Youngsub Lim

Pinch based approach to estimate CO2 capture and storage retrofit and compensatory renewable power for South Korean electricity sector

A pinch-based approach has been used to calculate optimum values of CO2 capture and storage (CCS) retrofit and compensatory renewable power for the Korean electricity sector. Three cases are proposed. In the first case, KEPCO 2020 power generation forecast data were used to calculate CO2 emissions and a 30% emission reduction target applied. For the second case, nuclear-free KEPCO 2020 forecast was used to calculate emissions along with 30% emissions reduction. In the third case, the emissions reduction target increased from 30% to 54.50% for case-2 scenario, in order to achieve 2005 emissions level. Results show that CCS retrofit and compensatory renewable power for case 3 is 2.6 times higher than case 1 and 1.8 times higher than case 2. According to sensitivity analysis results, CCS retrofit and compensatory renewable power for case 3 is more sensitive to CO2 removal ratio and parasitic energy loss ratio, respectively, as compared to case 1 and case 2.

Optimal Unloading Procedure for a Mixed Operation of Above-ground and In-ground LNG Storage Tank using Dynamic Simulation

Publisher Summary Natural gas is used as a heating fuel and its usage has increased due to its cleanliness. At the source, natural gas is usually transformed into liquefied natural gas (LNG) to decrease its volume. It is then transported to the demand region by carrier ship. LNG is then transferred from the carrier ship to an onshore storage tank. The process of unloading liquefied natural gas (LNG) from a carrier ship to a storage tank consists of three steps: recirculation, depressurization and unloading. Because LNG is typically maintained at a cryogenic temperature near –160 °C, a recirculation process is needed to keep the unloading pipeline cool and prevent vaporization of the LNG. The unloading line is then depressurized to a pressure valve that lies between the ship and the storage tank. Finally, the LNG in the carrier ship is transferred to the storage tank. There are two different types of LNG storage tanks: above-ground and in-ground tanks. When a single type of tank is used for storage, there are no critical problems encountered between the recirculation and unloading steps. However, for the mixed operation of above-ground and in-ground LNG storage tanks, the depressurization of an unloading pipeline can generate vapor on top of the unloading pipeline of the above-ground tank due to the pressure head. The vapor produced from the above-ground tank can congest depressurization, which can in turn cause excessive BOG(Boil-Off Gas) inflow.

Potential Explosion Risk Comparison between SMR and DMR Liquefaction Processes at Conceptual Design Stage of FLNG

An FLNG (floating liquefied natural gas) or LNG FPSO (floating production, storage and offloading) unit is a notable offshore unit with the increasing demand for LNG. The liquefaction process on an FLNG unit is the most important process because it determines the economic feasibility, but would be a hazard source because of the large quantity of hydrocarbons. While a high efficiency process such as C3MR has been preferred for onshore liquefaction processes, a relatively simple process such as the SMR (single mixed refrigerant) or DMR (dual mixed refrigerant) liquefaction process has been selected for offshore units because they require a more compact size, lighter weight, and higher safety due to their space limitation for facilities and long distance from shore. It is known that an SMR has the advantages of a simple configuration, small footprint, and lower risk. However, with an increased production rate, the inherent safety of SMR needs to be evaluated because of its small train capacity. In this study, the potential explosion risks of the SMR and DMR liquefaction processes were evaluated at the conceptual design stage. The results showed that an SMR has a lower overpressure than a DMR at the same frequency, only with a small production capacity of 0.9 MTPA. With increased capacity, the overpressure of the SMR was higher than that of the DMR. The increased number of trains increased the frequency in spite of the small amount of equipment per train. This showed that the inherent risk of an SMR is not always lower than that of a DMR, and an additional risk management strategy is recommended when an SMR is selected as the concept for an FLNG liquefaction process compared to the DMR liquefaction process. Received 3 November 2017, revised 22 March 2018, accepted 12 April 2018 Corresponding author Youngsub Lim: +82-10-8850-4586, s98thesb@snu.ac.kr ORCID: https://orcid.org/0000-0001-9228-0756 c 2018, The Korean Society of Ocean Engineers This is an open access article distributed under the terms of the creative commons attribution non-commercial license (http://creativecommons.org/licenses/by-nc/3.0) which permits unrestricted non-commercial use, distribution, and reproduction in any medium, provided the original work is properly cited.

Operational strategy to minimize operating costs in liquefied natural gas receiving terminals using dynamic simulation

Although the operation of an LNG receiving terminal, especially for LNG unloading process, is important in terms of economics and safety, the systematic approach for this process is deficient with regard to operating variables and inherent terminal characteristics. Because the characteristics of each LNG terminal vary according to its individual condition, it is worth to investigate the operational method manipulating operating variables to reduce operating costs regarding terminal characteristics. In this study, we perform a rigorous and extensive dynamic simulation of LNG unloading process to demonstrate the effects of terminal characteristics, including the total length of the pipeline, the number of storage tanks, the ambient temperature, and the operation cycle. Based on simulation results and cost analyses, we can suggest an operational strategy to minimize the operating cost in LNG receiving terminals.

BOG Handling Method for Energy Saving in LNG Receiving Terminal

Abstract Generation of Boil-off gas (BOG) in liquefied natural gas (LNG) receiving terminal affects considerably operating energy costs and safety issue. For that reason, the BOG handling method is determinant for design of LNG receiving terminal. This study proposes the concept of new design for BOG handling and calculates the design variables using sensitivity analysis for minimum send-out case. This design provides 21.9% energy saving and 0.197y payback period.

Risk and efficiency analysis of dual mixed refrigerant liquefaction process configurations for floating liquefied natural gas at conceptual design stage: Conceptual Risk Analysis of DMR Process for FLNG

Liquefied natural gas (LNG) floating production storage offloading, or floating liquefied natural gas (FLNG), is an offshore unit used to produce LNG from offshore gas reservoirs. The liquefaction is critical process for liquefying natural gas (NG) into LNG. Among NG liquefaction technologies used in the industry, single mixed refrigerant, dual mixed refrigerant (DMR), and the nitrogen expansion liquefaction process have been considered for FLNG on account of its space limitations and higher safety standards. In particular, the DMR liquefaction process is preferred for a large FLNG because of its high efficiency. Many studies have been suggested about an efficiency of DMR, but a few studies have been conducted on their process safety although different configurations in process concepts can cause meaningful differences in operating conditions and safety. In this study, two DMR process configurations were optimized to maximize the efficiency and conceptual explosion risk was analyzed to compare their risk at the conceptual design stage. The results showed a difference between the explosion risks by the differences in the optimal mixed refrigerant compositions and number of devices, with similar efficiencies. These results can provide insight for a risk management strategy at the conceptual design stage, to minimize the unexpected cost generation.

Choosing the suitable Carbon dioxide Storage Location in Sedimentary Basins of Korea

The average CO2 emission growth rate of Korea is 1.4% which is second highest among OECD countries. The Korean government plans to start CO2 injection by 2018, so in order to develop ready to inject sequestration site by that time, there is a need to assess storage sites technically, economically, and from safety point of view. Three potential basins namely Kunsan, Jeju and Ulleung are thought to have good CO2 storage capacity in Korea. In this study, CO2 storage potential in sedimentary basins of Korea is calculated along with their economic analyses. The results show that Ulleung basin has the maximum storage capacity and low storage cost among other basins. These results provide the basis for decision making while selecting storage site for commercial sequestration that offer maximum storage capacity and least storage cost.

LNG Processing: From Liquefaction to Storage

Abstract Development of LNG technology has responded to expanding LNG demand. LNG worldwide consumption is expected to increase continuously for the following two or three decades. The LNG value chain includes pretreatment, liquefaction process, shipping and storage of LNG. This paper addresses the process and development of LNG liquefaction plant and receiving terminals. In addition, the role of process systems engineering in the LNG industry is reviewed with future challenges as the concluding remarks.