-free nanofluid flooding.
The compatibility results showed that the ultra-low IFT surfactant solution with silica nanoparticles remained clear and stable at 90 °C for one month. The surfactant solution can effectively emulsify oil, and the stability of the oil emulsion could be further improved in the presence of silica nanoparticles. In addition, the solution could achieve lower IFT at both low and high temperature with the addition of 0.01% silica nanoparticles. The silica nanoparticles could effectively alter the wettability of the rock, making it become more water-wet with increasing silica nanoparticle concentration. The displacement experiments through 0.2–0.3 mD tight cores indicated that the enhanced oil recovery could reach 21.12%OOIP by the nanofluid flooding after water flooding, higher than that of surfactant flooding (18.84% OOIP), and much higher than that of surfactant-free nanofluid flooding (3.48% OOIP). Moreover, the injection pressure difference was able to decrease nearly 50% after nanofluid injection in comparison with the occurrence of an increase in pressure along the surfactant solution injection. Thus, the combined surfactant and nanoparticles behaved excellent synergistic effect.
The newly formulated surfactant based silica nanofluids can efficiently enhance oil recovery in comparison with water flooding, and significantly lower the injection pressure compared with the surfactant flooding. This work lays the foundation for the application of ultralow IFT nanofluid flooding technology in super-low permeability reservoirs.
Today, global energy demand increases significantly, but supply growth does not increase in the same proportion. The oil industry has been affected by the shortage of discoveries of new deposits of oil. Thus, it is compelling the development of cost-effective enhanced oil recovery (EOR) alternatives that allow the increase of the current hydrocarbons supply of actual reservoirs. Hence, the nanotechnology emerges as a good option as the use of nanoparticles and nanofluids has shown potential benefits in improving the efficiency of chemical treatments. Nevertheless, field applications of nanoparticles have been avoided due to current studies indicate that nanoparticles concentrations higher than 10,000 mg/L are needed, which disable the implementation due to high costs and the possibility of formation damage. Hence, the main objective of this study is the development for the first time of unconventional and engineered designed 0-D nanomaterials, namely NiO/SiO2 Janus nanoparticles that can be used for enhancing the oil recovery at low concentrations (~100 mg/L) without the risk of formation damage in the reservoir. These type of nanoparticles, due to its low size and 0-D characteristics, can improve the swept efficiency in the reservoir and increase the recovery. The primary mechanism of these nanomaterials is their strategic positioning at the oil/water interface and reduction of the interfacial tension. The Janus nanoparticles can migrate at the oil/water interface. The Janus-based nanofluids (nanomaterials dispersed in determined carrier fluid) flooding were assessed for reducing the interfacial tension (IFT), increasing the viscosity of the displacement phase, and altering the rock wettability, which impacts the capillary number and hence increases the crude oil recovery. The synthesized nanomaterials were characterized by TEM, stability, IFT, rheology, contact angle measurements and coreflooding tests under real reservoir conditions (fluids, pressure, temperature and rock samples) looking for flow assurance previous to a field trial. The results showed an increase of the capillary number at a very low concentration of 100 mg/L of both nanomaterials, mainly attributed to the decrease in the interfacial tension, which can lead to the increase of the oil recovery. Displacement tests using conventional SiO2 nanoparticles-based nanofluid at a concentration of 100 mg/L did not show an increase in oil recovery regarding the one obtained in the waterflooding step. Meanwhile, the nanofluid based on the engineering designed nanomaterials at the same concentration of 100 mg/L showed an increase in oil recovery up to 50%.
The focus of this paper is the application of colloidal suspensions of nanoparticles, commonly known as "nanofluids" for enhanced oil recovery in tight oil reservoirs. Nanofluids are specialized colloidal solvents, compatible with various types of fluids used in oil reservoirs and they have the potential to enhance the recovery of oil and gas from a variety of rock pores (EOR). Nanofluids can be used as an important tool to alter the properties of the formations. We examine here the underlying mechanisms, including the wettability alterations and reduction of the interfacial tension driving enhanced oil recovery in tight oil reservoirs using compositional numerical simulation.
We start with a review of the nanofluid properties critical to mobilize oil in the reservoir pore network by wettability alteration. We then demonstrate the effectiveness of surfactant-based nanofluids for wettability alteration using a comprehensive chemical flooding simulation. The modeling of wettability modification depends on a shift in relative permeability and capillary pressure curves during simulation. Altered wettability affects the residual phase saturations which, in turn, influences the relative permeability and causes oil mobilization. Moreover, capillary imbibition promotes oil recovery as the wettability is altered towards water-wet conditions. We investigate the major factors in wettability modification and how they influence the oil recovery through exhaustive sensitivity studies and a Pareto-based multi-objective optimization approach.
This study concentrates on the nanofluids mechanisms in enhanced oil recovery, including the permeability alterations, rock wettability alterations and reduction of the interfacial tension. A comprehensive simulation sensitivity study and a multi-objective optimization approach are utilized to identify the dominant parameters impacting oil recovery in tight oil reservoirs using complex surfactant based nanofluids. Based on the results, a set of guidelines are suggested for selection and application of nanofluids for improving oil recovery in tight oil reservoirs stimulated with multiple hydraulic fractures.
Hogeweg, Alexander Sebastian (Clausthal University of Technology) | Hincapie, Rafael E. (Clausthal University of Technology) | Foedisch, Hendrik (Clausthal University of Technology) | Ganzer, Leonhard (Clausthal University of Technology)
Utilization of nanoparticles in EOR have gained high attention recently, with good but controversial results reported on improving oil recovery. Within this work two types of nanoparticles are selected and assessed, to determine its effect in oil mobilization. The experimental evaluation is performed using micromodels (EOR chips), in combination with a detailed nanofluids characterization. The workflow presented is a useful approach that can extended among different laboratories as preliminary evaluation.
The workflow comprises a set of interrelated steps: 1) Selection and preparation of the Aluminium Oxide (Al2O3) and Titanium Dioxide (TiO2) nanofluids, influenced by recent literature comparisons, 2) Detailed rheological evaluation of nanofluids and oil, 3) Investigation of the Fluid-Fluid interaction by means of the interfacial tension (IFT) and nanoparticles effects in oil viscosity, 4) Two-phase flow experiments using EOR chips (breakthrough and mobilized oil vs PV injected), 5) Image processing analysis, leading to 6) Quantitative and qualitative analysis of the experimental data.
As expected, we observed that diluting nanoparticles in fresh water increased the stability compared to brine. It was required the use of a stabilizer to optimize nanofluids characteristics. Unlike reported in the literature where Polyvinylpyrrolidone (PVP) is used, we found that adding Poly(ethylene oxide)-(PEO) leads to a more stable nanofluids. There, seemed to be a tendency for the Al2O3 nanoparticles to reduce the viscosity of the aqueous-phase, when combined with PEO. Moreover, when Al2O3 was added to the oleic-phase increased its viscosity, with a strong dependency of soaking process. The image process analysis allowed to generate algorithms to calculate concentrations and saturations among the two-phase flow experiments. These algorithms proved to be highly beneficial enabling qualitative and also quantitative analysis of mobilized oil zones, as well as plugged areas. The experimental results did not show a significantly strong increase in mobilized oil due to Titanium Dioxide nanofluids, but slightly better results were observed with the Alumnium Oxide nanofluid in a low concentration.
Much research in recent years has focused on the study of Silica nanoparticles. Since different other nanoparticles can be commercially found, this work presents additive information to the existing body of literature. Moreover, the workflow presented can be used by fellow researchers as preliminary tool for laboratory evaluations. These, to obtain potential useful insights from oil mobilization by the application of nanoparticles flooding.
The investigation of nanotechnology applications in the oil and gas industry is increasing gradually; therefore, this technology needs more exploration to unveil promising applications. In this study, an experimental investigation of nanotechnology on the apparent viscosity, viscoelastic properties, and filtration performance of surfactant-based fluids (SBFs) or viscoelastic surfactants (VESs), polymeric fluids, and SBF/polymeric-fluid blends is presented. The concentration of SBF is 5 vol%, whereas that of polymeric fluids is 33 lbm/1,000 gal guar. Besides, both fluids contained 4 wt% potassium chloride (KCl). In addition, Blend-A and Blend-B were prepared by mixing SBF and polymeric fluids in the ratio of 75/25 and 25/75 vol%, respectively. Nanofluids were prepared by adding 20-nm silica nanoparticles, at concentrations of 0.058, 0.24, and 0.4 wt%, to the clean fluids. Apparent viscosity and viscoelastic data were gathered with a rheometer within a temperature range of 75 to 175°F, whereas filtration tests were conducted with a wall-mount filter press at ambient temperature and 100-psi differential pressure.
The results indicate an enhancement in the apparent viscosity and viscoelastic properties of surfactant-based and polymeric nanofluids up to a nanoparticle concentration of 0.24 and 0.4 wt%, respectively. Blend-A nanofluids show improvement in apparent viscosity and viscoelastic properties at a nanoparticle concentration of 0.058%. Similarly, Blend-B displayed favorable results up to a nanoparticle concentration of 0.24 wt% at temperatures of 125 to 175°F. Promising filtration results were displayed with surfactant-based nanofluids and Blend-A nanofluids at all nanoparticle concentrations, but the performance at 0.24 and 0.4 wt%, respectively, is slightly better. Polymeric nanofluids and Blend-B nanofluids revealed very good filtration results at all nanoparticle concentrations, but the performance at 0.24 and 0.058 wt%, respectively, is slightly better with a percentage reduction in API filtrate volume of 70.2 and 69.8%, respectively. A trial run was made with a commercially available fluid-loss additive [polyanionic cellulose (PAC)] in polymeric fluids at the same nanoparticle concentrations; the result confirmed that nanosilica facilitates the achievement of a superior filtration property. Comparison of apparent viscosity, viscoelastic properties, filtration performance, and economic analysis revealed Blend-A nanofluid as the preferred choice.
Further, Blend-A nanofluid (at 0.058 wt%) is selected as the best on the basis of filtration performance. The selected fluid was optimized at lower nanoparticle concentrations (0.02, 0.01, and 0.002 wt%). Interestingly, using Blend-A nanofluid at 0.002 wt%, compared with the initial recommendation of 0.058 wt%, which costs USD 171.7/bbl, reduces the cost of nanoparticles required for preparing 1 bbl of this fluid to USD 5.8. Therefore, from a filtration-performance standpoint, Blend-A nanofluid is recommended for use at a nanoparticle concentration of 0.002 wt%.
The application of nanotechnology on the apparent viscosity, viscoelastic behavior, and filtration properties of SBF, polymeric fluids, and SBF/polymeric-fluid blends can deliver some benefits, if nanoparticle concentrations are selected carefully. These nanofluids will be applicable for oilfield operations such as hydraulic fracturing.