Maximum Oil Recovery Research Articles

The Architecture of BaTiO3 Nanoparticles Synthesis via Temperature-Responsive for Improved Oil Recovery: A Molecular Dynamics Simulation and Core-Flooding Experimental Study

This research investigates the influence of various concentrations of BaTiO3 nanofluid on adsorption energy and improved oil recovery. BaTiO3 nanoparticles were successfully synthesized using a Sol-gel approach at temperatures of 400 °C, 500 °C, 800 °C, and 1000 °C and characterized for their structural and morphological properties and interfacial tension (IFT)/Wettability measurement. The study focuses on using ferroelectric nanofluid in combination with an electromagnetic field to enhance oil recovery mechanisms. Three concentrations of BaTiO3 nanofluid were prepared, and their effects on pressure and recovery factors were examined. The results demonstrate that BaTiO3 nanofluids increase the reservoir fluid’s ionic conductivity, leading to environmental polarization. Applying BaTiO3 nanofluid on glass bead samples resulted in a significant 42.15% increase in the recovery factor at a 0.3% concentration in various measurements, including interfacial tension, core-flooding, and wettability. The nanofluid caused a reduction in interfacial tension and a shift in wettability from oil-wet to water-wet. The higher adsorption energy of the nanofluid corresponded to more significant oil recovery. The optimal concentration for maximum adsorption energy (−2.566331 × 104) and oil recovery (22.5%) was 0.3wt%. At 0.1% concentration, the IFT value was 0.023 mN/m, at 0.3% concentration the IFT was 0.017 mN/m and at 0.5% concentration IFT value was 0.032 mN/m. The contact angle of the brine with the oil was 89.39% compared to the contact angle of 0.1%, 0.3%, and 0.5% which were 64.25%, 10.57%, and 44.63%, respectively. It was revealed from the result that 0.3% of nanofluid decreased the contact angle from 89.39% to 10.57 at a 0.3% concentration of BaTiO3 nanofluid. This shows that the wettability of the rock surface changed from oil-wet to water-wet with the novel application of BaTiO3 nanoparticles. This improvement in recovery can be attributed to the modification of wettability and reduction of interfacial tension.

Production Performance Analysis to Mature Field Development Plan

The research focuses on evaluating the production performance of three oil wells-Well F55A MB, Well Hovea 13 ST1, and Well Pedirka-1-using Inflow Performance Relationship (IPR) and Vertical Lift Performance (VLP) analysis to determine optimal artificial lift methods for each case. The study explores critical production parameters such as reservoir pressure, temperature, and gas-to-oil ratio (GOR) while employing decision tree methodologies to select suitable artificial lift systems. For Well Hovea 13 ST1 and Well Pedirka-1, gas lift installations significantly enhanced oil recovery rates by optimizing injection pressures and valve placements, achieving production gains of 694 and 300 barrels per day, respectively. In contrast, Well F55A MB, characterized by high water cut and lower reservoir temperatures, was deemed unsuitable for artificial lift based on the decision tree analysis, with a stable production of 2832 stb/d. This work highlights the importance of tailored artificial lift strategies for maximizing oil recovery and improving well performance in diverse reservoir conditions.

A Mini Review of the State-of-the-Art Development in Oil Recovery Under the Influence of Geometries in Nanoflood

The global demand for oil and petroleum products is experiencing a significant increase, while the number of newly discovered oil reservoirs is relatively low. This emphasises the critical need for innovative techniques to enhance the rate of oil recovery in order to meet global demand. The implementation of nanotechnology in enhanced oil recovery (EOR) yields numerous advantages, including cost savings in production and improved oil recovery. Additionally, it is critical to investigate the geometrical behaviour of the reservoir, as this information is vital for determining the maximum oil recovery rate. This review highlights the significance of nanotechnology through the utilisation of various geometries to determine the rate of hydrocarbon recovery. Furthermore, this paper also addresses the obstacles associated with achieving maximum oil recovery and provides suggestions for future research in this field. The review concludes with its key finding, which indicates that an examination of reservoir geometry utilising nanofluid in the presence of electromagnetic waves can significantly improve the rate of hydrocarbon recovery.

Green synthesis of zinc oxide nanoparticles using Enterobacter cloacae microorganism and their application in enhanced oil recovery

Employing safe and inexpensive methods for the synthesis of biocompatible nanoparticles (NPs) can be very challenging. Green synthesis refers to the process of synthesizing nanoparticles without using toxic and dangerous chemicals. One of the applications of nanoparticles is increasing production from oil reservoirs, known as enhanced oil recovery (EOR). The main aim of the current study is the biosynthesis of zinc oxide (ZnO) nanoparticles (NPs) using Enterobacter cloacae (Persian Type Culture Collection (PTCC): 1798) microorganism, extracted from the formation water of one of the southwestern Iranian reservoirs, as a novel approach in EOR applications. Several analytical methods, including Fourier transform infrared (FTIR), field emission scanning electron microscope (FSEM), X-ray diffraction (XRD), dynamic light scattering (DLS), energy dispersive X-ray spectroscopy (EDS), and zeta potential were used to analyze the produced NPs. The FESEM analysis confirmed the amorphous form of the nanoparticles and estimated their size in the range of 32 to 58 nm. In investigating the effect of synthesized nanoparticles on interfacial tension (IFT) and stability tests, three levels of base fluids (distilled water, seawater, and diluted sea water) and five levels of nanoparticle concentrations (0, 100, 500, 1000, and 2000 ppm) were considered. The IFT analysis showed that an increase in nanoparticle concentration causes a decrease in the IFT. Also, ZnO nanoparticles were chosen at concentrations of 500 and 1000 ppm for wettability alteration and the EOR test through injection into porous media. The results for the EOR test demonstrated a maximum oil recovery factor of 56% for nanofluid injection with a concentration of 1000 ppm with diluted seawater as the base fluid. Furthermore, oil recovery factors of 43% and 49% were achieved by injection of distilled water and seawater with a concentration of 1000 ppm, respectively.

Enhancement of surfactant performance via titanium dioxide nanoparticles: implication for oil recovery in sandstone.

The application of titanium dioxide nanoparticles in the petroleum research area has received ample attention in recent years owing to its impact on wettability-altering agents. Further, employing a surfactant injection to improve oil production in sandstone formations on an industrial scale has become an alternative solution, particularly for mature fields. However, the existing literature on the combination of alkyl ethoxy carboxylate (AEC) surfactant with titanium dioxide nanoparticles on the application of enhanced oil recovery in sandstone formations remains underreported. This study explores the impact of combining AEC surfactant with titanium dioxide nanoparticles on recovering trapped oil in sandstone by examining the interfacial tension, contact angle, zeta potential, and core flooding with various concentrations of added titanium dioxide nanoparticles (0, 0.01, 0.025, and 0.05wt%) on AEC surfactant. Although the addition of 0.05 wt% TiO2 to AEC surfactant can significantly reduce the interfacial tension to the lowest value of 5.85 × 10-5mN/m, our results show that the highest oil recovery in Berea sandstone (59.52% recovery factor) is achieved at the concentration of 0.025wt% added TiO2 to AEC surfactant. We find that the stability of TiO2 nanoparticles on AEC surfactant plays a significant role in getting maximum oil recovery. These important findings from this study contribute to improving our understanding on the application of TiO2 combined with AEC surfactant to achieve more efficient and sustainable enhanced oil recovery in sandstone.

CO2 foam structure and displacement dynamics in a Hele–Shaw cell

The substitution of CO2 gas with CO2 foam for improved mobility control has recently attracted research attentions in enhanced oil recovery (EOR) as well as aquifer and soil remediation. However, the interplay between CO2 foam properties and oil displacement remains less investigated. In this work, using clear visualizations, we systematically investigate the dynamic advection-dominated foam morphology, its corresponding viscosity, and the efficiency and dynamics of oil displacement process by CO2 foam in a Hele–Shaw cell under the effects of gas ratio (Rg), fluid injection rates (Qt), and surfactant type. Clear visualization enables particle image velocimetry to calculate actual, rather than nominal, foam velocity that significantly affects the estimated foam viscosity. Our results demonstrate that at elevated gas ratios under constant total injection rate, larger and more uniform bubbles with less number density and greater interfacial area are obtained. Increasing the injection rates leads to finer foam texture at a constant gas ratio. Different foam structures have an impact on the foam viscosity, with a general increasing trend of viscosity for larger bubbles as Rg increases from 0.5 to 0.85. The higher the foam viscosity, the more stable displacement interfaces with less viscous fingers are observed, leading to improved sweeping rates. The green surfactants (saponin + Cellulose NanoFibers) provide foams with higher viscosity and, thus, more stable displacement interfaces. These findings highlight the important effect of Rg–dependent foam structure on its viscosity, which in turn is crucial for controlling the mobility of CO2 foam to maximize oil recovery rate during EOR processes.

Research on the treatment and secondary fluid mixing technology for oil-containing drilling wastewater in gas fields

Drilling operations in oil and gas fields will generate a large amount of highly polluted and difficult to degrade drilling wastewater. Oil drilling wastewater mainly includes diluted drilling fluid mud, heavy metals and radioactive substances. At present, the treatment methods for oily drilling wastewater mainly include reinjection into the formation, recycling and discharge after standard treatment, but the treatment effect is not good. This article describes the treatment of oily drilling wastewater through wastewater oxidation, flocculation, mechanical dehydration, intermediate water oxidation, flocculation and filtration. The experimental results show that the RR of the wastewater can reach 93.50 %, the maximum oil recovery rate (ORR) can reach 89.56 %, the light transmittance (LT) of the purified water can reach 98.40 %, the suspended solids (SS) can be reduced to 46.12 mg/L, the HBO2- content can be reduced to 4.20 mg/L. The water quality meets the requirements of DB61/T 1248–2019. Indoor technology was used for on-site testing, and the lowest reduction rate (RR) and ORR after wastewater treatment were 87.64 % and 84.21 %, respectively. Comparing the cost of treating the same type of wastewater, the treatment cost of the process in this article can be reduced by 1.87 USD/m3, which has higher economic benefits.

CO2 injection for enhanced oil recovery: Analyzing the effect of injection rate and bottom hole pressure

The goal of net-zero carbon emissions has led to widespread interest in lowering carbon dioxide (CO2) emissions. At the same time, the oil and gas industry seeks to enhance oil recovery (EOR) techniques to meet growing demand. CO2 flooding, a key EOR method, offers a dual benefit: reducing CO2 emissions and enhancing oil recovery. This study investigates the impact of injection rate and bottom hole pressure (BHP) on CO2 injection performance using the Nexus reservoir simulator, a novel application in CO2-EOR research. To the best of the author's knowledge, there is no previous research published in which the researchers used the Nexus reservoir simulator for the study of CO2-EOR. Cases are thoroughly investigated with various injection rates and BHP limitations. Simulation results show that BHP has a minimal impact on oil production, whereas increased injection rates significantly enhance cumulative oil production (COP) by 33.39% and extend reservoir life from 20 to 37 years. Total oil production increased to 33150.7 MSTB, accompanied by reduced water production and maintained reservoir pressure. These findings align with previous research, underscoring the importance of optimized CO2 injection strategies for maximizing oil recovery and reservoir performance.

Enhanced oil recovery and mitigating challenges in sandstone oil reservoirs employing EDTA chelating agent/ seawater flooding

While low salinity water (LSW) holds promise for improving oil recovery, its implementation is comparatively costly due to the substantial volumes of fresh water required to dilute seawater (SW). Additionally, concerns arise regarding potential issues related to LSW, including fines migration in sandstone reservoirs and scale formation in carbonate reservoirs. Chelating agents can be introduced into undiluted SW to bind with metal ions, thereby lowering its salinity. This approach mimics the behavior of LSW injection while overcoming associated challenges. This study involves measuring oil/injected solution interfacial tension (IFT), evaluating sandstone surface wettability alteration, along with conducting different sand pack flooding scenarios using Ethylenediaminetetraacetic acid (EDTA) chelating agent. The aim was to comprehend the EDTA oil recovery mechanisms and determine the optimal concentration of EDTA that minimizes chemical consumption while maximizing oil recovery. The findings indicated that incorporating 5 wt% EDTA into SW significantly reduced IFT from 29.52 mN/m to 4.75 mN/m, making the oil nearly miscible in the solution. Moreover, wettability tests confirmed that a minimum EDTA concentration of 5 wt% is required to shift wettability from oil-wet to strongly water-wet conditions. Sand pack flooding experiments, on the other hand, further demonstrated that this optimized fluid system can potentially recover an additional 16.1 % of oil following SW flooding. Finally, inductively coupled plasma (ICP) analysis revealed a notable increase in metal ion concentration during EDTA flooding, indicating enhanced leaching of metals from the sandstone surface and improved wettability characteristics.

Numerical simulation and optimization of biological nanocomposite system for enhanced oil recovery

Abstract Nanofluid flooding is a novel technology with potential for enhanced oil recovery. In this study, a biological nanocomposite system was formed by mixing hexamethyldisilazane-modified hydrophobic nano-SiO2 with a biosurfactant produced by Bacillus. The stability of the system, its influence on rock wettability, and fluid interfacial tension were investigated experimentally. Numerical simulation methods were employed to simulate the displacement efficiency of the biological nanocomposite system and optimize the injection parameters. Finally, the application effects of the system in the field were evaluated. Results indicated that the biological nanocomposite system could change rock wettability and significantly reduce the interfacial tension to 1.8 mN/m at low concentrations. The core flooding results showed that the maximum oil recovery factor of the system reached 47.07%. Numerical simulations optimized the optimal injection concentration to be 7,000 ppm and the volume of injection to be 1.75 × 10–2 pore volumes, resulting in an oil increment exceeding 10,000 m3 in field application. This study provides a solution for the green development of oil reservoirs and provides effective technical support for the numerical simulation and process scheme optimization of biological nanocomposite systems.

Importance of Fluid/Fluid Interactions in Enhancing Oil Recovery by Optimizing Low-Salinity Waterflooding in Sandstones

Low-salinity waterflooding/smart waterflooding (LSWF/SWF) is a technique involving the injection of water with a modified composition to alter the equilibrium between rock and fluids within porous media to enhance oil recovery. This approach offers significant advantages, including environmental friendliness and economic efficiency. Rock/fluid mechanisms such as wettability alteration and fines migration and fluid/fluid mechanisms such as a change in interfacial tension and viscoelasticity are considered active mechanisms during LSWF/SWF. In this study, we evaluated the effect of these mechanisms, by LSWF/SWF, on sandstones. To investigate the dominant mechanisms, coreflooding studies were performed using different injected fluid composition/salinity and wettability states. A comparative analysis of the recovery and mobility reduction factor was performed to clarify the conditions at which fluid/fluid mechanisms are also effective. Our studies showed that wettability alteration is the most dominant mechanism during LSWF/SWF, but, for weak oil-wet cases, optimizing brine compositions may activate fluid/fluid mechanisms. Brine composition significantly influences interface stability and performance, with sulfate content playing a crucial role in enhancing interface properties. This was observed via mobility behavior. A comparative analysis of pressure differentials showed that fines migration may act as a secondary mechanism and not a dominant one. This study highlights the importance of tailored brine compositions in maximizing oil recovery and emphasizes the complex interplay between rock and fluid properties in enhanced oil recovery strategies.

Mechanistic understanding of asphaltene precipitation and oil recovery enhancement using SiO2 and CaCO3 nano-inhibitors

Asphaltene precipitation in oil reservoirs, well equipment, and pipelines reduces production, causing pore blockage, wettability changes, and decreased efficiency. Asphaltenes, with their unique chemical structure, self-assemble via acid–base interactions and hydrogen bonding. Nano-inhibitors prevent asphaltene aggregation at the nanoscale under reservoir conditions. This study investigates the effect of two surface-modified nanoparticles, silica, and calcium carbonate, as asphaltene inhibitors and oil production agents. The impacts of these nano-inhibitors on asphaltene content, onset point, wettability, surface tension, and oil recovery factor were determined to understand their mechanism on asphaltene precipitation and oil production. Results demonstrate that these nano-inhibitors can significantly postpone the onset point of asphaltene precipitation, with varying performance. Calcium carbonate nano-inhibitor exhibits better efficiency at low concentrations, suspending asphaltene molecules in crude oil. In contrast, silica nano-inhibitor performs better at high concentrations. Wettability alteration and IFT reduction tests reveal that each nano-inhibitor performs optimally at specific concentrations. Silica nano-inhibitors exhibit better colloidal stability and improve oil recovery more than calcium carbonate nano-inhibitors, with maximum oil recovery factors of 33% at 0.1 wt.% for silica and 25% at 0.01 wt.% for calcium carbonate nano-inhibitors.

Pore-scale probing CO2 huff-n-puff in extracting shale oil from different types of pores using online T1–T2 nuclear magnetic resonance spectroscopy

CO2 huff-n-puff shows great potential to promote shale oil recovery after primary depletion. However, the extracting process of shale oil residing in different types of pores induced by the injected CO2 remains unclear. Moreover, how to saturate shale core samples with oil is still an experimental challenge, and needs a recommended procedure. These issues significantly impede probing CO2 huff-n-puff in extracting shale oil as a means of enhanced oil recovery (EOR) processes. In this paper, the oil saturation process of shale core samples and their CO2 extraction response with respect to pore types were investigated using online T1–T2 nuclear magnetic resonance (NMR) spectroscopy. The results indicated that the oil saturation of shale core samples rapidly increased in the first 16 days under the conditions of 60 °C and 30 MPa and then tended to plateau. The maximum oil saturation could reach 46.2% after a vacuum and pressurization duration of 20 days. After saturation, three distinct regions were identified on the T1–T2 NMR spectra of the shale core samples, corresponding to kerogen, organic pores (OPs), and inorganic pores (IPs), respectively. The oil trapped in IPs was the primary target for CO2 huff-n-puff in shale with a maximum cumulative oil recovery (COR) of 70% original oil in place (OOIP) after three cycles, while the oil trapped in OPs and kerogen presented challenges for extraction (COR < 24.2% OOIP in OPs and almost none for kerogen). CO2 preferentially extracted the accessible oil trapped in large IPs, while due to the tiny pores and strong affinity of oil-wet walls, the oil saturated in OPs mainly existed in an adsorbed state, leading to an insignificant COR. Furthermore, COR demonstrated a linear increasing tendency with soaking pressure, even when the pressure noticeably exceeded the minimum miscible pressure, implying that the formation of a miscible phase between CO2 and oil was not the primary drive for CO2 huff-n-puff in shale.

Co-pyrolysis of phenolic printed circuit boards with CaO and Ca(OH)2 mixture in a fluidized bed reactor: Optimization of the operating conditions and the kinetic analysis

In a previous study (Haghi et al., 2023), we demonstrated that co-pyrolysis of paper-laminated phenolic PCB (FR2-PCB) with a mixture of CaO and Ca(OH)2 in a fluidized bed reactor results in the simultaneous enhancement of the production of the pyrolysis oil and a significant decrease in its halide content. To advance the utilization of a blend of CaO and Ca(OH)2 for scaling up the pyrolysis of FR2-PCB beyond laboratory-scale pyrolyzers, especially in fluidized bed reactors renowned for their effectiveness in large-scale pyrolysis of polymeric materials, the optimal operating conditions, as well as the kinetic parameters in the presence of CaO and Ca(OH)2 should be explored. To this end, this study focuses on optimizing the temperature (T), retention time (t), and PCB-to-additive ratio (FR2/A) as the parameters controlling the co-pyrolysis of paper-laminated phenolic PCB (FR2-PCB) with a 50:50 mixture of CaO and Ca(OH)2 in a fluidized bed reactor. According to the results of the experiments designed based on the response surface methodology, the maximum recovery of pyrolysis oil (40.6 %) was obtained at T = 620 °C, t = 22 min, and FR2/A= 5.4 g/g. Additional tests were carried out to explore the impact of CaO+Ca(OH)2 concentration on the halogen content of the pyrolysis products. Furthermore, the thermogravimetric analysis (TGA) was performed to investigate the influence of the tested additives on the pyrolysis behavior and the kinetic characteristics of FR2-PCB. By employing three iso-conversional model-free approaches, i.e., the Kissinger-Akahira-Sunose (KAS), Flynn-Wall-Ozawa (FWO), and Starink integral methods, it was found that adding CaO+Ca(OH)2 to FR2-PCB can reduce the activation energy of the pyrolysis reactions by 20 %.

Optimizing oil recovery with CO2 microbubbles: A study of gas composition

Microbubbles represent a feasible method for enhancing oil recovery (EOR). To further investigate microbubble displacement and interaction mechanisms between gas and oil, in this study, EOR experiments were conducted on normal (NB) and microbubble (MB) CO2 and CO2–N2 mixtures using NMR. The CO2 flooding process and the mechanism of microbubble CO2-oil interaction were examined, the contributions of small and large pores to oil recovery and CO2 storage were quantified. Importantly, economic benefits were analyzed under different injection conditions for the first time. The results show CO2 injection formed a stable displacement front and the maximum oil recovery was obtained from MB CO2. The oil swelling and “jamin effect” increased MB CO2 sweep area and the efficiency of small pore utilization was 20.9 % higher than NB CO2. Compared to CO2 injection, the oil recovery gradually decreased with increasing N2 concentration due to the reduced sweep area. The maximum CO2 storage efficiency achieved under MB CO2 injection was 35.92 %. Economic analysis revealed that MB CO2-EOR could provide significant economic benefits of approximately US $492.5 per ton of CO2 injected. This study provides data for the commercial application of microbubble technology.

Analysis of the flow and thermal-fluid–solid coupling of crude oil in circular pipe caused by variable pressure gradient

Abstract Globally, enhanced oil recovery (EOR) has become a pressing issue as the demand for crude oil continues to increase. This study investigates the flow and thermal-fluid–solid coupling of crude oil in a rod pump during hot water recovery and obtains the maximum recovery of crude oil in a vertical pipeline through numerical analysis. The pressure gradient in the pump barrel was first developed and deduced based on the ideal gas state equation and Bernoulli’s equation. According to the rheological experiment results, it was proven that the light crude oil conforms to the Newtonian constitutive equation. Subsequently, the momentum equation of crude oil flowing in the pipeline and fluid–solid coupling heat transfer equations were established and solved using the finite difference method. The effects of the thermal recovery temperature T w , wall thickness c, and stroke time n of the rod pump on flow Q are discussed. In particular, the flow Q within 1 min first increases and then slows down with the increase in stroke time n and reaches its maximum value at n = 7 r/min. Furthermore, flow Q decreases with an increase in c but increases as T w increases; c = 1.2 cm, T w = 363 K is the best oil recovery scheme.

Ionic liquids adsorption and interfacial tension reduction for synthetic resinous and asphaltenic oils: salinity and pH effects

The effects of sulfate salts under low and high salinity conditions and pH of 3.5–11 on interfacial tension (IFT) reduction and IL adsorption using resinous (RSO) and asphaltenic (8 wt/wt%) synthetic oils are investigated. The measurements showed the increasing effect of pH on the IFT of RSO/DW from 23.5 to 27.3 mN/m (pH = 3.5 → 7) in the first place and a reducing effect (0.4 mN/m) if pH = 7 → 11. Using a high concentration of 50,000 ppm for MgSO4, and Na2SO4 revealed an extensive IFT reduction for a pH value of 11 with the value of 0.20 mN/m for Na2SO4. The measured IFT values showed the significant impact of IL (500 ppm) on the IFT (minimum value of 0.01 mN/m for RSO/50,000 Na2SO4 + 500 ppm 1-decyl-3-methyl imidazolium triflate ([C10mim][TfO])) for pH = 11. The IL adsorption measurements showed the role of in-situ surfactant production (saponification process) on the 1-decyl-3-methyl imidazolium chloride ([C10mim][Cl]) and [C10mim][TfO] adsorption reduction from 3.67 to 2.33 and 4.21 to 3.34 mg IL/g rock, respectively. The performed core flooding experiments using the optimum chemical formulation showed the possibility of tertiary oil recovery with maximum oil recovery of 28.8% based on original oil in place in the presence of 500 ppm.

Green solvent-based lipid extraction from guava seeds and spent coffee grounds to produce biodiesel: Biomass valorization and esterification/transesterification route

Spent coffee grounds and guava seeds were used as representative biomass residues to analyze the replacement of hexane with alternative green solvents for the extraction of lipids and their application to obtain biodiesel with the aim of contributing to the global zero-waste strategy. Lipid extraction studies were performed with these biomass wastes under different operating conditions. The results showed that the green solvents (i.e., ethyl acetate, ethyl butyrate, and ethyl propionate) outperformed the lipid extraction using hexane, achieving a maximum oil recovery of 24% for guava seed and 16.4% for spent coffee grounds, with ethyl propionate. The impact of solvent-to-biomass ratio, extraction temperature, and biomass particle size on lipid recovery from tested biomass residues was analyzed and discussed. The optimal extraction conditions for both biomasses were ethyl propionate, 0.3 mm of particle size and 40 °C; while the best solvent to biomass ratio were 10 and 8 mL/g for guava seeds and spent coffee grounds, respectively. The lipids extracted with green solvents showed similar physicochemical properties and compositions to those lipids extracted with hexane. Lipid extraction kinetics exhibited an endothermic performance. The kinetic data were suitably described with the first-order model (R2 = 0.92 – 1) with kinetic rate parameters in the range of 0.38–0.59 and 0.28–0.72 min−1, for guava seeds and spent coffee grounds, respectively. The lipids extracted from tested biomass were analyzed as raw source for biodiesel production via transesterification. The best reaction conditions to produce biodiesel (90%) were found at 60 °C, 6 h, 15% of catalyst-to-oil, and molar methanol-to-oil ratio of 26:1 using a one-step process. FAME formation up to 96% was obtained using a two-step esterification/transesterification methodology. A detailed characterization of the biodiesel obtained from the lipid fraction from these biomass wastes was also performed, indicating that transesterification reduced the acid value and viscosity to meet the ASTM standard criteria for biodiesel. The study contributes to the valorization of biomass wastes to produce renewable energy and to minimize the waste management problem.

A New Method for Optimizing Water-Flooding Strategies in Multi-Layer Sandstone Reservoirs

As one of the most important and economically enhanced oil-recovery technologies, water flooding has been applied in various oilfields worldwide for nearly a century. Stratified water injection is the key to improving water-flooding performance. In water flooding, the water-injection rate is normally optimized based on the reservoir permeability and thickness. However, this strategy is not applicable after oilfields enter the ultra-high-water-cut period. In this study, an original method for optimizing water-flooding parameters for developing multi-layer sandstone reservoirs in the entire flooding process and in a given period is proposed based on reservoir engineering theory and optimization technology. Meanwhile, optimization mathematical models that yield maximum oil recovery or net present value (NPV) are developed. The new method is verified by water-flooding experiments using Berea cores. The results show that using the method developed in this study can increase the total oil recovery by approximately 3 percent compared with the traditional method using the same water-injection amounts. The experimental results are consistent with the results from theoretical analysis. Moreover, this study shows that the geological reserves of each layer and the relative permeability curves have the greatest influence on the optimized water-injection rate, rather than the reservoir properties, which are the primary consideration in a traditional optimization method. The method developed in this study could not only be implemented in a newly developed oilfield but also could be used in a mature oilfield that has been developed for years. However, this study also shows that using the optimized water injection at an earlier stage will provide better EOR performance.

Surfactant-Enhanced Assisted Spontaneous Imbibition for Enhancing Oil Recovery in Tight Oil Reservoirs: Experimental Investigation of Surfactant Types, Concentrations, and Temperature Impact

Surfactant-assisted spontaneous imbibition is an important mechanism in enhanced oil recovery by capillary pressure in low permeability and tight oil reservoirs. Though many experiments have been conducted to study the mechanism of enhanced oil recovery by surfactant-assisted spontaneous imbibition, the effects of surfactant type, concentration, and temperature have not been well studied. Using tight sandstone outcrop core samples with similar permeability and porosity, this paper experimentally studies surfactant-assisted spontaneous imbibition using three different surfactant types, i.e., sodium dodecylbenzene sulfonate (SDBS), cocamidopropyl betaine (CAB), and C12–14 fatty alcohol glycoside (APG). In addition to the type of surfactant, the effect of the surfactant concentration and the temperature is also investigated. The study results show that the ultimate oil recovery of spontaneous imbibition with formation water and denoised water is about 10%. Surfactant can significantly improve the oil recovery of spontaneous imbibition by reducing the interfacial tension between oil and water, emulsifying crude oil and improving oil mobility. APG showed better performance compared to SDBS and CAB, with a maximum oil recovery factor of 36.19% achieved with formation water containing 0.05% APG surfactant. Lower concentrations (0.05% APG) in the formation water resulted in a higher oil recovery factor compared to 0.1% APG. Increasing temperature also improves oil recovery by reducing oil viscosity. This empirical study contributes to a better understanding of the mechanism of surfactant-assisted spontaneous imbibition and enhanced oil recovery in tight oil reservoirs.