Optimized Vaporization Process with Unfavorable Design Conditions In-Soo Chun Senior Executive Vice President Seungchul Lee General Manager Hyundai Engineering Co., Ltd. AIChE Spring Meeting, April 2008 8th Topical Conference on Natural Gas Utilization New Orleans, LA, April 6-10, 2008 ABSTRACT

There are several types of vaporization schemes which have been commercially developed, such as Open Rack Vaporizer (ORV), Fired heater with Shell and Tube Vaporizer, Submerged Combustion Vaporizer (SCV), Intermediate Fluid Vaporizer, Ambient Air Vaporizer, etc. Selection of the right vaporizer system is the most important process in LNG Terminal design as the regasifying costs contribute major portion of an LNG terminal operation.

High reliability with low operating costs of the regasifying system is a key parameter for a successful operation of an LNG receiving terminal. Incheon LNG terminal, one of the biggest LNG terminals in the World, has successfully optimized vaporization facility for the most unfavorable weather conditions. The terminal’s vaporization involves ORV, SCV and seawater heater (SW HTR).

Seawater temperature conditions at Incheon terminal during winter is often below the ORV’s design temperature. However, during the same time the gas demand reaches at its peak. The operation flexibilities and production capacity reduces extremely under this unfavorable conditions.

Optimized vaporization has been achieved by combination of SCV and ORV with SW HTR. SW HTR enables seawater to be used as a heating medium, even though its temperature is below the design temperature. Without seawater heating by SW HTR, ORV may not be operated. Even it can be operated with lower seawater temperature, vaporization capacity is quite limited.

This paper reviews ORV performance and optimum heat recovery temperature under harsh seawater temperature. This paper discusses practical optimization of vaporization with the unfavorable seawater conditions in winter. Economic comparison between conventional vaporization and optimized vaporization, which are under operation, is also discussed.

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INTRODUCTION

Inchoen terminal, which is the second LNG terminal after Pyeong-taek terminal, was planned to provide base load of natural gas for the Seoul metropolitan area. Gas demand in the metropolitan area is higher than any other areas in the country. The main advantage of this terminal is to shorten the gas transportation distance resulting in lower transportation cost. However, there are several constraints in the terminal design. These include site preparation and temperature conditions of seawater, which is used as vaporization heat source. The terminal was built on a reclaimed site, where the tide level difference is quite high (about 10 meter from high-high tide and low-low tide).

In the winter season, seawater temperature may go down well below the design temperature of ORV. The warmer cooling water at a higher temperature coming out from the steam condenser of a thermal power plant can be used for the vaporization of LNG. Hence, the advantage is using the seawater for re-gasification in winter. However, the terminal is not integrated with any other thermal power plant and thus the advantage of thermal integration can not be used in designing the vaporization system.

The west coast of Korean peninsula, facing Yellow Sea, has low seawater temperature because of cold ocean current in winter. This cold seawater temperature is one of significant design constraints in optimizing the vaporization facility.

Low temperature does not allow to operate the ORV, which have the lowest operating cost. It results in the lowest life cycle cost compared with any other conventional vaporization scheme. The design conditions forces to use other vaporization options, such as Submerged Combustion Vaporizer (SCV), which uses a small portion of vaporized LNG as fuel gas. Since it burns the vaporized LNG, the operation cost is normally high.

This paper discusses the detail design constraints in designing the vaporization system and methodology of optimization of LNG vaporization with the unfavorable seawater conditions. The paper also presents operation results of this vaporization configuration with economic analysis. DESIGN CODITIONS Gas Demand Projection

Gas demand projection used for the basic design and actual gas supply are tabulated in Table 1 [1,2]. The gas demand projection established at the beginning of this project is compared with the actual gas supply records [2,3]. The design basis for the phase I of the terminal was 5 Million Tonnes per Annum (MTPA) of LNG. It was considered that the balance will be provided by the first terminal (Pyeong-taek) and third LNG terminal (Tong-Young).

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Table 1 – Projected Gas Demand and Actual Gas Supply Data (Unit: 1000 t/y)

Year Planned Demand (1) Acutal Supply (2) Difference (%)1992 3,390 3,524 3.81993 3,580 4,402 18.71994 4,720 5,860 19.51995 6,020 7,087 15.11996 7,400 9,241 19.91997 8,110 11,325 28.41998 8,280 10,645 22.21999 8,930 12,961 31.12000 9,570 14,557 34.32001 9,830 15,990 38.52002 10,610 17,768 40.32003 11,390 18,610 38.82004 12,640 21,809 42.02005 13,350 23,350 42.82006 14,050 24,090 41.7

Notes

1. These are planned data, which have been used for basic design of Incheon terminal, based on gas demand projection in 1992 [1]

2. This is actual gas supply volume data provided by KEEI [2].

Since the terminal was designed for base load terminal, the monthly basis send-out gas load distribution was established during the basic design. This pattern also has been changed during actual operation. Figure 1 illustrates comparison of the monthly gas send-out distribution.

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The send-out gas loads in winter season (January to March) are higher than the 2006’s load projected in 1992. The projected load distribution estimates that the load distribution in summer season (July and August) would be higher by 1 - 2% than June or September. However, the actual monthly send-out gas load distribution is almost same in June and July. The main differences of send-out gas load are in February and March.

For winter season gas send-out load, it is generally affected by winter ambient temperature. If it is cold winter, the send-out load increases and it will be vice versa.

The vaporizer’s economic analysis and optimization was performed based on the planned data at the beginning of the terminal Front End Engineering Design (FEED). The results have been applied to design configuration of vaporization. Seawater Temperature Conditions

In winter season seawater temperatures from the intake facility are shown in Fig. 2. This water temperature is measured 2m below the seawater surface measured at 6:00 in the morning each day.

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Dec FebJan Mar Apr Fig. 2 – Seawater Temperature Profile in Winter Season [4]

Seawater temperature in winter drops below the possible ORV seawater design temperature ranges (5 – 7 deg C). In some cases, seawater temperature drops below the freezing point. When the seawater temperature is low, the gas demand is high. Actual supply records show that this has a quite firm relationship.

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Generally, the design seawater temperature ranges between 7 to 9 deg C with 5 to 7 deg C temperature drop. In some cases, the design temperature drop will be higher than 7 deg C if the seawater temperature is above 9 deg C in winter. Since the seawater temperature is unfavorable at the site, the design temperature was evaluated based on operation economics. Seawater Intake Facility

Seawater is lifted by the seawater pumps before it is supplied to the seawater vaporizer, ORV. Five pumps were installed during Phase I and subsequently four pumps were added during expansion Phases. The capacity of the seawater pumps are 10,000 m3/h and 12,000 m3/h for Phase I and expansion, respectively.

Arrangement of the seawater pump station is shown on Fig. 3. The seawater outfall is located opposite side of the terminal in order to avoid any cold seawater recirculation.

Fig. 3 – Seawater Intake Facility Layout

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OUTLINE OF INCHEON TERMINAL PROCESS

Figure 4 illustrates the simplified process scheme of Incheon LNG terminal. LNG is transported by LNG tankers from various import sources. LNG is unloaded to the Terminal’s storage tanks through unloading arms and unloading lines. The design unloading rate is 11,000 m3/hr with three 16-in. full bore liquid unloading arms. At the initial facility design, return gas blowers were relocated from other terminal. Later it was found that the return gas to the LNG ship was sent back by a pressure difference between the tank and ship without using blowers.

Fig. 4 – Incheon Terminal Process Scheme

The terminal has two berths allowing dual unloading or single unloading

from either berth. This configuration also allows one ship unloading while another berth is on stand-by. The stand-by ship can perform vapor breathing operations to prevent over pressuring by extruding high pressure of vapor to onshore BOG header. It minimizes methane emission during unloading operation. Two berth systems can provide storage area zoning operation: LNG unloaded from one jetty can be stored in the above-ground tanks (8 tanks 100,000 m3 each), and LNG unloaded from the other jetty can also be stored in 2 Above-ground tanks and 8 In-ground tanks (total 1.7 million m3 including the 4th expansion). Intentionally, all stored LNG can be blended to minimize density difference between tanks and achieve even calorific values of send-out gas.

It is generally considered that one large unloading line will be cheaper than two equal-sized smaller lines. However, there is a very real advantage in dual unloading lines as in case one line to have any operational problems, then the other line is still available for unloading the ships at half capacity or higher. Also, most terminals require the recirculation of LNG in the unloading line during

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the period a ship is not unloading. This is normally required so that the recirculated LNG picks up the heat out of the terminal via the send-out. Since the terminal has two unloading lines (2 x 32-in.) from each berth, this configuration allows recirculation to be accomplished without the addition of a smaller second line.

At the initial stage, the terminal planned to build above-ground full containment tanks. As the terminal expanded, it needed more storage capacity to cover the demand gap between summer and winter as shown in Fig. 1. As tankage area extends, the required hydraulics increases at the ship manifold. Significant factors in determining hydraulics are tank static head and frictional losses across the unloading arms. Underground storage tank could alleviate the hydraulic limitations. A large in-ground storage tank makes use of high cost reclaimed island more efficiently than conventional smaller above-ground tanks. In-ground tanks allow adherent positioning of tanks compared to above ground tanks. This also saves plot space because of elimination of the dike area.

Boil-off gas (BOG) from storage tanks is gathered in a BOG header and pressurized by BOG compressors. The pressurized BOG is then routed to the recondenser where it is recondensed with sub-cooled LNG discharged from in-tank pumps. The recondensed liquid is further pressurized by the send-out pumps and re-gasified by vaporizers.

The BOG rates are 0.075%/day and 0.1%/day for above-ground tank and in-ground tank, respectively. The large storage volume makes considerably higher BOG rates than other terminals. Ten (10) BOG compressors are installed to handle the BOG during unloading operation.

Open Rack Vaporizers (ORV’s) are the base-load vaporizers, and Submerged Combustion Vaporizers (SCV’s) are used to back up ORV’s during peak shaving operation. However, the available seawater temperature drops below the design points during winter. The ORV performance then decreases considerably as seawater temperature decreases. In order to compensate the seawater temperature drops, twelve (12) Seawater Heaters (SW HTR’s) are operated. OPTIMIZED VAPORIZATION AND TECHNICAL CHALLENGES

In order to achieve low cost vaporization and minimize impact on the environment, ORV’s and SCV’s are combined as a back up and peak shaving was chosen from various vaporization technologies. A seawater facility requires a long seawater intake pipe (about 1,500m) since the tide difference is high (about 5m – M.S.L.). The seawater discharge temperature drops to 0oC after it is used for LNG vaporization, which is generally not recommended for ORV operation specially during the winter. Figure 5 illustrates the vaporization scheme of the terminal. LNG from the recondensers from each train is fed to the send-out pumps and the pressurized LNG is routed to the vaporizers. Seawater is supplied

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to ORV’s. When the temperature of seawater supplied to ORV’s is lower than the design point, it is mixed with the heated seawater from the SW HTR’s.

As shown in the seasonal gas demand pattern in Fig. 1, gas demand in the winter is higher than in the summer. However, the seawater temperature as a heat source is lower in the winter. Since LNG regasification is the most important parameter for lowering terminal operating costs, optimization of LNG vaporization has been performed against these unfavorable conditions.

The following parameters were investigated for the vaporization optimization:

Performance of ORV with the lower seawater temperature; Optimum seawater operating temperature; Economic combination of ORV and SCV; Economic justification of seawater heating; Overall economic assessment of vaporization facility.

In the ORV, the relationship between the number of heat exchange panel blocks and seawater requirement has been investigated for optimization and found that ORV manufacturers recommended a seawater temperature difference based on the manufacturer’s equipment optimization, which resulted in a less number of heat exchange panels. By analyzing the ORV performance curves with the various operating conditions, the relationship was extracted as shown in Fig. 6. The recommended seawater temperature differences are based on a 42MW heat duty (equivalent to 180t/h – 200t/h of LNG vaporization). Manufacturers confirmed that the minimum outlet temperature from the ORV was 1.5oC, which is obtained when seawater inlet temperature is 3oC.

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Fig. 5 – Vaporization Scheme

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In general, seawater requirement abruptly increases as inlet seawater temperature decreases, while seawater requirement is constant after a certain point even though its temperature increases. This is because seawater should be provided to maintain the minimum water film on the surface of the heat exchange tubes. The seawater requirement varies depending on the number of the heat exchanger panels and tubes.

The higher inlet seawater design temperature requires a smaller ORV and seawater lift structure, resulting in less capital and operation costs. However, these are only valid when the seawater temperature is high enough through out the year. As seawater temperature decreases below design temperature, the SCV operation and seawater heating process need to be operated, resulting in an increase in operating costs. During the winter, the fuel gas requirements for the operation of SCV’s and SW HTR’s increase linearly as the recovered heat from seawater decreases (seawater temperature drops). The economic analysis results are shown in Fig.7.

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In order to optimize the design seawater temperature, expense-based Net

Present Value (NPV) was calculated. From the economic analysis results, design seawater temperature was set at 5oC. The number of tube panels required was also determined based on design seawater temperature and expected delta temperature. The parameters used in economic analysis are summarized in Table 2. It was assumed that fuel cost was $7/MMBtu. Considering current fuel cost, the optimum design temperature may be shifted slightly to the lower point.

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ECONOMIC JUSTIFICAITON OF SEAWATER HEATING

Based on Life cycle costs, economic evaluation on vaporization costs for gas send-out has been performed during the year 2006 on the following Options:

• Base case: ORV+SCV+SW Heater (5 deg C design temp + SW heater)

• Option 1: ORV + SCV (7 deg C Seawater design temp. + no SW heater)

• Option 2: ORV + SCV (5 deg C Seawater design temp. + no SW heater)

• Option 3: All SCV (current the US terminal operation basis) The terminal operation cost estimates are based on Rich LNG with 1% of

maintenance costs for main equipment. Other details specified in Table 2 have been applied to the economic evaluation. Unloading, storage, vapor handling, and other costs are not considered because the same conditions are applied to all options. Gas sale revenues are also not considered. Instead, only incremental costs of vaporization are applied for evaluation purpose.

The economic analysis results are shown in Fig. 8 for relative total installed costs and operation costs to Base case. Option 1 requires slightly lower capital expenditure (Capex) than the Base case, while Option 2 shows almost the same Capex as the Base case. Option 3 with all SCV requires the lowest Capex.

Figure 9 presents the relative Incremental expense-based Net Present Value (NPV) of three Options to the Base case. The vaporization costs of the Base case are the lowest compared to any other Options. Main benefits in the NPV are heat recovery from low temperature seawater, which can not be used for LNG vaporization with the conventional ORV's without the SW HTR's.

For Option 1, the capital expenditure is slightly lower than the Base case because of its high delta temperature in ORV design. Operating cost is higher by about two fold of the Base case, mainly due to lower heat recovery from cold seawater. The NPV difference to the Base case is about 5% due to extra heat requirements for LNG vaporization during winter season.

Table 2 – Economic Parameters

25 years 12% 7¢/kWh 7 $/MMBtu 3% Not considered

Facility life time Discount rate Electricity cost Fuel cost Inflation rate Tax rate

ParametersDescription

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Capital cost requirement of the Option 2 is almost the same as the Base case as it does not require installation of the SW HTR's. However, operating costs are higher by a 50% than the Base case. NPV is slightly lower than the Base case, mainly due to lower heat recovery from cold seawater.

Since the Option 3 uses the SCV's for LNG vaporization, the required capital expenditure is the lowest than any other Options. However, its operating cost is by 8 times higher than the Base case because main heat for LNG vaporization is provided by fuel combustion. The main economic driver of the Option 3 is the lowest Capex, quick construction and US government approval process compared to seawater options.

Because the Expense-based NPV’s of Option 1 and 2 are not significantly different from the Base case, the overall economic evaluation is primarily affected by heat recovery from cold seawater and fuel gas burning for supplementary heat supply. The detail configuration and economic justification should be performed based on the project design conditions.

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CONCLUSIONS The design temperature of the Open Rack Vaporizer may be different from

the manufacturer’s recommended design temperature and optimum operation point, which will be justified by the individual project conditions. Optimized design temperature of the seawater vaporizer can be determined by overall economics based on the site operation and design conditions.

In optimum vaporization selection, design constraints with unfavorable seawater temperature have been successfully solved with heating up seawater with the seawater heater before it is provided to the ORV. This results in an increase in heat recovery from cold seawater. Unless otherwise, the seawater can not be used when it is lower than the design temperature.

Seawater heater increases total installation cost of the vaporization system. However, the warming up seawater temperature decreases by 50% of fuel gas consumption compared to the use of SCV vaporization configuration with the same design temperature, but without seawater heating up. ACKNOWLEDGEMENT The authors wish to thank Korea Gas Corporation (Kogas) for permission to prepare and present this paper. Special thanks are also extended particularly to Dr. J. H. Cho, CB&I, for his kind assistance and valuable discussions.

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REFERENCE CITED 1. Technical and Economical Summary of Basic Design Report for Incheon

LNG Terminal, Kogas/Hyundai Engineering Co/MWKL, Unpublished document, February 1993.

2. A Prospect of Gas Demand in Korea (2006-2011), Korea Energy Economics Institute, ISSn 1599-9009, Vol. 8, December 2006.

3. 8th Long Term Natural Gas Supply and Demand Plan, Ministry of Commerce Industry and Energy, Korea, December 2006.

4. Incheon Seawater Temperature, Korean Meteorological Administration, Korea.

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BIOGRAPHY of SPEAKER In-Soo Cheon is a Chemical Engineer with a B.S.ChE degree from Seoul National University, Korea. He is currently senior executive vice president of Hyundai Engineering Co., Ltd. He has worked as project manager for LNG distribution system in Seoul Metropolitan Area from 1983 to 1989. He has also worked as Project Director for Inchon LNG Receiving Terminal Project in Korea from 1991 to present. His career in LNG and gas processing spans over 39 years and has been involved in various gas monetization projects, ranging from conceptual design to commissioning. Through his vast hand-on experience in LNG projects, he has gained extensive knowledge in efficient and practical design towards safe operation of the LNG terminal. E-mail: ischun@hec.co.kr

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