• Journal of the Korean Society for Railway
• /
• v.20 no.3
• /
• pp.365-373
• /
• 2017

This study proposes a newly developed dry washing method for removing pollutants such as total petroleum hydrocarbon (TPH) and oxidized iron from the surface of ballast gravel. A batch-type dry washing method showed a good performance in a previous study. In this study, a continuous-type dry washing system, instead of a batch-type system, was prepared to improve the efficiency of the system. A drier and a separator were also applied to this system as pre-treatment process, and the performance of this system was evaluated. In this experiment, blasting media was blasted on the polluted gravels through 12 nozzles by a pressure of $5-6kg/cm^2$ for 20-30 mins to remove TPH and oxidized iron. It was found to be possible to remove 80-90% of TPH and oxidized iron by using this system. Several ways to improve the performance were suggested in this study.

• Journal of Soil and Groundwater Environment
• /
• v.13 no.3
• /
• pp.8-14
• /
• 2008

The effects of surfactant types and the ratio of nonionic and anionic surfactants on the washing of diesel contaminated soil were investigated. In batch tests, the nonionic surfactant, which has HLB within 12-13, showed a high diesel removal efficiency and Tergitol 15-S-7 (T15S7) with 20 g/L concentration exhibited the highest removal efficiency of 79-88% among the tested nonionic surfactants. Anionic surfactants, in general, showed lower removal efficiency than nonionic surfactants. In case of mixed surfactant system, the removal efficiency increased with nonionic surfactant concentration. With mixed surfactants of T15S7 and SDS as 3 : 1 ratio, diesel removal was enhanced to 76% with 10 g/L of the mixed surfactants. These results could be used in the selection of proper surfactants for remediation of diesel contaminated soils.

• Clean Technology
• /
• v.25 no.2
• /
• pp.140-146
• /
• 2019

Flammable substances, such as organic solvents, are commonly used in laboratories and industrial processes. The flash point of flammable liquid mixtures is a very important parameter for characterizing the ignition and explosion hazards, and the flash points of mixtures of $C_2{\sim}C_3$ alcohols and 2,2,4-trimethylpentane were measured in the present study. The 2,2,4-trimethylpentane is an important component of gasoline and is frequently used in the petroleum industry as a solvent. Lower flash point data were measured for the binary systems {ethanol + 2,2,4-trimethylpentane}, {1-propanol + 2,2,4-trimethylpentane}, and {2-propanol + 2,2,4-trimethylpentane}. The flash point measurements were carried out according to the standard test method (ASTM D3278) using a Stanhope-Seta closed cup flash point tester. The measured flash points were compared with the predicted values calculated using Raoult's law and also following $G^E$ models: Wilson, Non-Random Two Liquid (NRTL) and UNIversal QUAsiChemical (UNIQUAC). These models were able to predict the experimental flash points for different compositions of {$C_2{\sim}C_3$ alcohols + 2,2,4-trimethylpentane} mixtures with minimal deviations. The average absolute deviation between the predicted and measured lower flash point was less than 1.28 K. A minimum flash point behaviour was observed in all of the systems as in the many observed cases for the hydrocarbon and alcohol mixtures.

• Applied Chemistry for Engineering
• /
• v.30 no.3
• /
• pp.297-302
• /
• 2019

In order to investigate structural changes of the pyrolysis fuel oil (PFO), the volatile matters and heavy oil fractions were separated from PFO by heat treatment temperature. As a result of $^1H-NMR$ analysis of volatile matters, 1~2 ring aromatic compounds contained in the petroleum residue were mostly removed at a temperature before $340^{\circ}C$. Moreover, new peaks corresponding to aliphatic hydrocarbons were detected at the chemical shift of 2.0~2.4 ppm. It is attributed that the aliphatic hydrocarbon sidechain was cracked from the aromatic compound by the cracking reaction occurred at $320^{\circ}C$. The C/H mole ratio and aromaticity increased with increasing the heat treatment temperature. Therefore, from the structural analysis results of heavy oil fractions and volatile matters from PFO, the decomposition of the aliphatic sidechain by cracking reaction and the separation of volatile matters by boiling point of components were mostly affected structure changes of the PFO.

• Journal of Soil and Groundwater Environment
• /
• v.8 no.4
• /
• pp.27-35
• /
• 2003

The study site located in an industrial complex has a Precambrian age gneiss as a bedrock. The poorly-developed, disturbed soils in the study site have loamy-textured surface soil (1 to 2 m) and gravelly sand alluvium subsurface (2 to 6 m) on the top of weathered gneiss bedrock. The depth of the groundwater table was about 3.5 m below ground surface and increased toward down-gradient of the site. The hydraulic conductivity of transmitted zone (gravelly coarse sand) was in the range of 5.0${\times}$10$\^$-2/∼1.85${\times}$10$\^$-1/ cm/sec. The fine sand layer was in the range of 1.5${\times}$10$\^$-3/ to 7.6${\times}$10$\^$-3/ cm/sec. and the reclaimed upper soil layer was less than 10$\^$-4/ cm/sec. Toluene, ethylbenzene, and xylene (TEX) was the major contaminant in the soil and groundwater. The average depth of the soil contamination was about 1.5 m in the gravelly sand alluvium layer. At the depth interval 2.4∼4.8 m, the highest contamination in the soil is located approximately 50 to 70 m from the suspected source areas. The concentration of TEX in the groundwater was highest in the suspected source area and a lesser concentration in the center and southwest parts of the site. The TEX distribution in the groundwater is associated with their distribution in the soil. Microbial isolation showed that Pseudomonas flurescence, Burkholderia cepacia, and Acinetobactor lwoffi were the dominant aerobic bacteria in the contaminated soils. The analytical results of the groundwater indicated that the concentrations of dissolved oxygen (DO), nitrate, and sulfate in the contaminated area were significantly lower than their concentrations in the none-contaminated control area. The results also indicated that groundwater at the contaminated area is under anaerobic condition and sulfate reduction is the predominant terminal electron accepting process. The total attenuation rate was 0.0017 day$\^$-1/ and the estimated first-order degradation rate constant (λ) was 0.0008 day$\^$-1/.

• The Korean Journal of Petroleum Geology
• /
• v.2 no.2 s.3
• /
• pp.51-57
• /
• 1994

Analysis of the aeromagnetic data aquired by US Navy in the year 1969 permits us to predict a new sedimentary basin, Heugsan Basin, south of the known Gunsan Basin in Block Ⅱ. The basin appears to consist of three sub-basins trending NNW-SSE. The results of our analysis provide not only an independent assessment of the Gunsan Basin, but also new important information on the tectonic origin and mechanism for the two basins as well as for the entire region. The basin forming tectonic style is interpreted as rhombochasm associated with double overstepped left-lateral wrench faults. From the magnetic evidence, a few NE-SW trending major onshore faults are extended to the study area. We also interpreted the nature of the faults to be left-lateral wrenches. This new gross structural style is consistent with the results of recent Yeongdong Basin analysis by Lee. The senses of fault movement are also supported by the paleomagnetic evidence that the Philippine Sea had experienced an 80-degree clockwise rotation since the Eocene. Based on a 2 $\frac{1}{2}$ model study the probable maximum thickness of the sediments in the Gunsan Basin is approximately 7500 meters. We believe that the new Heugsan Basin was left unidentified because a high velocity layer may be overlying the basin. Because the overall structural configuration of the Heugsan Basin appears to be favorable for hydrocarbon accumulation, a detailed airborne magnetic survey is recommended in the area in order to verify the magnetic expression of this thick basin. A detailed subsequent marine gravity survey is also recommended in order to delineate the sedimentary section and to acquire supplemental data to the magnetic method only if an overlying high velocity layer is confirmed. Otherwise a high energy source seismic survey may be more effective.

• The Korean Journal of Petroleum Geology
• /
• v.14 no.1
• /
• pp.1-11
• /
• 2008

As conventional oil and gas reservoirs become depleted, interests for oil sands has rapidly increased in the last decade. Oil sands are mixture of bitumen, water, and host sediments of sand and clay. Most oil sand is unconsolidated sand that is held together by bitumen. Bitumen has hydrocarbon in situ viscosity of >10,000 centipoises (cP) at reservoir condition and has API gravity between $8-14^{\circ}$. The largest oil sand deposits are in Alberta and Saskatchewan, Canada. The reverves are approximated at 1.7 trillion barrels of initial oil-in-place and 173 billion barrels of remaining established reserves. Alberta has a number of oil sands deposits which are grouped into three oil sand development areas - the Athabasca, Cold Lake, and Peace River, with the largest current bitumen production from Athabasca. Principal oil sands deposits consist of the McMurray Fm and Wabiskaw Mbr in Athabasca area, the Gething and Bluesky formations in Peace River area, and relatively thin multi-reservoir deposits of McMurray, Clearwater, and Grand Rapid formations in Cold Lake area. The reservoir sediments were deposited in the foreland basin (Western Canada Sedimentary Basin) formed by collision between the Pacific and North America plates and the subsequent thrusting movements in the Mesozoic. The deposits are underlain by basement rocks of Paleozoic carbonates with highly variable topography. The oil sands deposits were formed during the Early Cretaceous transgression which occurred along the Cretaceous Interior Seaway in North America. The oil-sands-hosting McMurray and Wabiskaw deposits in the Athabasca area consist of the lower fluvial and the upper estuarine-offshore sediments, reflecting the broad and overall transgression. The deposits are characterized by facies heterogeneity of channelized reservoir sands and non-reservoir muds. Main reservoir bodies of the McMurray Formation are fluvial and estuarine channel-point bar complexes which are interbedded with fine-grained deposits formed in floodplain, tidal flat, and estuarine bay. The Wabiskaw deposits (basal member of the Clearwater Formation) commonly comprise sheet-shaped offshore muds and sands, but occasionally show deep-incision into the McMurray deposits, forming channelized reservoir sand bodies of oil sands. In Canada, bitumen of oil sands deposits is produced by surface mining or in-situ thermal recovery processes. Bitumen sands recovered by surface mining are changed into synthetic crude oil through extraction and upgrading processes. On the other hand, bitumen produced by in-situ thermal recovery is transported to refinery only through bitumen blending process. The in-situ thermal recovery technology is represented by Steam-Assisted Gravity Drainage and Cyclic Steam Stimulation. These technologies are based on steam injection into bitumen sand reservoirs for increase in reservoir in-situ temperature and in bitumen mobility. In oil sands reservoirs, efficiency for steam propagation is controlled mainly by reservoir geology. Accordingly, understanding of geological factors and characteristics of oil sands reservoir deposits is prerequisite for well-designed development planning and effective bitumen production. As significant geological factors and characteristics in oil sands reservoir deposits, this study suggests (1) pay of bitumen sands and connectivity, (2) bitumen content and saturation, (3) geologic structure, (4) distribution of mud baffles and plugs, (5) thickness and lateral continuity of mud interbeds, (6) distribution of water-saturated sands, (7) distribution of gas-saturated sands, (8) direction of lateral accretion of point bar, (9) distribution of diagenetic layers and nodules, and (10) texture and fabric change within reservoir sand body.

• The Korean Journal of Petroleum Geology
• /
• v.8 no.1_2 s.9
• /
• pp.1-43
• /
• 2000

A comparison study for understanding a stratigraphic response to tectonic evolution of sedimentary basins in the Yellow Sea and adjacent areas was carried out by using an integrated stratigraphic technology. As an interim result, we propose a stratigraphic framework that allows temporal and spatial correlation of the sedimentary successions in the basins. This stratigraphic framework will use as a new stratigraphic paradigm for hydrocarbon exploration in the Yellow Sea and adjacent areas. Integrated stratigraphic analysis in conjunction with sequence-keyed biostratigraphy allows us to define nine stratigraphic units in the basins: Cambro-Ordovician, Carboniferous-Triassic, early to middle Jurassic, late Jurassic-early Cretaceous, late Cretaceous, Paleocene-Eocene, Oligocene, early Miocene, and middle Miocene-Pliocene. They are tectono-stratigraphic units that provide time-sliced information on basin-forming tectonics, sedimentation, and basin-modifying tectonics of sedimentary basins in the Yellow Sea and adjacent area. In the Paleozoic, the South Yellow Sea basin was initiated as a marginal sag basin in the northern margin of the South China Block. Siliciclastic and carbonate sediments were deposited in the basin, showing cyclic fashions due to relative sea-level fluctuations. During the Devonian, however, the basin was once uplifted and deformed due to the Caledonian Orogeny, which resulted in an unconformity between the Cambro-Ordovician and the Carboniferous-Triassic units. The second orogenic event, Indosinian Orogeny, occurred in the late Permian-late Triassic, when the North China block began to collide with the South China block. Collision of the North and South China blocks produced the Qinling-Dabie-Sulu-Imjin foldbelts and led to the uplift and deformation of the Paleozoic strata. Subsequent rapid subsidence of the foreland parallel to the foldbelts formed the Bohai and the West Korean Bay basins where infilled with the early to middle Jurassic molasse sediments. Also Piggyback basins locally developed along the thrust. The later intensive Yanshanian (first) Orogeny modified these foreland and Piggyback basins in the late Jurassic. The South Yellow Sea basin, however, was likely to be a continental interior sag basin during the early to middle Jurassic. The early to middle Jurassic unit in the South Yellow Sea basin is characterized by fluvial to lacustrine sandstone and shale with a thick basal quartz conglomerate that contains well-sorted and well-rounded gravels. Meanwhile, the Tan-Lu fault system underwent a sinistrai strike-slip wrench movement in the late Triassic and continued into the Jurassic and Cretaceous until the early Tertiary. In the late Jurassic, development of second- or third-order wrench faults along the Tan-Lu fault system probably initiated a series of small-scale strike-slip extensional basins. Continued sinistral movement of the Tan-Lu fault until the late Eocene caused a megashear in the South Yellow Sea basin, forming a large-scale pull-apart basin. However, the Bohai basin was uplifted and severely modified during this period. h pronounced Yanshanian Orogeny (second and third) was marked by the unconformity between the early Cretaceous and late Eocene in the Bohai basin. In the late Eocene, the Indian Plate began to collide with the Eurasian Plate, forming a megasuture zone. This orogenic event, namely the Himalayan Orogeny, was probably responsible for the change of motion of the Tan-Lu fault system from left-lateral to right-lateral. The right-lateral strike-slip movement of the Tan-Lu fault caused the tectonic inversion of the South Yellow Sea basin and the pull-apart opening of the Bohai basin. Thus, the Oligocene was the main period of sedimentation in the Bohai basin as well as severe tectonic modification of the South Yellow Sea basin. After the Oligocene, the Yellow Sea and Bohai basins have maintained thermal subsidence up to the present with short periods of marine transgressions extending into the land part of the present basins.

• 한국석유지질학회:학술대회논문집
• /
• autumn
• /
• pp.28-46
• /
• 2001

Natural gas is a mixture of hydrocarbon gases and impurities such as nitrogen, hydrogen sulfide, and carbon dioxide and a clean energy producing no pollution materials for combustion. Currently, the demand of the natural gas is rapidly increasing due to worldwide environmental problems. According to Hubbert's study in the past, the natural gas was predicted as rapidly depleted resources, and then the results led to high gas price and limitation of usage during 1980s. Afterward, the study of natural gas resources based on geology identified the additional natural gas resources that were not considered in Hubbert's study. They are unconventional gas, additional resources in the existed reservoirs, and natural gas in deep subsurface areas. Such additional resouces made the future of natural gas bright and pormised low and stable gas price in the future. Deep natural gas is defined as the gas existing at or below 15,000ft$(4,752{\cal}m)$ in depth from the surface. According to the study from the U.S. Geological Survey(USGS) in 1995, 1,412 TCF of technically recoverable natural gas was remained to be discovered or developed in the onshore of United States. A significant part of that resource base, 114 TCF, exists at deep sedimentary basins, and it shows wide distribution with various geological environments. In 1995, the deep gas contributed to $6.7\% of total supply amount of natural gas in the United States and is expected to be $18.7\% by 201.5. However, the development of the deep gas is a high risky business due to expensive investment and high portion of dry holes, although it is developed. Thus, for developing the deep gas economically, it is necessary to overcome many technical challenges. In this paper, for increasing success rate of the deep gas, 1) geologic and compositional characteristics, and production cost have been analyzed according to depth, 2) technical problems related to deep gas production have been summarized, and 3) finally future study areas for increasing application of the deep gas have been suggested. For reference, this paper was written based on the study results from USGS and Gas Research Institute(GRI), for the United States is doing the most active R&D in the deep gas area, and thus, has many reliable data.

• Journal of Korean Society of Environmental Engineers
• /
• v.33 no.4
• /
• pp.267-274
• /
• 2011

The environmental impacts of 95% remediation of a total petroleum hydrocarbon-contaminated soil were evaluated using life cycle assessment (LCA). LCA of two remediation systems, soil vapor extraction (SVE) and biopile, were conducted by using imput materials and energy listed in a remedial system standardization report. Life cycle impact assessment (LCIA) results showed that the environmental impacts of SVE were all higher than those of biopile. Prominent four environmental impacts, human toxicity via soil, aquatic ecotoxicity, human toxicity via surface water and human toxicity via air, were apparently found from the LCIA results of the both remedial systems. Human toxicity via soil was the prominent impact of SVE, while aquatic ecotoxicity was the prominent impact of biopile. This study also showed that the operation stage and the activated carbon replacement stage contributed 60% and 36% of the environmental impacts of SVE system, respectively. The major input affecting the environmental impact of SVE was electricity. The operation stage of biopile resulted in the highest contribution to the entire environmental impact. The key input affecting the environmental impact of biopile was also electricity. This study suggested that electricity reduction strategies would be tried in the contaminated-soil remediation sites for archieving less environmental impacts. Remediation of contaminated soil normally takes long time and thus requires a great deal of material and energy. More extensive life cycle researches on remedial systems are required to meet recent national challenges toward carbon dioxide reduction and green growth. Furthermore, systematic information on electricity use of remedial systems should be collected for the reliable assessment of environmental impacts and carbon dioxide emissions during soil remediation.