• Journal of the Korean Institute of Gas
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• v.17 no.2
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• pp.9-20
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• 2013

Depleted gas reservoir has been already explored and its geologic data, along with its reservoir properties, are already known through seismic exploration and drilling. Therefore it would be less difficult to develope a gas storage from depleted gas reservoir. Cushion gas which remains in the reservoir to maintain pressure affects withdrawal rate of working gas in underground gas storage. In this study, we attempted to investigate the relationship between cushion gas and withdrawal rate using a commercial simulator. From the analyses of the results, it is found that the minimum limit for a cycle of 5-month injection and 5-month withdrawal is 10 wells with 50% cushion gas, and 12 wells with 60% cushion gas for a cycle of 7-month injection and 3-month withdrawal.

• Advances in Energy Research
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• v.6 no.1
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• pp.75-90
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• 2019

Anthropogenic greenhouse gas emissions are rising rapidly despite efforts to curb release of such gases. One long term potential solution to offset these destructive emissions is the capture and storage of carbon dioxide. Partially depleted hydrocarbon reservoirs are attractive targets for permanent carbon dioxide disposal due to proven storage capacity and seal integrity, existing infrastructure. Optimum well completion design in depleted reservoirs requires understanding of prominent geomechanics issues with regard to rock-fluid interaction effects. Geomechanics plays a crucial role in the selection, design and operation of a storage facility and can improve the engineering performance, maintain safety and minimize environmental impact. In this paper, an integrated geomechanics workflow to evaluate reservoir caprock integrity is presented. This method integrates a reservoir simulation that typically computes variation in the reservoir pressure and temperature with geomechanical simulation which calculates variation in stresses. Coupling between these simulation modules is performed iteratively which in each simulation cycle, time dependent reservoir pressure and temperature obtained from three dimensional compositional reservoir models in ECLIPSE were transferred into finite element reservoir geomechanical models in ABAQUS and new porosity and permeability are obtained using volumetric strains for the next analysis step. Finally, efficiency of this approach is demonstrated through a case study of oil production and subsequent carbon storage in an oil reservoir. The methodology and overall workflow presented in this paper are expected to assist engineers with geomechanical assessments for reservoir optimum production and gas injection design for both natural gas and carbon dioxide storage in depleted reservoirs.

• Korean Chemical Engineering Research
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• v.45 no.5
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• pp.515-522
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• 2007

In this study we have attempted to evaluate the technical feasibility of "BB-HY", which is depleted gas reservoir as a gas storage field, using the commercial compositional simulator "ECLIPSE 300". The "BB-HY" reservoir has an initial gas in place of 143 BCF which is relatively small, and its porosity and permeability are 19.5% and 50 md, respectively. For "BB-HY" gas reservoir, we have performed a feasibility analysis by investigating the cushion gas (or working gas), converting time to gas storage field, operation cycle, number of wells and the possible application of horizontal borehole as well. From the simulation results, it was found that the amount of cushion gas in "BB-HY" reservoir is required at least 50% of IGIP in order to operate stably as gas storage field. When one produces gas for longer time and hence the remaining gas in reservoir is less than optimal cushion gas, no technical problem was occurred as long as additional cushion gas is injected up to the optimal cushion gas. In the case of changing the operation cycle into producing gas for three months during winter season from producing five months, the result shows that either the cushion gas should be greater than 60% or the more number of wells should be drilled. Meanwhile, from the results of sensitivity analysis for the number of wells, in cases of operating six or eight vertical wells, the stable reproduction of the injected gas can not be possible in "BB-HY" gas reservoir since the remaining gas in reservoir is increased. Therefore, in "BB-HY" reservoir, at least ten vertical wells should be drilled for the stable operation of gas. This time, when three horizontal wells are additionally drilled including the existing two vertical wells, it was found that the operation of injection and reproduction of gas is relatively stable in "BB-HY" gas reservoir.

• Journal of the Korean Institute of Gas
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• v.27 no.1
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• pp.23-32
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• 2023

In this study, the Al₂O₃ nanofluid was synthesized as an additive for improving the injection efficiency and storage capacity of carbon dioxide (CO₂) in a depleted sandstone reservoir or deep saline aquifer. As the base fluid, deionized water (DIW) and saline prepared by referring to the composition of API Brine were used, and the fluid was synthesized by using Al₂O₃ nanofluid with CTAB (cetyltrimethyl-ammonium bromide), a cationic surfactant. After that, the dispersion stability was evaluated by using visual observation, dynamic light scattering (DLS), transmission electron microscope (TEM), and miscibility test. As a result, it was presented that stable nanofluid without agglomeration and precipitation after reaction with 70,000 ppm of brine could be synthesized when the nanoparticle concentration was 0.05 wt% or less.

• Geophysics and Geophysical Exploration
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• v.9 no.1
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• pp.37-43
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• 2006

In 2006, the Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC) plans to undertake (subject to receiving the necessary approvals) a Pilot program for $CO_2$ storage within a depleted gas reservoir. The Otway Basin Pilot Program (OBPP) aims to demonstrate that subsurface $CO_2$ storage is both economically and environmentally sustainable in Australia. This will be the first $CO_2$ storage program in the world to utilise a depleted gas reservoir and, hence, the experience gained will be a valuable addition to the range of international $CO_2$ storage programs that are underway or being planned. A key component of the OBPP is the design of an appropriate geophysical monitoring strategy that will allow the subsurface migration of the $CO_2$ plume to be tracked and to verify that containment has been successful. This paper presents the results from modelling the predicted gravity response to $CO_2$ injection into the Otway Basin reservoir, where the goal was to determine minimum volumes of $CO_2$ that may be detectable using non-seismic geophysical techniques. Modelling results indicate that gravity measurements at 10 m spacing within the existing observation well and the planned $CO_2$ injection well would provide excellent vertical resolution, even for the smallest $CO_2$ volume modelled (10000 tonnes), but resolving the lateral extent of the plume would not be possible without additional wells at closer spacing.

• Journal of the Korean Society for Marine Environment & Energy
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• v.19 no.4
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• pp.286-296
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• 2016

Offshore CCS technology is to transport and inject $CO_2$ which is captured from the power plant into the saline aquifer or depleted oil-gas fields. The more accumulated injected $CO_2$, the higher reservoir pressure increases. The increment of reservoir pressure make a dramatic change of the operating conditions of transport and injection systems. Therefore, it is necessary to carefully analyze the effect of operating condition variations over the injection period in early design phase. The objective of this study is to simulate and analyze the $CO_2$ behavior in the transport and injection systems over the injection period. The storage reservoir is assumed to be gas field in the East Sea continental shelf. The whole systems were consisted of subsea pipeline, riser, topside and wellbore. Modeling and numerical analysis were carried out using OLGA 2014.1. During the 10 years injection period, the change of temperature, pressure and phase of $CO_2$ in subsea pipelines, riser, topside and wellbore were carefully analyzed. Finally, some design guidelines about compressor at inlet of subsea pipeline, heat exchanger on topside and wellhead control were proposed.

• Advances in Energy Research
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• v.6 no.2
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• pp.103-129
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• 2019

While global demand for energy increases annually, at the same time the demand for carbon-free, sulphur-free and NO_x-free energy sources grows considerably. This state poses a challenge in the research for newer sources like biomass and shale gas as well as renewable energy resources such as solar, wind, geothermal and hydraulic energy. Although wave energy also is a form of renewable energy it has not fully been exploited technically and economically so far. This study tries to explain those reasons in which it is beyond doubt that the demand for wave energy will soon increase as fossil energy resources are depleted and environmental concerns gain more importance. The electrical energy supplied to the grid shall be produced from wave energy whose conversion devices can basically work according to three different systems. i. Systems that exploit the motions or shape deformations of their mechanisms involved, being driven by the energy of passing waves. ii. Systems that exploit the weight of the seawater stored in a reservoir or the changes of water pressure by the oscillations of wave height, iii. Systems that convert the wave motions into air flow. One of the aims of this study is to present the classification deficits of the wave energy converters (WECs) of the "wave developers" prepared by the European Marine Energy Center, which were to be reclassified. Furthermore, a new classification of all WECs listed by the European Marine Energy Center was arranged independently. The other aim of the study is to assess the technological state of the art of these WECs designed and/or produced, to obtain an overview on them.

• 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.

• Journal of the Korean Society for Marine Environment & Energy
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• v.13 no.1
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• pp.18-29
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• 2010

Offshore subsurface storage of $CO_2$ is regarded as one of the most promising options to response severe climate change. Marine geological storage of $CO_2$ is to capture $CO_2$ from major point sources, to transport to the storage sites and to store $CO_2$ into the offshore subsurface geological structure such as the depleted gas reservoir and deep sea saline aquifer. Since 2005, we have developed relevant technologies for marine geological storage of $CO_2$. Those technologies include possible storage site surveys and basic designs for $CO_2$ transport and storage processes. To design a reliable $CO_2$ marine geological storage system, we devised a hypothetical scenario and used a numerical simulation tool to study its detailed processes. The process of transport $CO_2$ from the onshore capture sites to the offshore storage sites can be simulated with a thermodynamic equation of state. Before going to main calculation of process design, we compared and analyzed the relevant equation of states. To evaluate the predictive accuracies of the examined equation of states, we compare the results of numerical calculations with experimental reference data. Up to now, process design for this $CO_2$ marine geological storage has been carried out mainly on pure $CO_2$. Unfortunately the captured $CO_2$ mixture contains many impurities such as $N_2$, $O_2$, Ar, $H_{2}O$, $SO_{\chi}$, $H_{2}S$. A small amount of impurities can change the thermodynamic properties and then significantly affect the compression, purification and transport processes. This paper analyzes the major design parameters that are useful for constructing onshore and offshore $CO_2$ transport systems. On the basis of a parametric study of the hypothetical scenario, we suggest relevant variation ranges for the design parameters, particularly the flow rate, diameter, temperature, and pressure.