TECHNICAL EFFORTS FOCUS ON CUTTING LNG PLANT COSTS

July 3, 1995
Ichizo Aoki, Yoshitsugi Kikkawa Chiyoda Corp., Yokohama, Japan LNG demand is growing due to the nuclear setback and environmental issues spurred by concern about the greenhouse effect and acid rain, especially in the Far East. However, LNG is expensive compared with other energy sources. Efforts continue to minimize capital and operating costs and to increase LNG plant availability and safety.
Ichizo Aoki, Yoshitsugi Kikkawa
Chiyoda Corp.,
Yokohama, Japan

LNG demand is growing due to the nuclear setback and environmental issues spurred by concern about the greenhouse effect and acid rain, especially in the Far East. However, LNG is expensive compared with other energy sources. Efforts continue to minimize capital and operating costs and to increase LNG plant availability and safety.

Technical trends in the LNG industry aim at reducing plant costs in pursuit of a competitive LNG price on an energy value basis against the oil price. This article reviews key areas of technical development.

TRAIN SIZE

A larger train is the common way to reduce LNG costs. Train size started from 600,000 metric tons/year for Algeria's Camel project in 1964 and has grown to nearly 3 million tons/year for recent projects (Table 1)(10726 bytes).

The train size of 21st century projects may reach 4 million tons/year (600 MMscfd), depending upon the market. If the C3-MR liquefaction process of Air Products & Chemicals Inc. (APCI) remains dominant, train size will be determined mainly by the available compressor and driver and the main heat exchanger size.

LIQUEFACTION PROCESS

Liquefaction processes in use in existing LNG projects are shown in Table 2(12400 bytes).

Shell Internationale Petroleum Maatschappij BV (SIPM) has carried out an extensive study of the double mixed refrigerant (DMR) process of Tealarc vs. C3-MR for Bonny LNG. The DMR process applies a C2/C3 mixture for precooling, using a plate fin heat exchanger. The precooling cycle can be some 20% higher than the efficiency of a propane cycle for the particular application.

The study showed that the DMR process had lower capital and operating costs due to the higher thermal efficiency. However, the C.3-MR process was selected for the project 2

ACID GAS REMOVAL

Product specifications of the acid gas removal process are commonly set as shown in Table 3(7881 bytes). Major acid gas removal processes are shown in Table 4(8056 bytes).

SULFINOL

Sulfinol is a physico-chemical absorption process. The Sulfinol solution consists of diisopropanolamine (DIPA), sulforane, and water. Since sulforane performs the physical absorption, this process has an advantage over other processes when the acid gas partial pressure is high; i.e., the feed gas has a high acid gas content. In addition, the process is preferable when the feed gas has a high mercaptan content, which is common in Middle East natural gas, since sulforane has a strong affinity for mercaptans.

Sulforane also has an affinity for heavy hydrocarbons, especially aromatics; therefore, when the acid gas from the regenerator is fed to the sulfur recovery unit, some consideration may be required to reduce the hydrocarbon content. Since the absorber is the heaviest equipment in an LNG plant, reduction of absorber size is one of the key factors for LNG project engineering and construction.

Royal Dutch/Shell Group's proprietary tray improves performance of large columns. In addition, recently structured packing has been used successfully in the Sulfinol absorber in Australia's North West Shelf LNG project to obtain increased capacity and suppress foaming.

BENFIELD HI-PURE

The Benfield Hi-pure process consists of two systems: hot potassium carbonate (HPC) and diethanolamine (DEA). The HPC system performs bulk removal, the DEA system final removal, of acid gas.

This process needs less regeneration

heat, although it is expensive due to the double system. A recent Bonfield process applies heat economization using flashed steam sucked by the ejector from the rich HPC solution as a carbonate regenerator heat source, lowering the requirement for regeneration heat.

UCARSOL

Ucarsol is a proprietary solvent based on tertiary amine methyldiethanolamine (MDEA) from Union Carbide Corp. This process was retrofitted to the Sontang LNG trains, which had been designed for the MEA process. It reduced the solution circulation rate and regenerator reboiler duty.5

DEHYDRATION AND SWEETENING

Dehydration is commonly done by a 4A-type molecular sieve. Sweetening after acid gas removal is required when total sulfur is specified as 30 mg/cu m for LNG at the receiving terminal, since the feed gas total sulfur is to be less than 20-25 mg/cu m, considering sulfur compound concentration into the LNG product during the liquefaction processing and tanker transportation. Heavy sulfur compounds usually distribute to C5+, while light sulfur compounds, such as COS, C1SH, and C2SH, distribute to LNG. The following kinds of molecular sieve have been used in recent LNG projects:

  • 5A type.
This type removes C1SH and C2SH, which are rather difficult to remove by Sulfinol; therefore, it is a good combination with Sulfinol. It also has less adsorption of heavy hydrocarbons, which results in less Wobbe Index variation when the regeneration gas is used as gas turbine fuel.
  • 13X type.
This type removes C1SH, C2SH, C3SH, and C4SH and adsorbs heavy hydrocarbons; therefore, it is a good combination with the Benfield process. The regeneration gas can be used as boiler fuel.

MERCURY REMOVAL

Mercury in the feed gas corrodes aluminum; therefore, the mercury content of the feed gas to the cryogenic section should be less than 0.01 micrograms/cu m.

Mercury content in the feed gas caused serious aluminum corrosion of the main heat exchanger of the Arun LNG plant. The mercury adsorber bed, which was provided upstream of the acid gas removal unit, got saturated and broke through to the downstream units. The mercury bed is a sulfur-impregnated activated carbon and reacts with Hg to form HgS.

In the Arun LNG plant an additional guard bed was provided upstream of the cryogenic section and resulted in a mercury content of 0.00023 micrograms/cu in.

Currently, any LNG plant is provided with a mercury adsorber bed to avoid this corrosion. Technology for mercury recovery from the spent catalyst of the sulfur-impregnated activated carbon has been developed by a German firm, although a commercial plant has not been built.

Other than sulfur-impregnated activated carbon, the following catalysts are available:

  • Alumina beads supporting a metal sulfide.
Institut Francais du Petrole (IFP) has developed an adsorbent for trapping metallic mercury from gas or liquid. The adsorbing media are alumina pellets supporting a metal sulfide, which reacts with mercury yielding nonvolatile mercury sulfide .7
  • Molecular sieve.
This type, developed by UOP, has not yet been used in an LNG plant, although it has been applied successfully to gas processing. Unlike sulfur-impregnated materials, it is regenerative.

HEAVY END REMOVAL

To prevent freeze-up during cooling, heavy ends are separated before liquefaction to less than 1 ppm (mole) benzene and less than 0.1 mole % C5+In the APCI process, heavy end removal is achieved by distillation in the so-called scrub column.

When the feed gas pressure is very high and separation is difficult due to column operating conditions close to the critical point or supercritical, the operating pressure of the column needs to be reduced to get a sufficient liquid/vapor density ratio for the tray liquid/vapor separation, although the refrigeration power for liquefaction will increase to some extent.

LIQUEFACTION

Liquefaction of feed gas after heavy end removal is done by cooling in heat exchangers (Table 5)(14950 bytes).

The plate fin heat exchanger has been successfully used for precooling in the Adgas third train, reducing plot space and refrigerant inventory. For the future train size of 4 million tons/year, APCI reports that it can manufacture and transport the main heat exchanger from the Wilks-Barre factory via rail employing Schnabel-type equipment.8

The main heat exchanger will have length less than 58 m and warm-bundle shell diameter less than 5.2 m.

N2 REJECTION

When the feed natural gas has N2 content exceeding 1 mole %, N2 rejection is required. It can be achieved via a single-stage flash and N2 stripper, according to the N2 content and boil-off rate at the storage tank.

REFRIGERATION COMPRESSOR AND DRIVER

Since the refrigeration compressor and the driver will have the major impact on capital cost, operating cost, and availability of the liquefaction train, this subject has needed careful study for past LNG projects.

COMPRESSOR TYPE

For a plant capacity of more than 2.5 million tons/year, an axial compressor can be applied to the low pressure (LP) MR compressor due to the large volume at the compressor suction, although use of the axial type is quite low. Use of the centrifugal type is also possible with the largest frame. The axial compressor will indicate better polytropic efficiency by more than 5% over the centrifugal compressor; this type was used in the MLNG-2 plant."' The centrifugal type has been used as a propane compressor and the high pressure (HP) MR compressor due to their configuration and suction volume.

GAS TURBINE DRIVER

Recent LNG projects have used gas turbine drivers, although some expansion projects still apply steam turbine drivers. The thermal efficiency improvement and ease of start-up give gas turbine drivers some advantages compared with steam turbine drivers. An LNG plant in the 2.4-3 million ton/year capacity class will require refrigeration power of 90,000-120,000 kw. Recent projects designed or studied use the schemes shown in Table 6(14025 bytes).

SINGLE SHAFT AND DUAL SHAFT

Basically, dual shaft gas turbines, such as frame-5 heavy duty units, are used for mechanical drive application, while single shaft gas turbines are used for generator drive application. As dual shaft gas turbines have HP turbine rotors which drive gas turbine air compressors and power turbine shafts which drive the process compressors, sufficient starting torque can be provided.

GE frame-5 has been successfully used in the Arun LNG plant and Australian North West Shelf LNG plant."'

LM-6000 is also a dual shaft machine, developed from GE's latest production aircraft engine, CF6-80C2. It has high thermal efficiency and easy maintenance because of its low weight and will be used in future LNG plants.12

As the maximum frame of heavy duty dual shaft gas turbines is frame-5, application of single shaft heavy duty gas turbines of frame-7 or frame-6 has been considered for the main refrigeration compressor drivers for LNG plants. For use of the single shaft gas turbine as a refrigerant compressor driver, vacuum suction of the refrigeration compressor will be needed to minimize start-up torque; to cover the shortage of torque during start-up, a variable speed motor or steam turbine is required. The single shaft machine will provide a speed range of 5%, while the dual shaft machine can provide a 25% speed range; therefore, the narrow operating speed range should be taken into account in the design of process control.

STRING, FULL LOAD TESTS

Since the refrigeration compressors and drivers are the major factors in plant availability, string tests are commonly done for compressors and the dedicated driver in the manufacturer's shop. When the applied compressor, coupling, and driver are in few actual installations, a full load test will be needed. In such a case the test in the manufacturer's shop will take 2-3 months. Additional time needed for modifications necessitated by test results could be critical to the overall project schedule.

Nuovo Pignone has successfully achieved thermodynamic and full load tests for the propane compressor and MR compressors in its test stands for MLNG-2."

DYNAMIC SIMULATION

Making use of advancing computer technology, new LNG projects will carry out dynamic simulation for the anti-surge circuits of refrigeration compressors. The dynamic simulation will result in the required CV value of the antisurge control valve for the various operational cases of start-up, normal shut-down, emergency shut-down, etc.

FUTURE COMPRESSORS, DRIVERS

In a future LNG plant with train capacity of 4 million tons/year, the propane compressor will have a suction volume less than 190,000 cu m/hr, which has been achieved by Dresser's frame-913 for the Bontang LNG trains; therefore, there will be no difficulty for the impeller selection.

The suction volume of the LP MR compressor in such a large plant will be close to 300,000 cu m/hr, which has never been proved for a single flow centrifugal compressor. Therefore, a double flow arrangement centrifugal compressor or axial flow compressor will be considered.

The HP MR compressor will require the vertical split (barrel type) centrifugal compressor due to its pressure rating. The 45,000 kw MR compressor of the Adgas 1,2 train, which is Dresser's frame-813, will be a good reference for this application.8

The total power requirement for a plant this size will be around 160,000 kw, and the frame-5 application will be unlikely due to too many gas turbines being required. The probable gas turbine driver combination will be as shown in Table 7(11688 bytes).

EXPANDER APPLICATION

Replacement of the J-T valve by a liquid expander will improve thermal efficiency of the liquefaction cycle. The liquid expander will be applicable for J-T valves around the main heat exchanger for the LNG stream, subcooled MR liquid, and subcooled MR vapor.

The replacement will increase the LNG production rate by 3-4% although the J-T valve will still be required as a back-up for possible malfunction of the expander.

COOLING MEDIA SELECTION

By nature, the liquefaction process generates a large amount of heat rejection to the cooling media, selection of which affects not only the plant cost but also plant thermal efficiency. Selection of cooling media should receive careful study at early stages of an LNG project, including site selection. Cooling media for LNG projects are shown in Table 8(9744 bytes).

LNG STORAGE, LOADING SYSTEM

Since the LNG tank contains a large amount of flammable substance, the type of the tank is determined by not only cost but also safety considerations. In addition to plant location, circumstances that must be considered include earthquakes, soil settlement, impact load such as an airplane collision, blast wave, heat radiation, cyclones or tornadoes, external aggression, Place spontaneous failure of equipment or material.

The above-ground LNG tank is commonly used. The more expensive inground type is preferable at receiving terminals near heavily populated area's such as Tokyo Bay, because of its resistance to spills.

Table 9 (13759 bytes) shows common types of LNG storage tanks,.

As tank size increases, costs per unit volume decline. A tank capacity of 140,000 cu m is the maximum for common tank types. Total plant tank capacity is a function of traffic between slipping and receiving terminals.

LOADING SYSTEM

The LNG tanker usually requires a sea depth of 15 m and, since costs of loading line and the jetty/trestle are high, the selection of plant location is a key item for cost reduction. A loading time of 12 hr is common for current 125,000 cu m-class tankers.

AVAILABILITY

Plant availability is an important factor in reducing LNG costs. Two factors-scheduled and unscheduled shut-downs-can improve availability by being held to minimum levels.

SCHEDULED SHUT-DOWN

This is required for maintenance work such as government inspections, periodic inspection and maintenance of equipment, gas turbine inspection and overhaul, plant modifications, etc. Duration of these shut-downs can be reduced by:

  • Round-the-clock maintenance operation.

  • Computerized maintenance management systems for warehouse inventory, automatic reordering, material planning, maintenance work orders, preventive maintenance programs, equipment historical files, plant operation daily reports, etc.

  • Parallel equipment configuration, which allows for on-line maintenance.

UNSCHEDULED SHUT-DOWNS

This is not identified during the development of the annual maintenance plan and is caused by events such as instrument fault, exchanger/line leak, equipment corrosion, acid gas removal foaming, and human error.

Methods for reducing unscheduled shut-downs include fault tree analysis for plant components such as control valves and equipment, configurations that include parallel arrangement and redundancy, and operator training with simulators.

Current LNG plants have achieved availabilities exceeding 95% (Table 10)(9877 bytes).

TANKER SIZE, CHAIN OPTIMIZATION

To supply the LNG at low cost to the consumer, the total optimization of the LNG chain must be considered, including LNG tankers and receiving terminals. The distance from Ras Laffan, Qatar, to Japan is about 6,400 nautical miles, and the freight cost of LNG will be comparable to the liquefaction cost. Therefore, reducing the freight cost will be essential.

Increased tanker capacity will help cut freight costs. Around 80 tankers are in service in the world, ranging from 18,900 cu m to 137,500 cu in. Over 20 tankers, ranging from 125,000 cu m to 137,500 cu m, are under order or construction. A recent project considered a design for a tanker with a capacity of 165,000 cu m, which will be realized in the near future.

Typical physical dimensions of LNG tankers are shown in Table 11 (9767 bytes), including those for a tanker as large as 200,000 cu m, which ship builders have studied."

ACKNOWLEDGMENT

The assistance of Chiyoda Corp. personnel S. Tagashira, J. Sakaguchi, and S. Miyashita in the preparation of this article and in providing valuable information is gratefully acknowledged.

REFERENCES

1. Nagelvoort, R.K., Pool, I., Ooms, A.J., "Liquefaction Cycle Development, LNG 9 International Conference, 1989.

2. World Gas Intelligence, Mar. 11, 1994.

3. Kosseim, A.J., Markovs, J., Brookes, T., Homes, E.S., "New Development in Gas Purification for LNG Plants," LNG 10 International Conference, 1992.

4. Bogani, F., "Initial Experience with the NWS LNG Plant," LNG 10 International Conference, 1992.

5. Dwyer, D.L., Hlozek, R.J., "CO2 Removal with Ucarsol Solvents," GPA Gas Treating Seminar, 1993,

6. Soemantri, IL, Soeryanto, J., "Strategies for Handling Mercury and Related Problems in the Arun Plant," LNG 9 International Conference, 1989.

7. IFP catalogue for catalyst.

8. Liu, Y.N., Edwards, T.J., Gehringer, J.J., Lucas, C.E., "Design Considerations of Larger LNG Plants," LNG 10 International Conference, 1992.

9. Chin, C., "Evaluate Separation for LNG Plants,"Hydrocarbon Processing, September 1978.

10. Borchi, M., Maretti, A., "Testing of TurboCompressor Trains for LNG Plants," TurboCompressors for Large LNG Plants seminar, Nuovo Pignone, 1993.

11. Soeryant and Triyantno, J., "Availability and capacity improvement of the Arun LNG Plant," LNG 10 International Conference, 1992.

12. Oganowski, G., "LM6000 Aeroderivative Industrial Gas Turbine," 36th GE Turbine State of the Arts Technology Seminar, 1992. schedule," OGJ, Sept. 17, 1973.

14. Sutopo, H.M., "Availability and Efficiency Improvement of the Badak ENG Plant," LNG 9 International Conference, 1989.

15. Iversen, H.H., Borgaas, B., "What LNG Carrier Does the Market Need?" LNG 10 International Conference, 1992.

- De Karr, LA., Kluivers, G.H., Punt, A.R., "Advances in LNG Technology," LNG 10 International Conference, 1992.

- EEMUA, The Engineering Equipment & Materials Users Association U.K. Publication No. 147, Recommendation of The Design and Construction of Refrigerated Gas Storage Tanks.

- Ekstrom, T.E., Garrison, P.E., "Large Gas Turbines for LNG Refrigeration Process Application," LNG 10 International Conference, 1992.

- Harryman, J.M., Smith, B., "Sulfur Compound Distribution in NGLs," GPA 73rd Annual Convention, 1994.

- Jean, P., Biaggi, J.P., "A New Step in LNG Sea Transportation: The 200,000 M3 Gt Type LNG Carrier," LNG 10 International Conference, 1992.