• Economic and Environmental Geology
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• v.54 no.1
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• pp.69-76
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• 2021

This study is to identify the mineralogical properties of caprock samples from drilling cores of the Pohang basin, which is the research area for the demonstration-scale CO2 storage project in Korea. The interaction of water-rock-gas that can occur due to CO2 injection was identified using geochemical modeling. Results of mineralogical studies, together with petrographic data of caprock and data on the physicochemical parameters of pore water were used for geochemical modeling. Modelling was carried out using the The Geochemist's Workbench 14.0.1 geochemical simulator. Two steps of modeling enabled prediction of immediate changes in the caprocks impacted by the first stage of CO2 injection and the assessment of long-term effects of sequestration. Results of minerlaogical analysis showed that the caprock samples are mainly composed of quartz, K-feldspar, plagioclase and a small amount of pyrite, calcite, kaolinite and montmollonite. After the injection of carbon dioxide, the porosity of the caprock increased due to the dissolution of calcite, and dawsonite and chalcedony were precipitated as a result of the dissolution of albite and k-feldspar. In the second step after the injection was completed, the precipitation of dawsonite and chalcedony occurred as a result of dissolution of calcite and albite, and the pH was increased due to this reaction. Results of these studies are expected to be used as data to quantitatively evaluate the efficiency of mineral trapping capture in long-term storage of carbon dioxide.

• Economic and Environmental Geology
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• v.49 no.5
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• pp.371-380
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• 2016

This study aims to identify the mineraloical and petrographical characteristics of caprock from drilling cores of Pohang basin as a potential $CO_2$ storage site. Experiments and modeling were conducted in order to investigate the geochemical and mineralogical caprock effects of carbon dioxide. A series of autoclave experiments were conducted to simulate the interaction in the $scCO_2$-caprock-brine using a high pressure and temperature cell at $50^{\circ}C$ and 100 bar. Geochemical and mineralogical alterations after 15 days of $scCO_2$-caprock-brine sample reactions were quantitatively examined by XRD, XRF, ICP-OES investigation. Results of mineralogical studies, together with petrographic data of caprock and data on the physicochemical parameters of brine were used for geochemical modeling. Modelling was carried out using the The Geochemist's Workbench 11.0.4 geochemical simulator. Results from XRD analysis for caprock sample showed that major compositional minerals are quartz, plagioclase, and K-feldspar, and muscovite, pyrite, siderite, calcite, kaolinite and montnorillonite were included on a small scale. Results from ICP-OES analysis for brine showed that concentration of $Ca^{2+}$, $Na^+$, $K^+$ and $Mg^{2+}$ increased due to dissolution of plagioclase, K-feldspar and muscovite. Results of modeling for the period of 100 years showed that the recrystallization of kaolinite, dawsonite and beidellite, at the expense of plagioclase and K-feldspar is characteristic. Volumes of newly precipitation minerals and minerals passing into brine were balanced, so the porosity remained nearly unchanged. Experimental and modeling results indicate the interaction between caprock and $scCO_2$ during geologic carbon sequestration can exert significant impacts in brine pH and solubility/stability of minerals.

• Economic and Environmental Geology
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• v.50 no.4
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• pp.303-311
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• 2017

The laboratory scale experiment was performed to evaluate the sealing capacity of the capping rock such as tuff and mudstone, measuring the intial supercritical $CO_2$ ($scCO_2$) injection pressure and the $scCO_2$-water-rock reaction for 90 days. The drilling cores sampled from 800 m in depth around the Janggi basin, Korea were used for the experiment. The mineralogical changes of mudstone and tuff were measured to evaluate the geochemical stability during the $scCO_2$-water-rock reaction at $CO_2$ storage condition (100 bar and $50^{\circ}C$). The rock core was fixed in the high pressurized stainless steel cell and was saturated with distilled water at 100 bar of pore water pressure. The effluent of the cell was connected to the large tank filled with 3 L of water and 2 L of $scCO_2$ at 100 bar, simulating the subsurface injection condition. The $scCO_2$ injection pressure, which was higher than 100 bar, was controlled at the influent port of the cell until the $scCO_2$ begin to penetrate into the rock and the initial injection pressure (> 100 bar) of $scCO_2$ into the rock was measured for each rock. The mineralogical compositions of mudstones after 90 days reaction were similar to those before the reaction, suggesting that the mudstone in the Janggi basin has remained relatively stable for the $scCO_2$ involved geochemical reaction. The initial $scCO_2$ injection pressure (${\Delta}P$) of a tuff in the Janggi basin was 15 bar and the continuous $scCO_2$ injection into the tuff core occurred at higher than 20 bar of injection pressure. For the mudstone in the Janggi basin, the initial $scCO_2$ injection pressure was higher than 150 bar (10 times higher than that of the tuff). From the results, the mudstone in Janggi basin was more suitable than the tuff to shield the $scCO_2$ leakage from the reservoir rock at subsurface.

• Economic and Environmental Geology
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• v.49 no.3
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• pp.225-242
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• 2016

Rock physics serves as a useful tool for seismic reservoir characterization and monitoring by providing quantitative relationships between rock properties and seismic data. Rock physics models can predict effective moduli for reservoirs with different mineral components and pore fluids from well-log data. The distribution of reservoirs and fluids for the entire seismic volume can also be estimated from rock physics models. The first part of this report discusses the Voigt, Reuss, and Hashin-Shtrikman bounds for effective elastic moduli and the Gassmann fluid substitution. The second part reviews various contact models for moderate- to high-porosity sands. In the third part, constant-cement model, known to work well for the sand that gradually loses porosity with deteriorating sorting, was applied to the well-log data from an oil field in the North Sea. Lastly, the rock physics template constructed from the constant-cement model and the results from the prestack inversion of 2D seismic data were combined to predict the lithology and fluid types for the sand reservoir of this oil field.

• Tunnel and Underground Space
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• v.27 no.3
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• pp.146-160
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• 2017

$CO_2$ sequestration for alleviating global warming is a hot issue in the world. In this study, TOUGH2 and FLAC3D were combined for analyzing the hyro-mechanical coupling behaviors expected in $CO_2$ sequestration and applied it to Sleipner project carried out in Norway. In the analysis, the influence of pore pressure on in situ stress was considered and the influence of caprock permeability on hydro-mechanical behaviors was analyzed. In the condition of constant injection rate, pressure and saturation at the injection well, liquid and gas saturation in rock, major and minor stress variations with time and distance from the injection well, and horizontal and vertical displacements after injection could be investigated. The major principal stress was quickly increased in the early stage and then slowly decreased to a stable value, which was higher than the initial value. In contrast, the minor principal stress returned to initial value after some increase in the early stage. Surface upheaval was steadily increased and it was up to 15mm in 2 years after injection. When the caprock's permeability was changed from $3e-15m^2{\sim}3e-18m^2$, it was found that the injection well pressure and surface upheaval were inversely propotional to the permeability.

• Economic and Environmental Geology
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• v.46 no.4
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• pp.359-373
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• 2013

Shale is considered as a source rock for conventional oil and gas exploration and development because shale is fine-grained detrital sedimentary rock which can preserve the organic matter better. Shale has a good sealing capacity for the petroleum trap due to its low permeability. Commercial recoveries of gas from shale in the North America based on the development of technologies of horizontal drilling and hydraulic fracturing reveal that shale also function as a effective reservoir rock. Geochemical techniques to evaluate generation potential of the hydrocarbons from organic matter in the source rocks can be applied for the exploration of the shale gas resources. To evaluate shale gas resources, it is important to understand various geochemical processes and shale characteristics controlling generation, storage and estimation of shale gas reserves. In this paper, the generation mechanism of the oil and gas from organic matter is reviewed, and geochemical techniques which can be applied for the evaluation and characterization of shale gas are introduced.

• Geophysics and Geophysical Exploration
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• v.2 no.3
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• pp.149-153
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• 1999

The study was performed as a part of 3-D exploration project of the South Con Son basin, where Korea National Oil Co. (KNOC) and SHELL Company are performing joint operation. In the structurally complex area, seismic facies or lap-out patterns, which are usually the tools for the conventional seismic stratigraphy developed by Exxon Group (Vail et at., 1977), are not easily identifiable. Therefore, stratigraphic informations are mainly extracted from seismic attribute maps of each sequence or systems tracts, and isopach maps in correlation with the stratigraphic information from the wells. The attribute maps of the sequence or systems tract boundaries and isopach map describe the variations of paleodepositional environments. The shape of the attribute maps of the boundaries is a reasonable description of the shape of the paleodepositional surface. With other maps such as isopach and structural maps, the variations of the parasequences in the systems tracts can be projected using the surface attribute maps. The reflection intensity attribute at each sequence or system tract boundary can be related to lithology, facies or porosity distributions. The azimuth attribute of source rock sequence can be used to identify the hydrocarbon migration patterns into the prospects. The overall risks of reservoir rocks, cap rocks, structure and hydrocarbon migrations were computed using the results of the study.

• The Korean Journal of Petroleum Geology
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• v.4 no.1_2 s.5
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• pp.27-39
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• 1996

In the Cretaceous, the Gulf Coast Basin evolved as a marginal sag basin. Thick clastic and carbonate sequences cover the disturbed and diapirically deformed salt layer. In the Cretaceous the salinities of the Gulf Coast Basin probably matched the Holocene Persian Gulf, as is evidenced by the widespread development of supratidal anhydrite. The major Lower Cretaceous reservoir formations are the Cotton Valley, Hosston, Travis Peak siliciclastics, and Sligo, Trinity (Pine Island, Pearsall, Glen Rose), Edwards, Georgetown/Buda carbonates. Source rocks are down-dip offshore marine shales and marls, and seals are either up-dip shales, dense limestones, or evaporites. During this period, the entire Gulf Basin was a shallow sea which to the end of Cretaceous had been rimmed to the southwest by shallow marine carbonates while fine-grained terrigengus clastics were deposited on the northern and western margins of the basin. The main Upper Cretaceous reservoir groups of the Gulf Coast, which were deposited in the period of a major sea level .rise with the resulting deep water conditions, are Woodbinefruscaloosa sands, Austin chalk and carbonates, Taylor and Navarro sandstones. Source rocks are down-dip offshore shales and seals are up-dip shales. Major trap types of the Lower and Upper Cretaceous include salt-related anticlines from low relief pillows to complex salt diapirs. Growth fault structures with rollover anticlines on downthrown fault blocks are significant Gulf Coast traps. Permeability barriers, up-dip pinch-out sand bodies, and unconformity truncations also play a key role in oil exploration from the Cretaceous Gulf Coast reservoirs. The sedimentary sequences of the major Cretaceous reseuoir rocks are a good match to the regressional phases on the global sea level cuwe, suggesting that the Cretaceous Gulf Coast sedimentary stratigraphy relatively well reflects a response to eustatic sea level change throughout its history. Thus, of the three main factors controlling sedimentation (tectonic subsidence, sediment input, and eustatic sea level change) in the Gulf Coast Basin, sea-level ranks first in the period.

• Journal of the Korean earth science society
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• v.42 no.6
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• pp.646-661
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• 2021

The Zagros fold-thrust belt formed from the collision of the Arabian and Eurasian plates during Cenozoic periods and extends for 2,000 km, from Turkey to the Hormuz Strait, in the northeast-southwest direction. Anticline traps in the front of the Zagros thrust fold hold approximately 8% of the world's petroleum reserves. Middle Cretaceous to Early Miocene petroleum systems of the belt have the largest original oil in place (OOIP). The oil is expelled from Kazhdumi and Pabdeh source rocks, and accumulated in the Asmari and Bangestan (including Sarvak and Ilam formations) reservoir rocks covered by the evaporitic Gachsaran and the marly Gurpi formations. The hydrocarbons trapped in the Asmari and Sarvak reservoirs are mainly charged (more than 90%) by the Kazhdumi Formation whereas the rest are charged by the Pabdeh Formation. In the Dezful Embayment, all the large high-relief anticlines have been drilled into, except in the Asmari, Sarvak and Khami formations, where a few anticlines of smaller size and deeper strata remain unexplored. Therefore, the exploration potential of these regions strengthens our understanding of the Zagros fold-thrust belt's petroleum system.

• 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.