• Economic and Environmental Geology
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• v.45 no.3
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• pp.317-333
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• 2012

The Yeongweol Group is a Lower Paleozoic mixed carbonate-siliciclastic sequence in the Taebaeksan Basin of Korea, and consists of five lithologic formations: Sambangsan, Machari, Wagok, Mungok, and Yeongheung in ascending order. Sequence stratigraphic interpretation of the group indicates that initial flooding in the Yeongweol area of the Taebaeksan Basin resulted in basal siliciclastic-dominated sequences of the Sambangsan Formation during the Middle Cambrian. The accelerated sea-level rise in the late Middle to early Late Cambrian generated a mixed carbonate-siliciclastic slope or deep ramp sequence of shale, grainstone and breccia intercalations, representing the lower part of the Machari Formation. The continued rise of sea level in the Late Cambrian made substantial accommodation space and activated subtidal carbonate factory, forming carbonate-dominated subtidal platform sequence in the middle and upper parts of the Machari Formation. The overlying Wagok Formation might originally be a ramp carbonate sequence of subtidal ribbon carbonates and marls with conglomerates, deposited during the normal rise of relative sea level in the late Late Cambrian. The formation was affected by unstable dolomitization shortly after the deposition during the relative sea-level fall in the latest Cambrian or earliest Ordovician. Subsequently, it was extensively dolomitized under the deep burial diagenetic condition. During the Early Ordovician (Tremadocian), global transgression (viz. Sauk) was continued, and subtidal ramp deposition was sustained in the Yeongweol platform, forming the Mungok Formation. The formation is overlain by the peritidal carbonates of the Yeongheung Formation, and is stacked by cyclic sedimentation during the Early to Middle Ordovician (Arenigian to Caradocian). The lithologic change from subtidal ramp to peritidal facies is preserved at the uppermost part of the Mungok Formation. The transition between Sauk and Tippecanoe sequences is recognized within the middle part of the Yeongheung Formation as a minimum accommodation zone. The global eustatic fall in the earliest Middle Ordovician and the ensuing rise of relative sea level during the Darrwillian to Caradocian produced broadly-prograding peritidal carbonates of shallowing-upward cyclic successions within the Yeongheung Formation. The reconstructed relative sea-level curve of the Yeongweol platform is very similar to that of the Taebaek platform. This reveals that the Yeongweol platform experienced same tectonic movements with the Taebaek platform, and consequently that both platform sequences might be located in a body or somewhere separately in the margin of the North China platform. The significant differences in lithologic and stratigraphic successions imply that the Yeongweol platform was much far from the Taebaek platform and not associated with the Taebaek platform as a single depositional system. The Yeongweol platform was probably located in relatively open shallow marine environments, whereas the Taebaek platform was a part of the restricted embayments. During the late Paleozoic to early Mesozoic amalgamations of the Korean massifs, the Yeongweol platform was probably pushed against the Taebaek platform by the complex movement, forming fragmented platform sequences of the Taebaeksan Basin.

• Journal of the Geological Society of Korea
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• v.54 no.6
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• pp.587-603
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• 2018

3-D petroleum system modeling was performed on the Jeju Basin, offshore southern Korea to analyze the hydrocarbon migration and accumulation as well as the generation and expulsion of the hydrocarbon, based on subsurface structure maps of respective sedimentary formations. The lowermost formation deposited in Eocene time was assigned as a source rock, for which a mixed kerogen of type II and III was input in the modeling of oil and gas generation in consideration of the sedimentary environment of fluvio-lacustrine condition. Initial TOC was 4% as an input, based on the analysis of the well data and sedimentary environment. The modeling results show that a considerable amount of hydrocarbons was generated and expelled from the source rocks at the western Joint Development Zone (JDZ) sub-block 4, where the hydrocarbons was migrated to the above reservoir rocks at 20 Ma. The oil and gas in the reservoir rocks of the JDZ sub-block 4 are accumulated into the prospects with closure structures that has already been formed at the nearby areas. Another generation of hydrocarbon occurs from the source rock at the eastern border area of JDZ sub-block 1 and 2, where the expulsion of the hydrocarbons occurs at 10 Ma from the source rock into the above reservoir rocks, in which the accumulation also is expected. The generation, migration and accumulation were retarded at the eastern area of the JDZ sub-block 1 and 2, compared with the area of the western JDZ sub-block 4. Based on the modeling results, it is estimated that gases migrated laterally and vertically in long distance whereas oil migrated laterally in shorter distance than gases. A substantial amount of hydrocarbon could have seeped out of the reservoir formations to the surface since the migration of oil and gas actively occurred in Miocene time before the formation of seals. However, the modeling shows that the hydrocarbon could be accumulated smoothly into the closed structures that can be formed locally by alternation of sand and shale beds.

• Economic and Environmental Geology
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• v.55 no.1
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• pp.53-61
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• 2022

The Gasado Au-Ag deposit is located within the south-western margin of the Hanam-Jindo basin. The geology of the Gasado is composed of the late Cretaceous volcaniclastic sedimentary rocks and acidic or intermediate igneous rocks. Within the deposit area, there are a number of hydrothermal quartz and calcite veins, formed by narrow open space filling along subparallel fractures in the late Cretaceous volcaniclastic sedimentary rock. Vein mineralization at the Gasado is characterized by several textural varieties such as chalcedony, drusy, comb, bladed, crustiform and colloform. The textures have been used as exploring indicators of the epithermal deposit. Mineral paragenesis can be divided into two stages (stage I, ore-bearing quartz veins; stage II, barren carbonate veins) considering major tectonic fracturing event. Stage I, at which the precipitation of Au-Ag bearing minerals occurred, is further divided into three substages (early, middle and late) with paragenetic time based on minor fractures and discernible mineral assemblages: early, marked by deposition of pyrite and pyrrhotite with minor chalcopyrite, sphalerite and electrum; middle, characterized by introduction of electrum and base-metal sulfides with minor argentite; late, marked by argentite and native silver. Au-Ag-bearing mineralization at the Gasado deposit occurred under the condition between initial high temperatures (≥290℃) and later lower temperatures (≤130℃). Changes in stage I vein mineralogy reflect decreasing temperature and fugacity of sulfur (≈10^-10.1 to ≤10^-18.5atm) by evolution of the Gasado hydrothermal system with increasing paragenetic time. The Gasado deposit may represents an epithermal gold-silver deposit which was formed near paleo-surface.

• 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.