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The significantly different geological processes experienced by the shales in the southern Sichuan Basin provide a means for comparing their pore characteristics and their supercritical m...

The effect of clay minerals on the methane adsorption capacity of shales is a basic issue that needs to be clarified and is of great significance for understanding the adsorption characteristics and mechanisms of shale gas. In this study, a variety of experimental methods, including XRD, LTNA, HPMA experiments, were conducted on 82 marine shale samples from the Wufeng–Longmaxi Formation of 10 evaluation wells in the southern Sichuan Basin of China. The controlling factors of adsorption capacities were determined through a correlation analysis with pore characteristics and mineral composition. In terms of mineral composition, organic matter (OM) is the most key methane adsorbent in marine shale, and clay minerals have little effect on methane adsorption. The ultra-low adsorption capacity of illite and chlorite and the hydrophilicity and water absorption ability of clay minerals are the main reasons for their limited effect on gas adsorption in marine shales. From the perspective of the pore structure, the micropore and mesopore specific surface areas (SSAs) control the methane adsorption capacity of marine shales, which are mainly provided by OM. Clay minerals have no relationship with SSAs, regardless of mesopores or micropores. In the competitive adsorption process of OM and clay minerals, OM has an absolute advantage. Clay minerals become carriers for water absorption, due to their interlayer polarity and water wettability. Based on the analysis of a large number of experimental datasets, this study clarified the key problem of whether clay minerals in marine shales control methane adsorption.

The chemical and stable isotopic compositions of 24 gas samples were investigated to determine the geochemistry and accumulation process of the Shenmu Gas Field (SGF), Ordos Basin, central China. Natural gas of the SGF includes both wet and dry gas with dryness coefficients (C1/C1−5) between 0.907 and 0.958. δ13C1 and δD1 values range from −39.4‰ to −35.6‰ and −191‰ to −201‰, respectively, displaying a positive isotopic series. Geochemical characteristics indicate that gases of the upper Paleozoic reservoirs of the SGF are typical coal-type gas, whereas gases of the lower Paleozoic reservoirs are primarily oil-type gas (occasionally containing a small proportion of coal-type gas). Gas-source correlation demonstrates that gases of the upper Paleozoic reservoirs of the SGF display near-source accumulation, primarily derived from the underlying Carboniferous–Permian humic source rocks, while gases of the lower Paleozoic reservoirs in the SGF are mainly sourced from the carbonate Majiagou Formation (O1m). SGF reservoirs were generally tight prior to gas accumulation. Integrated with the maturation process of source rocks, the accumulation process of gas in the SGF could be separated into four stages: prenatal (before early Jurassic), development (early–late Jurassic), prime (early Cretaceous), and formative (late Cretaceous–present).

Recent significant breakthroughs have been made of the Lower Silurian shale gas in the Changning-Zhaotong blocks recently, the key exploration area of China. Through comparative research of the gas geochemistry, Longmaxi Formation shale gas is mainly composed of methane (98.8%), with extremely low wetness coefficient (0.49%), and possesses negligible quantities of ethane and propane. The Non-hydrocarbon gases are mainly composed of small-scale quantities of N2 and CO2 of mixed origin. Enriched δ13C1 (from −29.4‰ to −26.7‰) and δ13C2 (from −34.5‰ to −31.6‰) values, together with sapropelic organic matter, indicate a typical overmature oil-type gas. Abnormal geochemical characteristics of shale gas (δ13C1 > δ13C2 > δ13C3) result from merged secondary impacts in the high-maturity and well-confined shale reservoirs, like the mixing of secondary cracking gases, Rayleigh fractionation of C2 when transition metals and water undergo redox reactions. Notable geographic variation can also be observed, as the δ13C1 and δ13C2 values of the Longmaxi Formation become more positive toward the thrust-faulted folds developed in the southern CZ blocks.

We found for the first time enriched liquid mercury beads in a thermal simulation experiment on humic kerogen extracted from coal, which provided some kind of direct evidence that mercury can be re...

Sha Yang,* Yun Yang,* Sixin Cui, Ziqi Feng, Yuzhi Du, Zhen Song, Yanan Tong, Liuyang Yang, Zelin Wang, Hao Zeng, Quanming Zou, Hongwu Sun National Engineering Research Center of Immunological Products & Department of Microbiology and Biochemical Pharmacy, College of Pharmacy, Third Military Medical University of Chinese PLA, Chongqing, 400038, People’s Republic of China *These authors contributed equally to this work Introduction: Methicillin-resistant Staphylococcus aureus (MRSA) is one of the most predominant and fatal pathogens at wound infection sites. MRSA is difficult to treat because of its antibiotic resistance and ability to form biofilms at the wound site. Methods: In this study, a novel nanoscale liquid film-forming system (LFFS) loaded with benzalkonium bromide was produced based on polyvinyl alcohol and chitosan. Results: This LFFS showed a faster and more potent effect against MRSA252 than benzalkonium bromide aqueous solution both in vitro and invivo. Additionally, the LFFS had a stronger ability to destroy biofilms (5 mg/mL) and inhibit their formation (1.33 µg/mL). The LFFS inflicted obvious damage to the structure and integrity of MRSA cell membranes and caused increases in the release of alkaline phosphate and lactate dehydrogenase in the relative electrical conductivity and in K+ and Mg2+ concentrations due to changes in the MRSA cell membrane permeability. Conclusion: The novel LFFS is promising as an effective system for disinfectant delivery and for application in the treatment of MRSA wound infections. Keywords: liquid film-forming system, methicillin-resistant Staphylococcus aureus, wound healing, antibiofilm, antibacterial

Recently, shale-gas exploration in the Lower Silurian has been conducted in the Weiyuan area, southwestern Sichuan Basin, which has a special symbolic significance for the development of shale gas in China. According to the first systematic analysis of its geochemical characteristics, methane accounts for the vast majority (95.7%) of the Longmaxi Formation shale gas in the Weiyuan area, with extremely low wetness (C2–3/C1–3%) of 0.57%. Non-hydrocarbon gases consist of small amounts of N2 and inorganic-induced CO2. The δ13C-CH4 values of shale gas range from −36.9‰ to −34.0‰, and the δ13C-C2H6 values range from −42.8‰ to −37.5‰, indicating that the gases originate from sapropelic kerogen. A reversal in carbon-isotopic composition, i.e., δ13C-CH4 > δ13C-C2H6 > δ13C-C3H8, results from combined secondary effects such as secondary cracking and diffusion under extremely high thermal maturity. Geologic features of organic-rich shale and secondary effects at the overmature stage together lead to differences in geochemical characteristics of shale gas in the Weiyuan and Changning and Fuling (CF) areas, which can be used to indicate the distribution of geochemical parameters and predict shale-gas production.

The graptolitic shale of the Wufeng–Longmaxi Formations is widely deposited across the Ordovician and Silurian transition in South China, which is the target of shale gas exploration and development within China. The contribution of graptolites to organic enrichment and reservoir of gas shale is discussed below based on the statistics of nearly 1000 shale samples from the Wufeng Formation and the bottom part of the Longmaxi Formation in the southern and northern margins of the Yangtze plate. The assessment involves graptolites abundance, the total organic carbon (TOC) content analyses, and the different scales of scanning electron microscopy analyses of related samples. The TOC content of the Wufeng–Longmaxi graptolitic shales (including graptolites and non-graptolites, i.e., the host shale) is mainly controlled by that of its host shale, while less affected by the graptolites abundance, indicating that the graptolites barely influence the organic enrichment. Graptolites consist of a large number of organic matter with reticular biological tissue structure; they account for 20%–50% of the graptolitic area. The aforementioned also developed honeycomb-shaped pores with pore sizes ranging 110 nm-1.7 μm (an average of about 500 nm), which are higher than those of the organic pores in the host shale (108–770 nm, average 330 nm), proving that graptolites have an important contribution to shale gas storage space. Since there are a large number of graptolites within the shales from the Wufeng Formation and the bottom part of the Longmaxi Formation, the laminated and stacked local pattern of their distribution provides abundant storage space for shale gas. Moreover, the feature also serves as the predominant channel for shale gas flow. Therefore, the widely developed graptolites should be considered as one of the essential factors controlling enrichment and high productivity of shale gas in the Wufeng–Longmaxi Formations. Keywords: Shale gas, Graptolites, Longmaxi formation, Organic pore, Organic enrichment, Reservoir, Sichuan basin

Chemical components, stable isotopic compositions and light hydrocarbons are investigated to determine the origin and isotopic anomalies of natural gases in the Paleogene of the Liaohe Basin of northeastern China. Natural gas in Paleogene is dominated by alkanes. Dry gas predominantly occurs in the shallow layers of the Paleogene having burial depth less than 1900 m, specifically in the Dongying Formation (E3d) and the first member of the Shahejie Formation (E3s1); wet gas mostly occurs in the deep layer, primarily in the third member of the Shahejie Formation (E2s3). The relative content of methyl cyclohexane in the Western Depression (WD) of the Liaohe Basin is less than that in the Eastern Depression (ED), while the relative contents of alkanes in the C5-7 light hydrocarbons of the WD are higher than those of the ED. Natural gases are of multiple origins, including microbial gas (gas generated by microbial action on immature source rock), coal-derived gas (gas generated by humic source rock) and oil-associated gas (gas generated by sapropelic source rock). In the WD, oil-associated gas is dominant, while in the ED, coal-derived gas dominates. The abnormally heavy carbon isotopic composition of Paleogene heavy alkanes is primarily caused by bacteria oxidation, rather than by being mixed with deep source gas. Natural gases from the E3d and E3s1 suffer the most severe bacterial oxidation, the intensity of which gradually declines with the increasing depth. The low average heptane and isoheptane values indicate that natural gases are mostly generated in the early mature stage of the source rock. Natural gases in E2s3 of the WD are mainly derived from E2s4 and E2s3 source rocks, while those of E3d and E3s1 are predominantly generated by E2s3 source rock. Gases in the ED come principally from E2s3 source rock.

According to the compositional and isotopic analyses of He, CO 2 and CH 4 of 95 gas samples from the Ordos Basin and 76 gas samples from the Bohaibay Basin in China, this study carried out a detailed investigation on the geochemical characteristics of helium and CO 2 from the cratonic and rift basins, especially the cratonic Ordos Basin and rift Bohaibai Basin in China. Compared to the rift Bohaibay Basin, the cratonic Ordos Basin has lower level of helium and CO 2 , lower R/Ra ratio and lower δ 13 C CO2 maximum value. When the content of CO 2 is 2 associated with the hydrocarbon generation process and inorganic CO 2 from the thermal decomposition of carbonates or dissolution of organic acid. Rift basin can also have CO 2 > 20% and δ 13 C CO2 of − 6 ± 2‰ or − 4‰ –− 9‰, which is of volcanic-magmatic or mantle-derived origin, while cratonic basin has no such type of CO 2 . The cratonic basins (Ordos, Sichuan) have CO 2 13 C CO2 , i.e., 25.6‰ (− 0.8‰ –− 26.4‰). The rift basins have higher level of CO 2 , R/Ra ratios and δ 13 C CO2 values. The content of CO 2 can reach 100%, the R/Ra ratio can be up to 6.45 and the variation range of δ 13 C CO2 is 34‰ (7‰ –− 27‰). Bigger variation range of δ 13 C CO2 implies stronger tectonic activities, which is not favorable for the gas accumulation. While smaller variation range means more stable structure, which is favorable for the discovery of large gas fields. Sample in the cratonic basin in China generally has CH 4 / 3 He of 10 9 – 10 12 and R/Ra 4 / 3 He of 10 5 – 10 13 and R/Ra of 0.1– 6.45. It is concluded that methane with CH 4 / 3 He ≤ 10 8 is of inorganic origin and methane with CH 4 / 3 He ≥ 10 11 is of organic origin. The regression equation for the CH 4 / 3 He-R/Ra in the cratonic basin is: y = 3E + 11e − 46.28x and it is: y = 4E + 10e − 1.791x in the rift basin. Both Ordos and Bohaibay basins found gas wells with He > 0.05%, which has significant commercial values and provides a clue for the exploration of helium-rich gas fields. Traps with R/Ra > 2 is a favorable clue for the discovery of CO 2 gas fields. Seven CO 2 gas fields have been found in the Bohaibay Basin, but no systematic development has been carried out and only some liquid CO 2 has been injected for tight oil from the Huagou CO 2 gas field.

The carbon isotope ratios of individual light hydrocarbons and the n-alkanes of twenty-one condensates from the Tarim Basin, as well as 47 condensates and oils from other petroliferous basins (Ordos Basin, Sichuan Basin, Turpan-Harmi Basin, Qiongdongnan Basin, Beibu Gulf Basin and Bohai Bay Basin) in China, were analyzed. We investigated the oilâoil correlation, the effects of gas washing and maturity, as well as the distinguishing parameters of humic and sapropelic condensates, and have come to the following conclusion. The carbon isotopic patterns of condensates and oils in the Ordovician strata of Tarim Basin are very similar, indicating they originate from the same type of source rocks. The condensates from Dawanqi oil field and Yinan 2, as well as Ti'ergen and Yitikelike gas fields, have similar carbon isotopic patterns. Thus, they probably have originated from the same terrestrial Jurassic source rock. The carbon isotopic patterns of the condensates from the Dabei, Kela 2, and Keshen gas fields are also similar, indicating they are of the same oil family and sourced from the Triassic and Jurassic terrestrial source rock. The carbon isotopic ratios of 2-MP, 3-MP, 3-MH, and nC5-8 are much more susceptible to maturity level than other light hydrocarbons. Gas washing has minor effects on the δ13C compositions of individual light hydrocarbons and n-alkanes, although it causes  â25â°, δ13CCH > â24â°, δ13CMCH > â24â°, δ13Cbenzene > â25â°, and δ13Ctoluene > â24â°, whereas sapropelic condensates mainly have δ13CMCPÂ

The molecular and isotopic (C and H) compositions of Paleogene [Shahejie Formation (E 2–3 s) and Dongying Formation (E 3 d)] natural gases from 11 new gas samples as well as the data of 71 gases published from previous studies in the Liaohe Basin were analyzed, and the results were considered in combination with geochemical and distribution characteristics of the source rocks. The genetic type, gas–source correlation and secondary alteration of the natural gases were studied in detail, and the source rock maturities of the gases were estimated. The following conclusions were reached: (1) with the exception of dry gases in the major part of the third member of the Shahejie Fm. (E 2 s 3 ) reservoirs, the gases in other reservoirs are mainly wet; (2) variable carbon and hydrogen isotopes of the alkane gases are observed in different reservoirs of the basin with δ 13 C 1 values ranging from − 60.7‰ to − 34.2‰, δ 13 C 2 from − 47.3‰ to − 22.3‰, δ 2 H CH 4 from − 261‰ to − 188‰, and δ 2 H C 2 H 6 from − 269‰ to − 148‰; (3) the natural gases of the basin are of multiple origins, and mixing of thermogenic and microbial is observed — the mixing ratio in the first member of the Shahejie Fm. (E 3 s 1 ) is the highest among all the reservoirs; (4) gases of different reservoirs suffered varying extents of biodegradation, which caused partial reversal of the carbon isotope series of methane and its homologues (δ 13 C 1 13 C 2 13 C 3 > δ 13 C 4 ); the reversal of the gases in the shallow reservoirs (E 3 s 1 and E 3 d) is greater, while those in the deep reservoir (E 2 s 3 ) is less; (5) humic natural gases of the ED were mainly generated by source rocks at early maturity, while the sapropelic ones of the ED and WD were generated during the mature and high mature stages; (6) both the source rocks of E 2 s 3 and E 2 s 4 strata could contribute to the gas reservoirs of E 2 s 3 and E 2 s 1 in the west depression. Sapropelic gases in east depression were generated by E 2 s 3 source rocks, while the other gases reservoired in the E 2 s 3 , E 3 s 1 , and E 3 d strata are probably sourced from the source rock strata of E 2 s 3 and E 3 s 1–2 .

This paper focuses on Longmaxi shale gas geochemistry and carbon isotopic reversal in Changning and Fuling gas fields through comparative study of shale gas composition and carbon and hydrogen isotopes in North America and Changning and Fuling gas fields. Longmaxi shale gas in Changning and Fuling gas fields exhibits the features of dry gas. Specifically, the average methane (CH4) content is 98.72 and 98.17%, respectively. The humidity is less than 0.5%. Nonhydrocarbon gases include a small amount of CO2 and N2. Extremely heavy δ13C1 value, average δ13C2 value of −33.3 and −34.6‰ for Changning and Fuling, and sapropelic organic matter indicate the properties of petroliferous dry gas. Carbon isotopic reversal, i.e. δ13C1>δ13C2>δ13C3, may be caused by combined secondary effects at high maturity and high geotemperature. The reversal may also be related to ethane Rayleigh fractionation and late methane generation by water and transition metals reaction. Geologic setting in these two gas fields may have an impact on carbon isotopes distribution.

This study performed a detailed geochemical analyses of the components, stable carbon isotopes of alkane gas and CO2, stable hydrogen isotopes of alkane gas and helium isotopes of reproducing gas from the largest tight gas field (Sulige) and shale gas (Fuling) field in China. The comparative study shows that tight gas from the Sulige gas field in the Ordos Basin is of coal-derived origin, which is characterized by a positive carbon and hydrogen isotopic distribution pattern (δ13C1 > δ13C2 > δ13C3 > δ13C4; δ2H1 > δ2H2 > δ2H3), i.e., the carbon and hydrogen isotopes increase with increasing carbon numbers. Carbon dioxide from this field are of biogenic origin and the helium is crust-derived. Shale gas from the Fuling shale gas field belongs to oil-derived gas which has complete carbon and hydrogen isotopic reversal of secondary alteration origin (δ13C1

The Yan’an gas field in the Ordos Basin, China, was discovered in 2014 and contains reserves of up to 100 billion m3. Its occurrence in the basin contradicts the distribution model of “gas in the north, oil in the south”. Upper Paleozoic natural gas in the Yan’an area is dominated by methane, with an average dryness coefficient (C1/C1–4, %) of 99.5% (δ13C1 = −30.8 to −27.5‰), with minor amounts of CO2 = 3.8%, N2 = 0.5%, and ethane (δ13C2 = −37.2 to −30.5‰) and traces of higher hydrocarbons. The gas is predominantly coal-derived originating from Carboniferous–Permian humic hydrocarbon source rocks and minor oil-type gas from sapropelic source rocks. The carbon isotope series includes reversals, with δ13C2

As a new expansion area for natural gas exploration, the Yichuan-Huanglong area improves the complete evolutionary sequence of the Paleozoic natural gas in the eastern part of the Ordos Basin, but the geochemical characteristics and the late gas generation processes involved have not been discussed. By collecting and analyzing gas samples from existing wells, the following insights were obtained. The alkane components had a dichotic characteristic, the wetness of the O1m5–C2b natural gas (average: 3.85%) was relatively higher than that of the Permian natural gas (average: 0.88%). The carbon isotopic compositions exhibited partial reversal (δ13C-CH4 >δ13C-C2H6), and the Permian natural gas from the coal-measure strata had abnormally low δ13C-C2H6 values (

A comprehensive analysis was carried out on the geochemical characteristics of 15 shale gas samples from the Changning area to study the carbon isotopic composition features of shale gas and the reversal cause of carbon isotopic composition in post-mature shale gas in the Silurian Longmaxi Formation of the Changning area, Sichuan Basin. Through the analysis of alkane gas component and carbon isotopic composition, combining with the research on carbon isotopic composition from the Longmaxi Formation of the Fuling and Weiyuan areas in Sichuan Basin, the methane from the Longmaxi Formation shale gas accounts for 97.11% to 99.45%, the average gas wetness is 0.49% representing typical dry gas, abnormal average δ13C1 value as −28.2‰ and the average of δ13C2 values is −33.2‰, in view of sapropel-type kerogen, the Longmaxi Formation shale gas belongs to the typical oil-associated gas. With the increasing degree of thermal evolution, the wetness of shale gas decreases gradually, and carbon isotopic composition of methane becomes heavier, and the carbon isotopic composition of ethane and propane will reverse, but the carbon isotopic composition of ethane and propane in the post-mature shale gas of the Changning area stays in the post-stage of reverse and will not get continuously heavier. The abnormal heavy carbon isotopic composition of methane and the reversal phenomenon of carbon isotopic (δ13C1>δ13C2>δ13C3) mainly generate from the secondary cracking effect in the post-mature stage and reactions between ethane with ferrous metals and water under Reileigh fractionation situation. Furthermore, the high temperature is also one of the important influence factors. Key words: Sichuan Basin, Changning area, Silurian Longmaxi Formation, shale gas, carbon isotope

Based on the geochemical characteristics of Lower Paleozoic gases from 154 most recently drilled wells and their genetic type, in combination with the organic abundance evaluation of 733 core samples from the Lower Paleozoic, the origin of Lower Paleozoic gases in Ordos Basin was discussed. According to the carbon isotope data of paraffin gases in the gas samples and the geological background, the Lower Paleozoic gases are divided into three types and four sub-types: (1) the coal-derived gas generated from the Upper Paleozoic coaly source rock; (2) the oil-associated gas sourced from the Lower Paleozoic source rock, and (3) the mixing gas originated from the Upper Paleozoic coaly source rock and Paleozoic limestone, and the mixing gas can be divided into two sub-types, the mixing gas of positive carbon isotopic series and that of negative carbon isotopic series. From the TOC and organic maceral results of Lower Paleozoic source rock, the samples below salt have an average TOC of 0.3%, with 28.2% of them having TOC>0.4%, the kerogen type being sapropel type, showing great gas generating potential. The Lower Paleozoic gases are primarily coal-derived gas generated from the Upper Paleozoic coal, some oil-associated gas of self-source and self-reservoir can be found in pre-salt reservoirs in the central-eastern basin, where the developed source rock can serve as the source of some Lower Paleozoic gas. Key words: Ordos Basin, Lower Paleozoic, natural gas origin, source rock

The carbon isotopic series of alkane gases were divided into three types: (1) positive carbon isotopic series: δ 13 C values increased with increasing carbon numbers among the C 1 –C 4 alkanes, which is a typical characteristic for primary alkane gases; (2) negative carbon isotopic series: δ 13 C values decreased with increasing carbon numbers among the C 1 –C 4 alkanes; and (3) partial carbon isotopic reversal, which had no increasing or decreasing relationship between the δ 13 C values and carbon numbers. Negative carbon isotopic series were further divided into primary and secondary origins. The primary is a typical characteristic of abiogenic gases, while the secondary is a result of the secondary alteration imposed on biogenic gases usually observed in over-mature shale gas and coal-derived gas. Previous research has proposed several possible explanations for negative carbon isotopic series of secondary origin, such as secondary cracking, diffusion, and the Rayleigh fractionation of ethane and propane through redox reaction with the participation of transition metal and water at 250–300 °C. After a comparative study, the authors found that the negative carbon isotopic series of secondary origin for both shale gas and coal-derived gas appeared in areas where source rocks (shales) were at an over-mature stage, but not in areas where source rocks (shales) were only at a high-maturity stage. As a result, high maturity (>200 °C) was the main controlling factor for the occurrence of negative carbon isotopic series of secondary origin in thermogenic gases. Within this maturity interval, secondary cracking, diffusion, and Rayleigh fractionation of ethane and propane could happen separately or together.

The Carboniferous–Permian coal beds in the Ordos Basin of central China are generally considered the source of gas found in upper Paleozoic reservoirs. However, the coal beds consist of both coal and coaly mudstone, each with a different distribution and potential for hydrocarbon generation. The ability to distinguish the gases generated by each type of source rock is critical for further petroleum exploration. In this study we integrated several light hydrocarbon indices (e.g., the Halpern C7OCSD, the K2) with carbon and hydrogen isotopes and the distribution of sedimentary facies in order to distinguish the coal-generated gases from the mudstone-generated gases. The differences in the light hydrocarbon contents of the coal and the coaly mudstone relate to the depositional environment, where the coal was deposited on a delta plain and the mudstone was deposited along the delta front. This paper presents a method for accurate gas–source correlation and its integration with sedimentary facies and depositional environment, for improved prediction and exploration of petroleum systems.

To verify recent single-well data from the Sichuan Basin, we analyzed the molecular and isotopic composition of late-mature Longmaxi shale gases from the southwestern portion of the Fuling block. The gases are highly enriched in methane (>96.1%) and have low C2+ hydrocarbon contents (

s This study aimed to improve the solubility, reduce the side effects and enhance the efficacy of gambogic acid against acute myeloid leukemia in vitro and in vivo. This oil-in-water nanoemulsion (average size 17.20 ± 0.11 nm, zeta potential 4.17 ± 0.82 mV) containing Tween-80, glycol, squalene and gambogic acid with improving 4000 times solubility was prepared by pseudoternary phase diagrams. We found that this nanoemulsion successfully encapsulated gambogic acid; it was stable and showed an obvious delayed release effect for the drug in three different phosphate-buffered saline (pH = 2.0, 5.8 and 7.4). The half inhibiting concentration (IC50) of this nanoemulsion (480.7 μg/mL and 408 μg/mL) were 1.67 times and 1.98 times higher than those of its water solution (287 μg/mL and 206 μg/mL) after acting on the toxicity standard cell line (L929 line) for 24 h and 48 h, respectively. Importantly, acute injection toxicity indicated that the half lethal dose (LD50) of this nanoemulsion (23.25 mg/kg, 95% LD50, 21.7–25.16 mg/kg) was 1.26 times higher than that of its water solution (18.59 mg/kg, 95% LD50, 16.84–20.53 mg/kg). Compared with its suspension, the bioavailability of this nanoemulsion was 318.2%. Furthermore, this nanoemulsion had a better efficacy against the acute myeloid leukemia in vitro and in vivo by improving the time and percent of survival (MV4-11 engrafts mice) and reducing half inhibiting concentration values in acute myeloid leukemia such as Jurket, HL-60 and MV4-11 cells. Our studies suggested that this nanoemulsion may be a promising therapeutic medicine for acute myeloid leukemia.