Mechanism Of Oil Production Research Articles

Oil Production Mechanism of Water Injection Huff-n-Puff for Enhancing Oil Recovery in Tight Sandstone Reservoir

Oil Production Mechanism of Water Injection Huff-n-Puff for Enhancing Oil Recovery in Tight Sandstone Reservoir

INCREASING THE EFFICIENCY OF THE SAGD METHOD BY ADDING VARIOUS GASES

Due to their low mobility in the reservoirs, heavy oils are very difficult to produce by conventional methods. That is why several specific techniques have been created by geoscientists, in order to produce those heavy oils which represent a significant part in the world primary energy resources. One recurrent principle among those methods is to heat the oil, or to modify its composition in order to reduce its viscosity. And then the resulting oil, more mobile flows toward the production wells thanks to the gravity force. The main problematics of this project are first to highlight the importance of gravity drainage in the production of heavy oil. And after that, how using the gravity to produce the maximum of oil? In other words, with a given reservoir model, what kind of addition of hydrocarbon gases or CO2 can we consider as improving effect for gravity mechanism of oil production. The goal of this study is to simulate the ES-SAGD, which stands for Expanded Solvent SAGD. Let’s keep in mind that the objective is to enhance oil recovery by changing its composition, and meanwhile decreasing its viscosity for example thanks to the injection of miscible gas. Through the different sections of this part, we will investigate the effects of injecting different solvents in our reservoir model. In the course of the study pure steam, CH4, C3H8 and CO2 cases and their different mixtures were considered during this research. Solvents that give the largest amount of oil recovered were identified.

Investigating the Synergistic/Antagonistic Effects of Mixing SiO2 Nanoparticles and Ionic Liquid, Nonionic Emulsifier, and Gemini Surfactants on the Main Mechanisms of Crude Oil Production

Investigating the Synergistic/Antagonistic Effects of Mixing SiO₂ Nanoparticles and Ionic Liquid, Nonionic Emulsifier, and Gemini Surfactants on the Main Mechanisms of Crude Oil Production

Analysis of Migration Characteristics of Supercritical CO2 and Mechanism of Oil and Gas Production in Condensate Gas Reservoirs

At present, circulating gas injection is the most effective development method for condensate gas reservoirs in China, but the phenomenon of dry gas overlap has seriously affected the development effect of circulating gas injection in condensate gas reservoirs, while CO2 injection is used to drive gas, which can make CO2 widely used in removing retrograde condensation of condensate gas reservoirs, improving the development effect of gas reservoirs. This paper by comparing the migration laws of injected dry gas and injected CO2 obtains that the dry gas with a smaller density flows to the upper space of the reservoir, while the CO2 with a larger density settles to the lower part. With the injection of CO2 into the reservoir, the content of CO2 in the crude oil increases, the volume of condensate oil expands significantly, and the flow capacity of condensate oil in the formation is improved. Injecting CO2 into the formation can reduce the viscosity of condensate. The mixture of CO2 injected into the formation and formation water is slightly acidic, which can dissolve some cement in the rock. With the increase of CO2 injection, the interfacial tension between oil and water will also increase, which is unfavorable for the stability of the oil-water system and is easy to emulsify. After demulsification, the viscosity will decrease and the condensate oil will flow more easily. The dissolved carbon dioxide in the water is in a weak acid state, which is easy to corrode and shed particles, improving the reservoir space and seepage conditions near the well. It will provide theoretical support for the effective development of a condensate gas reservoir.

Enhanced recovery of tight reservoirs after fracturing by natural gas huff-n-puff: Underlying mechanisms and influential factors

Tight oil resources are abundant in the world. It is very important to strengthen the research on the development theory and technology of tight oil reservoirs for ensuring national energy security. Natural gas huff-n-puff can effectively improve the oil recovery of tight oil reservoirs. However, the pore-scale oil production characteristics and the mechanisms of natural gas huff-n-puff in matrix-fracture cores are poorly understood. The influence degree of important factors on oil recovery is not clear and the interactions between factors are rarely considered. In this paper, the oil production characteristics and mechanisms of natural gas huff-n-puff in tight cores with different fracture lengths were quantitatively analyzed by combining nuclear magnetic resonance (NMR) with numerical simulation technology. The influencing factors and their interactions were evaluated by the response surface method (RSM). The results show that tight cores mainly consist of medium pores (0.1–1 μm) and small pores (0.01–0.1 μm). The fracture mainly increases the proportion of macro-pores (1–10 μm) and medium pores. In the natural gas huff-n-puff process, crude oil from macro-pores (1–10 μm) and medium pores is mainly developed, and the contribution percentage of crude oil in medium pores to oil recovery is the largest, up to 98.28%. The position of gas–oil contact (GOC) moves deeper as the number of huff-n-puff cycles increases. The contents of CH4 and CO2 in the oil phase remain at a high level within the GOC, while between the GOC and the component sweep front, the contents of CH4 and CO2 in the oil phase decrease with the increase in dimensionless distance. The gas component sweep volume is increasing with the increase in fracture length. Moreover, the injected natural gas mainly extracts C3–C10 components from crude oil. The reduction law of crude oil viscosity is consistent with the migration laws of CH4 components along the path. Compared with soaking time and gas diffusion coefficient, the injection pressure is the most significant factor underlying the recovery of natural gas huff-n-puff in tight cores. Besides the influence of single-factor, the interaction effects of gas injection pressure and diffusion also should be considered to determine the huff-n-puff parameters in the field implementation of natural gas huff-n-puff in tight reservoirs after fracturing.

Effect of ADH7 gene loss on fusel oil metabolism of Saccharomyces cerevisiae for Huangjiu fermentation

Hongqu Huangjiu is considered to have higher fusel oil content than other alcoholic beverages. Saccharomyces cerevisiae is the microorganism most responsible for fusel oil production during fermentation. We found that ADH7 gene loss might be closely related to low fusel oil production of S. cerevisiae. The aim of this study was to determine the effect of ADH7 gene on the fusel oil metabolism of S. cerevisiae. S. cerevisiae strain JH301 was used as the research strain with low fusel oil production, S. cerevisiae model strain S288c was used as the control strain. ADH7 gene complementation in the strains JH301-A1, JH301-A2, and JH301-A3 was carried out by rDNA-mediated multicopy integration. The effect of ADH7 gene loss on fusel oil metabolism of S. cerevisiae was analyzed by measuring fusel oil production of gene complementation strains, JH301 and S288c. The results showed that ADH7 gene loss reduced the production of six compounds, mainly including 3-methyl-1-butanol and 2-methyl-1-propanol. In addition, it had a significant effect on fusel oil formed by amino acids rather than formed by glucose. To conclude, these findings show the importance of understanding the molecular mechanism of low fusel oil production in S. cerevisiae.

A capillary bundle model for the forced imbibition in the shale matrix with dual‐wettability

AbstractThe forced imbibition during hydraulic fracturing is one of the main mechanisms of oil production in shale oil reservoirs. However, the shale matrix has complex structures of nanopores and is rich in organic matters. The wettability of nanopores in organics matters is different from the nanopores in inorganic matters, and the characteristic of dual‐wettability leads to complex mechanisms of forced imbibition. This paper proposes a model for describing the imbibition in a dual‐wettability shale oil reservoir based on the capillary tube model. The external displacement pressure gradient is also considered to study the forced and spontaneous imbibition of hydraulic fracturing liquid into oil‐wet organic nanopores and water‐wet inorganic nanopores. The slip effect in organic nanopores and the boundary‐layer effect in inorganic nanopores are considered in this model. The analytical expressions for describing the location of the oil–water imbibition front in an oil‐wet organic nanopore and a water‐wet inorganic nanopore are derived, respectively. The semi‐analytical solution for predicting flow rate in a shale core with an external pressure gradient is given and demonstrated with a case study.

Lag times in toe-to-heel air injection (THAI) operations explain underlying heavy oil production mechanisms

From a time value of revenue point of view, it is preferred that the time between reservoir stimulation and oil production response is small. Heavy oil combustion processes have a lag time between air injection and liquid production, but the common practice in production data analysis uses simultaneous injection and production data when seeking a relationship between them. In this research, the time scales of production for the Kerrobert toe-to-heel air injection (THAI) heavy oil project in Saskatchewan, Canada, is analyzed by using cross correlation analysis, i.e. time delay analysis between air injection and oil production. The results reveal two time scales with respect to production response with two distinctive recovery mechanisms: (1) a short time scale response (nearly instantaneous) where oil production peaks right after air injection (directly after opening production well) reflecting cold heavy oil production mechanisms, and (2) a longer time scale (of order of 100–300 days) response where peak production occurs associated with the collective phenomena of air injection, heat generating reactions, heat transfer, and finally, heated mobilized heavy oil drainage to the production well. This understanding of the two time scales and associated production mechanisms provides a basis for improving the performance of THAI.

Experimental evaluation of designed and synthesized Alkaline-Surfactant-polymer (ASP) for chemical flooding in carbonate reservoirs

More than half of the oil and gas resources of the world are hosted in carbonate reservoirs. Also, a total of 60% of their residual oil is left unswept during conventional primary and secondary oil recovery operations. The complexity of carbonate reservoirs due to relative weak water imbibition, undesired capillary forces, low permeability (less than 50mD), oil wetness and geochemical interactions in the presence of formation water high salinity causes precipitation of the injection chemicals resulting in clogging of pore throats and residual oil entrapment. Therefore, taking advantage of purposefully designed chemicals known as alkaline-surfactant-polymer (ASP) for enhanced oil recovery (EOR) applications rather than common commercial ASP materials for these challenging petroleum reservoirs is expected. In this research, the synthesized ASP combination was considered to improve the oil production mechanisms of the desired carbonate porous medium. Ultra-low interfacial tension about 1.6 × 10–3 has been achieved by Alkaline-Surfactant-Nano (ASN) synergistic formulation. Meanwhile, wettability alteration was evaluated by contact angle measurement. The contact angle was reduced from Θ = 155.2° (oil-wet) to Θ= 23.7° (water-wet) by the ASN combination. As well, the remarkable HTHS tolerable and shear resistance synthesized Co-polymer Nanocomposite was applied, and 10 times diluted seawater (losal) was chosen as chemicals compatible aqueous solvent for core flooding experiments. Thus, formulated ASP fluids were synergized by alumina nanoparticles at optimized concentrations of chemicals. Hence, this synthesized ASP is able to improve the residual oil production mechanism and lower the capillary pressure (Pc). 16 chemical flooding scenarios were run on Karanj oil field carbonate outcrop cores; the results of the four successful scenarios with the highest original oil in place (OOIP) recovery percentages are discussed. Experiments results are revealed that the cumulative oil recovery could arrive at 91% under the harsh condition of the reservoir. According to the findings of current research, this ASP formulation is highly recommended for chemical flooding of tight carbonate reservoirs.

Evaluation Model and Application of Shale Oil Production Efficiency Under Energy-Depleted Development Mode in Jimsar Sag

In order to reveal the shale oil production mechanism and production efficiency under the energy-depleted development mode, experiments on expulsion oil based on imbibition and elastic energy release under high temperature and pressure were carried out, and nuclear magnetic resonance on-line monitoring was used to observe the production characteristics of shale oil. The experimental results show that the imbibition-expulsion oil mainly occurs in the small-size pore-throat system. Under the condition of high temperature and pressure, the oil-expulsion efficiency is generally less than 2% affected by pore pressure, which is significantly different from the conventional imbibition experiment results. Although elastic-energy expulsion oil occurs in different sizes of pore-throat systems, the oil-expulsion efficiency in large size pore-throat systems is more sensitive to temperature. Overall, the total elastic-energy oil-expulsion efficiency is significantly positively correlated with reservoir physical properties, production differential pressure and temperature, and negatively correlated with crude oil viscosity. Comprehensively considering various geological factors affecting oil-expulsion efficiency, the shale oil production efficiency evaluation model under the energy-depleted development mode is constructed, and the movable oil porosity of shale oil development section in the study area is evaluated. The results show that there is a good positive correlation between movable oil porosity and oil production intensity. The movable oil porosity of dry layer is generally lower than 0.5% and that of poor oil layer is between 0.5% and 1.5%. When the movable oil porosity is between 1.5 and 2.5%, it can be determined as the type II oil layer, and for more than 2.5%, it is the type I oil layer. The single-well evaluation results show that the shale oil “sweet spots” of the Lucaogou Formation in Jimsar Sag are mainly distributed in P2l22−1∼ P2l22−3 and P2l12−1∼ P2l12−3, which is in good agreement with the current development status.

Numerical Investigation of Oil–Water Exchange Behaviors in Shale During Post-Fracturing Soaking Periods

Fracturing fluid imbibition and retention are treated as a main mechanism for oil production from shale reservoirs. However, the oil–water exchange phenomenon during post-fracturing soaking periods has not been thoroughly studied. In this study, a water–oil flow model is built to investigate the water imbibition and oil drainage phenomenon in hydraulically fractured shale. With the developed numerical simulator, the main characteristics of post-fracturing soaking, that is, pressure diffusion, water imbibition, and especially, the oil–water exchange behavior are simulated. Three key time points, that is, oil–water exchange equilibrium, steady exchange efficiency, and oil breakthrough in fracture are found. The oil–water exchange efficiency and exchange volume are also calculated. Moreover, the proposed model is validated by field wellhead pressure dynamics, indicating a relevance of time between the oil–water exchange efficiency and the wellhead pressure falloff derivatives. Finally, the influences of shale permeability, wettability, fracture complexity, and oil viscosity on the oil–water exchange behavior are investigated. Results indicate that the matrix of oil-wet shale almost does not suck water and discharge oil, and only the oil in natural fractures exchanges with the water in hydraulic fractures. The water-wet shale with low permeability, high oil viscosity, and few natural fractures needs extra soaking time to achieve good oil–water exchange performance. The suitable soaking period for the water-wet base case in this study is from 17.25 to 169 days, among which 64 days is the optimal soaking time.

Effect of in Situ Formed Emulsions on Enhanced Extra-Heavy Oil Recovery by Surfactant Flooding

Thermochemical flooding is becoming more popular nowadays as a subsequent EOR method after thermal recovery in extra-heavy oil reservoirs. During this process, in-situ emulsions could happen due to interfacial active components existing in heavy crude oil. The enhanced oil recovery is inevitably related with the formation of emulsions, which is one of the main mechanisms and deserves a thorough study. Also, the features of relative permeability curves during thermochemical flooding should be investigated further, because they are very important but usually are difficult to obtain since physical reactions could happen.Based on core-flooding experiments, combined with careful observation of produced crude oil emulsion morphology, this paper compared and analyzed the features of relative permeability curves and displacement efficiency at different conditions, and the mechanisms of extra-heavy oil production by surfactant displacement is then investigated. The surfactant used are provided by the oilfield at a varied mass fraction of 0.1%, 0.2% and 0.3% and under temperature of 100, 150 and 180 °C. The relative permeability data were processed with JBN method.The experimental results show that both the oil and water relative permeability increase as the temperature increases. As surfactant concentration increases, the relative permeability of the aqueous phase decreases as opposite to oil. The ultimate recovery increased with the increase of temperature and surfactant concentration. Except for the oil viscosity reduction by surfactant, it is interesting to note that the formation of crude oil emulsions (mainly O/W emulsions) are observed to be positively impacting the oil recovery factor. As surfactant concentration increases, larger size of dispersed phase in the emulsions were observed in the effluent corresponding to a higher oil recovery factor. This work is of great significance for heavy oil research and field development.

Solvent co-injection with steam-assisted gravity drainage process performance evaluation–New analytical treatment in relation to constant injection rate

Steam-based enhanced oil recovery methods like Steam-Assisted Gravity Drainage (SAGD) for extracting extremely heavy oils and bitumen are energy intensive and require high steam volumes with steam generation resulting in significant greenhouse gas emission. The oil industry has resorted to adding solvent to steam aiming to overcome these limitations. A new analytical model is developed for describing solvent co-injection with steam (solvent-SAGD) process in relation to constant injection rate, for the first time, based on the combination of an overall solvent mass balance, heat balance and volumetric oil displacement and Darcy's oil rate using a mixture viscosity model as a function of temperature and solvent concentration ahead of a moving vapor-oil front which satisfy the equilibrium in the system. The objectives of this work are to evaluate the performance of the solvent-SAGD process by predicting; vapor chamber growth, oil production rate, solvent production rate, solvent loss (or solvent retention) rate, and the effect of solvent type and concentration on the process. The mechanism of oil recovery by steam with added solvent is not clear. Given the controversy regarding the use of solvents with steam, by developing the new mathematical approach, this study is intended to explain whether solvent-SAGD process increases oil recovery compared to SAGD or not. If any, which solvent results in better recovery. The results of this approach give a better understanding of the oil production mechanism during the solvent-SAGD process by interconnecting vapor chamber conditions and the conditions of heated and diluted oil ahead of the moving vapor-oil interface. The results show that mass transfer occurs over a scale of centimeters, while heat transfer scale is of the order of meters. The rate of solvent retention increases over time, while the production rates of solvent and bitumen decrease. Also, it is shown that the solvent-SAGD process which is a combination of heat and mass transfer would yield a higher oil recovery, if viscosity reduction from dilution at a lower temperature is greater than viscosity reduction by temperature in the SAGD process, for the same total injection rate.

Activating solution gas drive as an extra oil production mechanism after carbonated water injection

Abstract Enhanced oil recovery (EOR) methods are mostly based on different phenomena taking place at the interfaces between fluid-fluid, and rock-fluid phases. Over the last decade, carbonated water injection (CWI) has been considered as one of the multi-objective EOR techniques to store CO2 in the hydrocarbon bearing formations as well as improving oil recovery efficiency. During CWI process, as the reservoir pressure declines, the dissolved CO2 in the oil phase evolves and gas nucleation phenomenon would occur. As a result, it can lead to oil saturation restoration and subsequently, oil displacement due to the hysteresis effect. At this condition, CO2 would act as in-situ dissolved gas into the oil phase, and play the role of an artificial solution gas drive (SGD). In this study, the effect of SGD as an extra oil recovery mechanism after secondary and tertiary CWI (SCWI-TCWI) modes, has been experimentally investigated in carbonate rocks using coreflood tests. The depressurization tests resulted in more than 25% and 18% of original oil in place (OOIP) because of the SGD after SCWI and TCWI tests, respectively. From the ultimate enhanced oil recovery point of view, the efficiency of SGD was observed to be more than one-third of that of CWI itself. Furthermore, the pressure drop data revealed that the system pressure depends more on the oil production pattern than water production.

Effects of methanol and acetone as mutual solvents on wettability alteration of carbonate reservoir rock and imbibition of carbonated seawater

The enhanced oil recovery (EOR) methods combination is a way to simultaneously utilize the mechanisms of the combined methods. Besides, in chemical water injection, additives controlling the mechanisms by their mutual interactions also exert other effects on the system, known as synergistic effects. In the current study, acetone and methanol mutual solvents were utilized to enrich carbonated water and their effects on the mechanisms of carbonate reservoir rock wettability alteration and oil production in the imbibition process have been investigated at different conditions of salinity, the ratio of solvent to water and pressure. Also, various boundary conditions and fracture effects were considered in the imbibition experiments. Imbibition fluid optimization was performed based on the contact angle tests and reservoir rock wettability alteration. Seawater was used as the base fluid at various initial and diluted concentrations. According to the results, the contact angle magnitude depends on the parameters of salinity, the volume percent of the mutual solvents and the pressure so that as the solvents volume and pressure increase and the salinity decreases, the contact angle decreases when carbon dioxide (CO2) is present but in absence of CO2, the contact angle decreases with increasing base fluid salinity. The lowest contact angle values for methanol and acetone solvents were recorded at 10.342 MPa, initial seawater salinity, 15% volumetric solvent, and a constant temperature 75 °C in absence of dissolved CO2 at 60.95° and 58.43°, respectively. The lowest contact angle values were obtained in the presence of dissolved CO2 for methanol and acetone solvents at 15% volumetric pressure at 10.342 MPa, salinity resulting from 20 times seawater dilution and at a temperature of 75 °C at 36.31° and 32.92°. Final oil production of 66.29%, 28.44%, 85.42% and 91.38% of primary oil saturation for the imbibition of carbonated water containing 15%Vol of methanol and final oil production of 70.32%, 32.10%, 90.60% and 94.09% of primary oil saturation for the imbibition of carbonated water containing 15%Vol acetone were obtained which were performed as one-dimensional co-current spontaneous imbibition (COCSI), one-dimensional counter-current spontaneous imbibition (COUCSI), multi-dimensional COUCSI and imbibition in the fractured plug, respectively.

Comparative Analysis of Water Drive, Gas Drive and Natural Drive Mechanism for Oil Production using Alwyn North Field as a Case Study

In-situ Crude oil can be produced through several drive mechanisms of which the choice of specific drive mechanism is dependent on several key performance tools. This study examines the Alwyn North field and presents a comparative analysis for producing crude oil using water drive, gas drive and natural drive or depletion drive. The Eclipse Simulator was used to simulate different scenarios of well placement and performance tools such as FOPR, FPR, FWCT, FGOR and FOE was used during simulation to compare the outcomes of the well placement. Economic analysis which is key in decision making was carried out using economic tools such as Gross Profit Margin (GPM), Net Present Value (NPV), Payback Period, Internal Rate Return (IRR) and Profitability Index (PI). The payback period for water injection was 2.1years and 1.99years for gas injection. IRR was 53% and 48% for water and gas injection development schemes respectively and Profitability Index for water injection was 1.73 and 1.36 for gas injection. These economic tools helped to arrive at a conclusion of best drive mechanism for the production of the field.

Comparative Analysis of Water Drive, Gas Drive and Natural Drive Mechanism for Oil Production using Alwyn North Field as a Case Study

In-situ Crude oil can be produced through several drive mechanisms of which the choice of specific drive mechanism is dependent on several key performance tools. This study examines the Alwyn North field and presents a comparative analysis for producing crude oil using water drive, gas drive and natural drive or depletion drive. The Eclipse Simulator was used to simulate different scenarios of well placement and performance tools such as FOPR, FPR, FWCT, FGOR and FOE was used during simulation to compare the outcomes of the well placement. Economic analysis which is key in decision making was carried out using economic tools such as Gross Profit Margin (GPM), Net Present Value (NPV), Payback Period, Internal Rate Return (IRR) and Profitability Index (PI). The payback period for water injection was 2.1years and 1.99years for gas injection. IRR was 53% and 48% for water and gas injection development schemes respectively and Profitability Index for water injection was 1.73 and 1.36 for gas injection. These economic tools helped to arrive at a conclusion of best drive mechanism for the production of the field.

Quantifying the reimbibition effect on the performance of gas‐oil gravity drainage in fractured reservoirs: Mathematical modelling

AbstractAs a major oil production mechanism, gravity drainage in fractured oil reservoirs is heavily affected by the reimbibition phenomenon. In this work, a stack of oil‐saturated two matrix blocks surrounded by oil‐saturated fractures are considered as a synthetic fractured reservoir. A mathematical computer program is developed to numerically simulate the fluids’ flow through the matrixes and fractures employing the finely gridded single porosity concept. Simulation results are validated by checking the continuity of the gas volume through the reservoir. The percentage of oil recovered by gravity drainage is determined employing the new material balance equation approach. A new procedure is employed for deactivating the reimbibition phenomenon, introducing the zero transmissibility for the oil phase in the case of oil transfer from the fracture to matrix region. According to the simulation results and considering the proposed model, under the constraints of constant gas injection and oil production rates, fully or partially deactivating the reimbibition phenomenon causes a faster gas movement through vertical fractures. The reason for this is that some of the oil leaving the upper matrix block goes to vertical fractures and causes a faster gas breakthrough in them due to reduced available pore volume to gas. In this case the oil recovered by gravity drainage from the system is decreased. Inactivating this phenomenon in the simulated case study causes a 40 % reduction in oil production by gravity drainage from the matrix blocks until the breakthrough time.

Comprehensive evaluation of fuel properties and complex regulation of intracellular transporters for high oil production in developing seeds of Prunus sibirica for woody biodiesel

BackgroundBased on our previous studies of 17 Prunus sibirica germplasms, one plus tree with high quality and quantity of seed oils has emerged as novel potential source of biodiesel. To better develop P. sibirica seed oils as woody biodiesel, a concurrent exploration of oil content, FA composition, biodiesel yield and fuel properties as well as prediction model construction for fuel properties was conducted on developing seeds to determine the optimal seed harvest time for producing high-quality biodiesel. Oil synthesis required supply of carbon source, energy and FA, but their transport mechanisms still remains enigmatic. Our recent 454 sequencing of P. sibirica could provide long-read sequences to identify membrane transporters for a better understanding of regulatory mechanism for high oil production in developing seeds.ResultsTo better develop the seed oils of P. sibirica as woody biodiesel, we firstly focused on a temporal and comparative evaluation of growth tendency, oil content, FA composition, biodiesel yield and fuel properties as well as model construction for biodiesel property prediction in different developing seeds from P. sibirica plus tree (accession AS-80), revealing that the oils from developing seeds harvested after 60 days after flowering (DAF) could be as novel potential feedstock for producing biodiesel with ideal fuel property. To gain new insight into membrane transport mechanism for high oil yield in developing seeds of P. sibirica, we presented a global analysis of transporter based on our recent 454 sequencing data of P. sibirica. We annotated a total of 116 genes for membrane-localized transporters at different organelles (plastid, endoplasmatic reticulum, tonoplast, mitochondria and peroxisome), of which some specific transporters were identified to be involved in carbon allocation, metabolite transport and energy supply for oil synthesis by both RT-PCR and qRT-PCR. Importantly, the transporter-mediated model was well established for high oil synthesis in developing P. sibirica seeds. Our findings could help to reveal molecular mechanism of increased oil production and may also present strategies for engineering oil accumulation in oilseed plants.ConclusionsThis study presents a temporal and comparative evaluation of developing P. sibirica seed oils as a potential feedstock for producing high-quality biodiesel and a global identification for membrane transporters was to gain better insights into regulatory mechanism of high oil production in developing seeds of P. sibirica. Our findings may present strategies for developing woody biodiesel resources and engineering oil accumulation.

Modification of LoSal water performance in reducing interfacial tension using green ZnO/SiO2 nanocomposite coated by xanthan

Interfacial tension (IFT) is one of the most important factors that affect oil production mechanisms in porous media. Nanoparticles show potential for high performance in IFT reduction, wettability alteration and enhanced oil recovery. The current work focuses on the simple, economical and, importantly, green method of biosynthesis to generate a nanocomposite (NC) for reducing the IFT in enhanced oil recovery. In this study, ZnO@SiO2@Xanthan NC was created from pomegranate sed extract and characterized by various analytical techniques. The nanofluids were prepared by varying the concentration of NC to find the optimum value of IFT reduction under different conditions of salinity, temperature and pressure. The results showed that by applying this nanocomposite at a concentration of 2000 ppm into a low salinity (LoSal) water at high temperature and pressure, the IFT reduced by 93.6% from 31.8 (for seawater) down to 2.016 mN/m. Further IFT reduction was obtained by the NC as the salinity of water was decreased and the temperature and concentration of NC were increased although there was no clear trend with pressure.