Baryte, a non-metallic mineral, is used primarily for the formulation of drilling mud to control reservoir pressure during drilling. However, despite its abundant reserves in Nigeria, the international oil companies (IOC) operating in Nigeria still apply imported baryte for operations. Therefore, in this research, the physical properties (specific gravity (SG), hardness and moisture content (MC, and pH)), of baryte deposits from 5 selected sites in Obubra mine of Cross River State, were determined and compared, vis-à-vis the API specifications, to ascertain their suitability for use in oil drilling. The white powder obtained from a streak test on the 5 ores indicated that all were indeed baryte ores. Furthermore, the samples were separately washed, dried, crushed, ground, and milled. In addition, the ore’s hardness of 3.5, and MC range of 0.00-0.01%, and pH range of 7-7.4, were all within the API specifications. Moreover, readings from the SG obtained were; site 1=4.25, site 2 = 4.28, site 3 = 4.32, site 4 = 4.12 and site 5 = 3.37. Thus, baryte in sites 3 and 5 recorded the highest and lowest SG, respectively. Ultimately, these results showed that ores from sites 1, 2, and 3 meet the API 4.20 specification for drilling purposes. At a SG of 4.12, site 4 sample, fell slightly below 4.20, while site 5 sample was unsuitable for drilling. Therefore, baryte from sites 4 and 5 should be further processed to meet the API SG specification for drilling. These findings prove that Obubra baryte possesses crucial criteria for drilling mud formulation.
In this study, the synthesis of adsorbents from agricultural residues, specifically olive kernels, was examined using chemical precipitation with potassium hydroxide (KOH) as the activating agent. The carbonization process was conducted under an inert gas atmosphere at three temperatures: 600°C, 700°C, and 800°C. Subsequently, a carbon molecular sieve (CMS) was developed by incorporating a binder into the activated carbon. The specific surface area of the produced samples was determined using the Brunauer-Emmett-Teller (BET) method, with measured values ranging from 360 m²/g to a maximum of 1103 m²/g. Moreover, the adsorption and separation characteristics of carbon dioxide (CO₂) and methane (CH₄) were evaluated for both activated carbon (AC) and carbon molecular sieves (CMS) across a pressure range of 1,200 to 1,500 kPa. Additionally, the obtained adsorption isotherms were analyzed using the Langmuir, Freundlich, and Sips models. Furthermore, a strong correlation was observed between the experimental data and the Sips isotherm, indicating enhanced selectivity for CO₂ over CH₄. Ultimately, among the investigated samples, the activated carbon subjected to carbonization at 800°C exhibited the highest CO₂ adsorption capacity, reaching 0.1699 g of CO₂ per gram of adsorbent, highlighting its potential efficacy for gas separation applications.
Horizontal separator vessels exhibit better phase separation efficiencies when fluids flow at lower velocities, favoring the sedimentation process. The optimized determination of internal devices, such as baffles, can reduce fluid velocity from the inlet to the separation region. This research aimed to evaluate the impact of semi-perforated baffles on flow dynamics and the separation efficiency of gas, oil, and water in a three-phase horizontal separator vessel. Moreover, to achieve this goal, a base geometry was adapted. Furthermore, two configurations of semi-perforated baffles were analyzed, varying their distance from the inlet, height relative to the vessel bottom, and vertical length. In addition, computational fluid dynamics was used to obtain numerical results. Moreover, the multiphase flow was modeled using the VOF method in conjunction with the standard k-epsilon turbulence model. Also, the results indicated that the insertion of baffles contributed to reducing the velocity of the inlet fluids. Ultimately, among the analyzed geometric arrangements, it can be concluded that the three-phase horizontal separator with a semi-perforated baffle at position P1 exhibited a more uniform three-phase flow and better liquid/gas (90.03%) and oil/water (100%) separation efficiencies when compared to the other studied geometries.
Nowadays, with the increase in energy consumption, governments are forced to apply various tariffs to optimally control energy consumption in society. For this reason, electricity consumption meters have been designed and implemented in three modes: low, medium, and peak load. One of the methods that can be used in the summer season to reduce energy consumption is to store cooling load in low-load hours and use it during high-load hours. In this design, an ice chiller is used to prepare ice in a tank. In this thesis, first, a 5-story, two-unit building in the east of Tehran was dynamically simulated with Design Builder software, and accurate heating and cooling loads were obtained. Then, the ice tank was designed in such a way that it can cool all the units from 1:00 p.m. to 11:00 p.m. The amount of savings in the simulation with this year’s electricity tariff was about 965$ in one year, which will result in a return on investment of about 5 years for this building. Also, to reduce energy consumption during the day and based on accurate simulation results, 20 high-efficiency 500-watt panels were used to provide electricity for lighting and equipment, which economic calculations showed that this amount will be returned in less than two years.
The AN field, located offshore in the Douala Sub-Basin within the Douala/Kribi-Campo Basin, is part of the larger Aptian Salt Basin in Equatorial West Africa. This study focuses on evaluating the petrophysical properties and determining the reservoir quality of the sandstones in the AN Field to enhance production efficiency. Furthermore, well log data, including caliper, gamma-ray, density, neutron, sonic, and resistivity logs, were collected from Well 1 and Well 2 (pseudonym) in the AN field Douala Basin and analyzed using Techlog version 2015.1 software for petrophysical analysis and reservoir quality assessment. Moreover, the lithologic sequence consists of sandstone beds alternating with shale. In addition, three sandy reservoir units were identified (R1, R2, and R3), with thicknesses ranging from 16.6 to 53.8 m, identified in Wells 1 and 2. In addition, the reservoirs exhibited poor average formation porosity (1.54 - 16.53%), low average permeability (0.02 - 5.93 mD), and significantly high average water saturation (64.81-99.1%). In addition, analysis of true formation resistivity values versus water saturation indicated that all reservoir units in both wells were water saturated and unable to yield a commercial quantity of hydrocarbons. Furthermore, the gamma-ray log patterns indicate the depositional environment to be a deep marine setting, specifically fan valley sediments, encompassing braided river floodplains, deep tidal channel fills, and submarine fan lobes. In addition, the identified depositional environment aligns with a deep marine setting, which emphasizes the need for further exploration and assessment to optimize production efficiency in this area. Moreover, the results from this study will guide wellsite decisions, reservoir development, and production planning, and impact critical financial decisions at every stage of the Exploration and Production lifecycle in the Douala Sub-Basin, Cameroon.
Flared gas recovery (FGR) plays a crucial role in controlling greenhouse-gas emissions and improving energy-efficiency in industrial gas plants. Every year, significant amounts of valuable gases are lost through flaring, leading to both environmental/economic consequences. Moreover, developing an effective and cost-efficient strategy for flare gas recovery remains a major challenge, requiring a careful balance between technical feasibility and financial viability. This study introduces a new approach to flare gas recovery by investigating two alternative utilization scenarios in a large-scale gas refinery. Furthermore, unlike conventional studies focusing primarily on economic feasibility, this research comprehensively integrates exergy analysis to evaluate energy and financial performance. This study analyzes all potential consumption sources of recovered flare gas and evaluates the feasibility and efficiency of two major effective scenarios. In the first scenario, recovered flare gases are compressed to 70 bar and injected into the gas sweetening unit, achieving an exergy-efficiency of over 69%. In the second scenario, recovered gases are redirected to existing compressors in the gas condensate stabilization unit, yielding a calculated exergy efficiency exceeding 78%. A detailed economic evaluation, considering both capital and operating expenditures, reveals that the overall flare gas recovery system has a return on investment of 17 months. Scenario one requires 24 months to break even, whereas scenario two achieves profitability in just 11 months. Ultimately, findings demonstrate that directing recovered flare gases to compressors of gas condensate stabilization unit provides most efficient and optimal utilization of these gases. Also, this research presents a viable solution for reducing emissions, minimizing waste, and maximizing both energy and financial resources in gas processing plants.
The enhanced oil recovery method by low-salinity water flooding in sandstones has had promising results. When two immiscible phases are in contact with a solid surface, one is generally more strongly attracted by the solid than the other, called the wetting phase. The ability of different polar compounds to change the rock wettability depends on the rock type. In sandstone reservoirs, the electrostatic attraction between the positively charged surface of the oil and the negatively charged basal plans of the rock controls the oil adhesion on the rock surface. It is well known that typically lowering the injection brine salinity can enhance oil recovery, however, the effects of low-salinity water injection in sandstones are probably the result of several mechanisms acting in conjunction, highlighting the need to execute experimental tests. Moreover, this study aimed to evaluate the effect of brines with different compositions and salinity on the oil recovery factor of reservoir sandstone cores by carrying out core flooding experiments. In addition, reservoir cores were very friable, so sandpacks were produced to facilitate manipulation and make it possible to carry out the water flooding tests. Furthermore, they were used in four core flooding tests. Also, results indicated a potential low-salinity water effect, with an average incremental oil recovery of around 5.8%. The injectivity was analyzed using differential pressure during the experiments, and significant alterations were not observed due to the change in salinity of injected brines. Ultimately, the mineralogical analysis suggests that even sandstones with no clay content might show additional oil recovery due to low-salinity water injection, bespeaking the need to conduct more experiments for further investigation of the impact of the injected brine, the mineralogical composition of the rocks and the acting mechanisms.
Although water and gas injection within enhanced oil recovery has garnered considerable attention in the contemporary era, some engineers argue that alternative and cost-effective methods could play a pivotal role in this field. The utilization of substances like surfactants and polymers is seen as an innovative technique that has substantially impacted the oil sector; however, the large-scale production of such materials is financially burdensome. Furthermore, manufacturing these substances results in hazardous wastes, posing risks to both human health and the environment, ultimately leading to extensive and irreversible pollution. Adopting natural surfactants emerges as a viable solution with relatively high efficacy. These plant-derived surfactants, extracted from indigenous plant leaves, are cost-effective, biodegradable, and pose no threat to human health or the environment. Incorporating these natural surfactants in oil-related experiments has yielded satisfactory outcomes, showcasing their effectiveness in reducing the interfacial tension between water and oil, modifying crude oil viscosity, and isolating heavy components of crude oil. Using conventional methods in the industry, such as water and gas injection, only leads to small exploitations, and in general, a considerable amount of oil remains in place. However, using modern methods, such as surfactant injection, these efficiencies increase to 30-40%. According to the micromodel injection tests, maximum recovery factors are achieved when natural surfactants interact well with divalent ions; the cedar non-ionic and Rosemary cationic surfactants have improved efficiency by 33% and 46%, respectively.
This paper delves into the transformative implications of Digital Twin (DT) technology on pipeline management within Industry 4.0, emphasizing its pivotal role in ensuring integrity, efficiency, and leak detection for oil, gas, and water transportation. The proposed pipeline management platform adopts a conceptual DT architecture, integrating key components such as the Asset Administration Shell (AAS), Admin-Shell-IO, Node-RED, Apache StreamPipes, SimCenter, MATLAB, and Ignition software.The platform focuses on automation, operational optimization, safety, and regulatory compliance through this integration. To achieve these goals, the paper introduces the Modified Real-Time Transient Modeling (MRTTM) framework, which aims to swiftly and accurately detect and locate leaks. Furthermore, the operational procedure of this framework involves three key stages. In the “Data Collection” phase, sensor data are monitored by observing nodes. In the subsequent “Detection” stage, leaks are identified, and in the concluding “Decision-making” module, the exact magnitude and location of the leakage are determined using MRTTM. Leveraging a hybrid approach that combines the Extended Kalman Filter (EKF), Real-Time Transient Modeling (RTTM), and machine learning algorithms, the framework offers accurate insights into the pipeline’s operational status. Moreover, machine learning models, including K-nearest neighbors (KNN) and support vector machines (SVM), enhance anomaly detection precision, allowing for early identification and localization of potential leaks.Ultimately, the proposed framework brings several key benefits to pipeline management, including early anomaly detection, real-time data integration, predictive maintenance, and regulatory compliance. By identifying potential leaks and anomalies early on, operators can take measures to prevent failures, respond quickly to disruptions, and comply with environmental and safety regulations.
The processing of hamburger bean (HB) and African oil bean (AF) seeds for local consumption generates large amounts of waste (shells) that are considered an environmental nuisance. This manuscript presents the experimental result from the study on the utilization of HB and AF shell powders as fluid loss control additives in drilling mud. The mud filtration test was conducted at 25oC and 100 psi following with the American Petroleum Institute (API) guidelines for polymer-based mud. From the study, the HB-based mud sample showed a progressive decrease in the volume of fluid loss as the content of the HB additive increased. Furthermore, the fluid loss from mud samples with AF increased with an increase in its concentration, producing mud cake thickness between 2.2 and 2.8 mm. ultimately, the results demonstrate that HB is a cost-effective and sustainable green additive that can serve as a local alternative to the imported and expensive conventional filtrate control additives.
Chemical looping reforming is a new technology for hydrogen or synthesis gas (syngas) production with lower CO2 emission and energy usage than conventional routes such as methane steam reforming. In this study, the numerical analysis of syngas production in a packed-bed reactors’ network is presented. Moreover, the proposed layout consists of four parallel reactors performing oxidation, reduction, and purge operations. In addition, both nickel and perovskite particles are used as the oxygen carrier. Furthermore, methane and oxygen were employed as fuel and oxidizer to produce H2 and CO continuously. In addition, with the proper selection of temperature and reduction time, a dynamic study was carried out to evaluate the feasibility of the proposed system in terms of methane conversion (about 1), H2 yield (about 0.65 mole H2/mole CH4), average syngas ratio (about 4 mole H2/mole CO) and zero carbon dioxide at the reactor output. In the end, a switching system of the network is proposed for continuous syngas production..
This study presents a comprehensive review combined with experimental and numerical investigations into the effectiveness of acoustic wave and high-frequency (HF) radiation exposure on oil properties and core permeability to enhance oil recovery in low-permeability reservoirs. Also, a specially designed experimental setup was developed to replicate reservoir conditions, maintaining a temperature of 40 °C and a pressure of 27.58 MPa. Core samples from a reservoir in the Republic of Tatarstan were used to simulate realistic conditions of low-permeability oil reservoirs. The experiments were conducted at an HF radiation frequency of 2 GHz and acoustic wave frequencies of 3, 4, and 5 kHz. Oil viscosity and core permeability changes were evaluated over exposure times ranging from 10 to 60 minutes. Experimental results demonstrated that combined HF and acoustic wave exposure significantly reduced oil viscosity by up to 35% and increased core permeability by up to 40%, with the most effective results achieved at an acoustic frequency of 5 kHz and the maximum exposure time. Numerical modeling in COMSOL Multiphysics was employed to complement the experimental findings, visualizing sound pressure distribution within the core and its effect on the pore structure. Ultimately, these results confirm the validity of the experimental observations and suggest that combined HF and acoustic wave exposure is a promising technology for enhancing oil recovery in low-permeability reservoirs.
Accurate interfacial tension (IFT) determination between crude oil and brines is crucial in enhanced oil recovery (EOR) processes. However, the available IFT models only apply to systems containing pure hydrocarbons and saline waters. The current study aims to design comprehensive predictive tools for the IFT between asphaltenic crude oils and various brines. Hence, 339 relevant experimental data covering an extensive range of operating conditions were gathered from the literature, and the most effective input variables were determined through Spearman’s rank coefficient. Then, the experimental data were utilized to train the smart soft-computing approaches, i.e., radial basis function (RBF), multilayer perceptron (MLP), and Gaussian process regression (GPR). Although all novel predictive tools presented excellent results, the one designed based on the GPR method was recognized as the most reliable model with an average absolute relative error (AARE) of 0.67% and an R2 value of 99.63% in the testing stage. Additionally, it estimated most of the IFT data with relative errors below 0.10%. On the other hand, the validity of the gathered databank was confirmed through the leverage method. The influences of pressure, temperature, salinity, and structural characteristics of salts on the IFT were discussed in detail, and the proposed models favorably described the physical trends. Eventually, a sensitivity analysis was carried out based on the GPR model to clarify the order of significance of factors in controlling the crude oil-brine IFT.
sequent shale swelling. In this study, we utilized Carboxymethyl Trimethyl Ammonium Chloride (CTAC) to inhibit shale swelling, representing a novel application for this particular cationic surfactant. Several experiments were carried out to assess the effectiveness of CTAC in preventing shale swelling and to gain insights into the underlying mechanisms. Moreover, based on the results, CTAC is highly effective at low concentrations and can be used with other common additives. Furthermore, the contact angle in the presence of CTAC, cetyltrimethylammonium bromide (CTAB), and potassium chloride (KCl) at 1 wt.% in the bentonite mixture was 77°, 75°, and 38°, respectively. Also, by adding CTAB, total shale recoveries in simple and complete drilling muds increased by 5.53% and 0.94%, respectively. Meanwhile, In the presence of CTAC, the increase was equal to 12.37% and 6.43%, respectively. In addition, CTAC and CTAB in the complete drilling mud reduced the swelling by 9.94% and 4.2%, respectively. Ultimately, comparative studies show that CTAC performs better as a new inhibitor than CTAB and KCl as conventional inhibitors.
The quality and extraction rate of oil shale is a significant challenge in the oil shale processing field. In this article, the effects of heating rate and grain size as fundamental parameters in oil shale production from the QaliKuh reservoir in Iran on the quantity and quality of produced oil shale are explored as other sources. Fisher’s developed microwaves at 2450 kHz were used to heat several oil shale samples at power levels of 650, 900, and 1200 watts up to coking temperature (700 °C). It was observed that the amount of oil produced increased from 5.2% to 5.9%, then it reduced to 5% weight of the sample as the microwave heating rate increased; however, the quality of the oil (asphaltene reduced from 25% to 19%, sulfur content reduced from 16% to 7%, and carbon percentage increased from 67% to 78%,) improved. In contrast, conventional oil shale pyrolysis showed that the quality of the oil improved with an increase in the heating rate (asphaltene reduced from 31% to 28 %, sulfur content reduced from 19% to 13%, and carbon percentage near to constant), while the amount of produced oil diminished from 4.7% to 4.3% weight of the sample. The grain size of the shale was divided into three ranges: 7-12 mm, 7-4 mm, and less than 4 mm. In the case of microwave heating, the amount of produced oil increased with the grain size reduction (from 5.9% to 6.8% weight of the sample). Still, the quality fluctuated (asphaltene reduced from 20% to 18 % then increased to 22%, sulfur content reduced from 12% to 10% then increased to 15%, carbon content increased from 75% to 80% then reduced to 69%, Aliphatic component increased from 38% to 40.5% then reduced to 34%, also aromatic index reduced from 0.28% to 0.26% then increased to 0.31%). These results suggest that there is potential for further research to optimize the grain size for oil shale production. With the conventional heating techniques, the quality of the produced oil improved but can also fluctuate with decreases in grain size (from 4.7% to 5.4% then 5.1%). Also, the quality fluctuated (asphaltene reduced from 31% to 30 % then increased to 33%, sulfur content reduced from 19% to 17% then increased to 20%, carbon content increased from 62% to 71% then reduced to 64%, Aliphatic component increased from 28% to 30% then reduced to 25%, also aromatic index reduced from 0.29%, to 0.42% then increased to 0.36%). It was found that microwave pyrolysis yielded more oil produced than the conventional method and improved the quality of the oil. An optimal particle size and heating rate can be established based on the results, sparking interest in further research to explore these possibilities.
Starch reduces fluid loss while enhancing viscosity in drilling fluid formulation. Starch obtained from soursop (SS) was chemically modified by carboxymethylation methods (SC1 & SC2) and acetylation method (SA) and compared with cassava (CN). The physicochemical properties: swelling power, gelatinization temperature, thermal stability and particle size, rheological properties: yield point (YP), gel strength and plastic viscosity (PV) and also fluid loss control of the starches were investigated to determine their performance as viscosity enhancer and fluid loss control ability in drilling fluid. The results obtained revealed that modified starches (SC1 and SC2) demonstrated better physicochemical properties than SA, SS and CN. Thus, showing that carboxymethylation improved the thermal stability and gelatinization temperature of the starches. The morphology result revealed that modification reduced the particle size of the starches thereby, increasing their surface area and reactivity. In addition, the native and modified soursop starches exhibited good rheological properties and fluid loss control as required by API standards. However, modified starch, SC2 exhibited better rheological properties in PV, YP, gel strength and controlled filtration-loss than other starches SC1, SA as well as native soursop and cassava. The possession of these excellent properties places soursop and its modified starches (SCI and SC2) as potential replacement for cassava as additives in drilling fluid formulation. This will help improve efficiency in drilling operations, and on the other hand help to reduce the negative impact on food security in Nigeria since soursop is mainly consumed as a dessert.
Fractures are the main flow channels for oil and gas in the Permian Jiamuhe Formation volcanic reservoir in the Jinlong 2 Oilfield at the northwestern margin of the Junggar Basin. According to core, thin section and image logging data analyses, the fractures in this area are dominantly semifilled or unfilled high-angle fractures, followed by semifilled low-angle oblique fractures, and vertical fractures. The image logging results show that the fractures are oriented nearly east–west, approximately parallel to the direction of the present-day maximum principal in situ stress, and they have good flow effectiveness. The volcanic reservoir fracture development is mainly affected by structure and lithology. The fractures are mostly distributed in strips along the faults. The closer to the fault, the greater the structural curvature and the more developed the fractures. The fractures of intermediate–acid volcanic lava and pyroclastic lava are well developed in the study area. Additionally, the fracture development characteristics of a single well are determined by calculating the fracture density, fracture dip angle, and fracture porosity. Combined with the prestack seismic prediction method, i.e., amplitude versus azimuth (AVAZ), the attenuation initial frequency attribute is selected to predict the fracture distribution characteristics of the Jiamuhe Formation volcanic reservoir.
The Fahliyan Formation, a significant carbonate reservoir in southwestern Iran encompassing the Izeh and Dezful Zones, underwent detailed petrographic investigations. These analyses revealed eight distinct microfacies associated with four different depositional settings within a homoclinal ramp model. From a diagenesis perspective, the formation has undergone various processes, including micritization, dissolution, compaction, cementation, dolomitization, stylolitization, and fracturing. These diagenetic features affected the Fahliyan Formation from early marine–meteoric to late burial diagenetic realms. Notably, dissolution developed as the most effective and widespread diagenetic feature, improving reservoir quality. Likewise, fracture and dolomitization positively impact reservoir quality, while compaction and cementation have destructive effects. Micritization and early isopachous calcite cement have a retentive role in reservoir characteristics. In addition, the Flow Zone Indicator (FZI) approach introduced three Hydraulic Flow Units (HFUs). The correlation between microfacies types and their petrophysical features indicates that the bioclastic peloid packstones and grainstones have better reservoir quality, which resulted from dissolution, and initial isopachous calcite cements. Also, Planktonic foraminifer’s bioclastic mud/ wackestone and Quartz-bearing mudstone, equivalent to HFU1, indicate lower reservoir quality due to the compaction (stylolitization) and cementation.
Oil/brine electrical behavior could control the wettability of the oil/brine/rock system during low salinity water flooding. However, there is a lack of understanding of chemical reactions occurring on the oil surface. There are a few surface complexation models (SCMs) for the oil/brine interface, and all of them assume that the surface site density is a fixed number, like the mineral surface. The current study assessed two existing models on this subject (Model A and B). These models ignore the dynamic nature of the oil/brine interface. Therefore, they failed to capture experimentally measured ζ potentials appropriately. Therefore, this study constructed a novel diffuse layer SCM (Model C) considering the interfacial concentration of surface carboxylic acid as a function of brine salinity for each salt, including NaCl, Na2SO4, CaCl2, MgCl2, and NaHCO3. Model C matches the experimental data of the literature far better than A and B. Based on Model C, Na+, Cl-, and SO42- cannot be adsorbed on the oil/brine interface; however, the role of these ions in the electrical behavior of crude oil/brine is only to affect the interfacial concentration of -COOH. For example, an increase in Na+ reduced the oil/brine IFT. Therefore, more carboxylic groups would be available at the oil/brine interface. As a result, -COO- concentration increases, and the crude oil surface becomes more negatively charged. The current study indicated that Ca2+ and Mg2+ are not the only factors that make the interface more positively charged. However, an increase in IFT (in this study by salinity reduction) significantly makes the oil/brine interface more positive, too.
TiO2 nanocomposites on carbonaceous compounds, such as carboxyl-functionalized, multi-walled carbon nanotubes (MWCNT-COOH), and graphene oxide (GO) were synthesized by the sol-gel method. The samples were coded as TiO2 (T), TiO2-MWCNT-COOH (TM), and TiO2-GO (TG). The effect of the addition of carbonaceous compounds on the enhancement of demulsification efficiency of TiO2 nanocomposites in crude oil (W/O) emulsions was then investigated. FT-IR, Raman, and morphological analyses such as FE-SEM, EDXS, XRD, HR-TEM, DRS, BET surface area, and TGA were used to determine the properties and structures of the nanoparticles prepared. In addition, the demulsification efficiency of three nanoparticles was studied under various concentrations, settling times, and temperature conditions by bottle test. According to the screening results, TG was selected as the best sample. The response surface method with a central composite design (CCD) was used to optimize the demulsification activity of TiO2 nanocomposites with graphene oxide (TG). Thus, the impacts of temperature, demulsifier concentration, and time were studied by the RSM-CCD method. Ultimately, the results indicated ~100% demulsification efficiency under optimal conditions at concentration, temperature, and time of 75 ppm, 65oC, and 120 min., respectively.
