• Korean Journal of Soil Science and Fertilizer
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• v.27 no.3
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• pp.168-178
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• 1994

Acid sulfate soils occur extensively in Gimhae area where they have been formed from the brackish alluvial sediments along the sea coast and river estuary. The strong acid environment enhances silicate weathering and thus affects the soil clay minerals. The minerals were identified through chemical, X-ray diffraction and thermal methods. The ratio of $SiO_2$ and $Al_2O_3$ in the clay fractions ranged from 3.14 to 3.77, indicating that the distribution of the clay minerals were 1 : 1 and 2 : 1 minerals. Cation exchange capacity in the clay fractions was low due to high contents of 1 : 1 minerals and hydroxy interlayered vermiculite(HIV). The B and C horizon rich in jarosite have large amounts of yellow streaks which reflect high content of $Fe_2O_3$ and $K_2O$. Vermiculite and illite were quantified from thermogravimetry(TG), kaolin minerals from both TG and differential thermal analysis(DTA), and HIV from X-ray diffraction analysis. The dominant clay minerals were kaolin minerals, vermiculite, illite and HIV. HIV considered to be formed, especially, in acid soil environments. The minor minerals were quarts, feldspar, jarosite, pyrite, hematite and goethite. Kaolin minerals were the most abundant clay minerals throughout the acid sulfate soil. Kaolin minerals, however, increased towards the top of horizons throughout the soils and HIV decreased towards the top of horizons in the soil of Gimhae series and Haecheog series. Alteration of HIV to kaolin minerals during weathering of low pH condition in deep soil horizons may explain the high quantities of kaolin minerals and the relatively low quantities of HIV in the soil at top horizons.

• Journal of Wetlands Research
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• v.17 no.1
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• pp.26-37
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• 2015

Halophyte distribution pattern and area in the Suncheon-bay and Beolgyo estuary coastal wetlands were analyzed using KOMPSAT-2 landsat images were taken in 2008 and 2009, and field investigations were fulfilled for confirming the precise boundaries of individual halophyte areas. The salt-marsh vegetation in those areas can be classified mainly into two dominant communities: Suaeda japonica-dominant and Phragmites communis-dominant communities. In order to identify sedimentary characteristics, tidal-flat surface leveling and sedimentary facies analysis had been conducted. The sedimentary facies of marsh area are mostly silty clayey and clay facies with a little seasonal change and its slope is very gentle (0.0007~0.002 in gradient). Phragmites communis and Suaeda japonica communities were distributed in the mud-flat zone between 0.7 m and 1.8 m higher than MSL (mean sea level): zone of 1.1~1.8 m in the former and zone of 0.7~1.3 m in the latter. In the Suncheon-bay estuarine wetland, on the basis of 2009 distribution, Phragmites communis-dominant and Suaeda japonica-dominant communities are about $0.79km^2$ and $0.22km^2$ in distribution area, respectively. On the other hand, Bulgyo estuarine marsh shows that the distribution areas of Phragmites communis-dominant and Suaeda japonica-dominant communities are about $0.31km^2$ and 0.031km2 in distribution area, respectively. Individual 105 and 60 dominant community areas and their distribution patterns can be well defined and indicated in the Suncheon-bay and Bulgyo estuarine marshes, respectively. The distribution pattern and area of hylophyte communities analyzed in this study based on 2008/2009 satellite images would be valuable as a base of future monitoring of salt-marsh related studies in the study area which is the most important salt-marsh research site in Korea.

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