REDUCE GREENHOUSE GAS EMISSIONS ACROSS THE LNG CHAIN

REDUCE GREENHOUSE GAS EMISSIONS ACROSS THE LNG CHAIN Chiu, Chen-Hwa, ChevronTexaco Energy Research and Technology Company Knaus, Chris, ChevronTexaco Energy Research and Technology Company Lewis, Craig, ChevronTexaco Energy Research and Technology Company 1. INTRODUCTION The LNG chain consists of the natural gas production, transportation to the baseload LNG plant, pretreatment and liquefaction of the natural gas for LNG production, LNG transport by oceangoing LNG carriers, LNG receiving and regasification terminal, and transportation to the end users such as electric power generation, industrial and domestic customers. Production and use of LNG can contribute to the reduction of greenhouse gas emissions. Not only can LNG production reduce the flaring and venting of associated gas from oil production, thus reducing the greenhouse gas emissions, but also the re-gasified fuel can be used in a high efficiency combined cycle gas turbine (CCGT) power plant, in lieu of coal, which would otherwise be most likely to be consumed for the power generation. Total life cycle greenhouse gas emissions from the use of LNG, spanning the complete LNG chain from production through to consumption, are markedly lower per unit of energy than traditional fossil fuels such as coal or fuel oil. However, there is still a potential across the LNG chain for further reducing greenhouse gas emissions. As international energy companies are increasing their participation in more and even all segments of the LNG chain, a systematic approach to the reduction of greenhouse emissions across the LNG chain can yield reduced emissions. 2. GAS PRODUCTION AND PRETREATMENT 2.1. Improved Acid Gas Removal Process The upstream production of natural gas and the bulk removal of high concentrations of CO 2 may provide an option to sequester CO 2 underground. The natural gas feed to the LNG plant usually contains a certain amount of CO 2. To avoid CO 2 freezing during the liquefaction process, the CO 2 is removed down to levels of about 50 ppmv, typically by a chemical solvent absorption process. The removed CO 2 is vented to atmosphere in all currently operating LNG plants. Some solvent processes co-absorb or entrain significant quantities of methane and heavier hydrocarbons as well. Sequestering all or part of the separated reservoir CO 2 could significantly reduce the amount of greenhouse gas emissions. The acid gas removal process is very energy intensive and any improvement in the conventional solvent absorption process by using new technology such as adding membrane contactor or separation devices, or cryogenic separation to reduce energy consumption will be welcome. 2.2. Waste Heat Recovery Most new LNG plants use large industrial gas turbines for both power generation and for direct drive of the refrigeration compressors. The use of waste heat recovery units on the gas turbine exhaust, to provide heat for acid gas removal solvent regeneration, molecular sieve dehydrator regeneration, and other plant heating needs, can reduce the greenhouse gas emissions and fuel consumption in place of using fired heaters. Usually these heating requirements represent around 5% of the total fuel requirements of the LNG plant. The benefits can be higher when treating high acid gas content in the feed gas. Although the capital cost of waste heat recovery systems is generally greater than that of direct fired heating systems, the added cost may be justified by the reduced cost of fuel and emissions. 3. CO 2 CAPTURE AND STORAGE 3.1. CO 2 Capture The two major sources of CO 2 emissions in LNG plants are the acid gas removal unit and the flue gas from the gas turbines used for driving refrigerant compressors and electric power generation. The removal of CO 2 from the feed gas is usually performed using solvent process of MDEA, Sulfinol

or others. There are other options such as membrane, cryogenic distillation, which may be considered [1]. There are several options for sequestering the CO 2 underground after the CO 2 capture. The removed CO 2 can be dehydrated, compressed, liquefied and injected for enhanced oil or gas recovery or underground storage. Capture of CO 2 from emission sources and storage in geologic strata is viewed as one of the leading technical options to sequester CO 2 underground, and thereby lessen the growth of elevated CO 2 concentrations in the atmosphere. There are a number of ongoing technology developments programs on CO 2 capture and geologic storage. Some governments are already taking action. In Western Australia, new greenfield operations or extensions must address greenhouse mitigation plans in their Environmental Impact Statement or other environmental review documentation. In offshore Norway, there is a so-called Carbon Tax of around US$38 per tonne of CO 2. The European Union has pending legislation for trading and taxing schemes. Canada recently ratified the Kyoto Protocol, and is pursuing and developing protocols for safe and effective storage of CO 2. In the United States, many companies are pursuing voluntary actions to reduce greenhouse gas emissions. 3.2. Geologic Storage There are several options for storage of CO 2 in geologic strata. One is enhanced oil recovery (EOR), where CO 2 has traditionally made attractive economic returns due to improved displacement efficiency and incremental oil production. There is a great wealth of industry experience over the past 30 years, in over 100 fields, mostly in the Permian Basin in Texas and New Mexico. Another option for CO 2 storage is injection in depleted oil and gas reservoirs. The option with the greatest ultimate geologic storage capacity is injecting CO 2 into deep, saline reservoirs. In Statoil s Sleipner Vest Field, offshore Norway, CO 2 is removed from the produced natural gas to meet pipeline specifications and is re-injected at a rate of about one million tonnes per year via a single horizontal well into a shallower formation. The Gorgon Gas Development in Australia plans to pursue a project to re-inject the reservoir CO 2, removed from the feed gas stream, into geologic strata. Plans to install the gas processing facility on Barrow Island provide a unique opportunity to re-inject CO 2 into saline reservoir, such as the Dupuy sands as shown in Figure 1 [2]. The Snøhvit LNG project in Norway [3] also plans to re-inject its reservoir CO 2 into a formation below the producing reservoir. Figure 1: CO 2 Re-Injection Scheme proposed for Gorgon Gas Development

4. PRIME DRIVERS OF BASELOAD LNG PLANT The refrigeration and gas recovery power requirements can account for up to 90% of the plant fuel gas consumption. Therefore, the selection of the gas turbines and combustion efficiency has a direct impact on the overall plant greenhouse gas emissions. Currently, a typical baseload LNG plant has one to three trains, with a feed gas rate per train at around 17 million cubic-meters per day and the LNG production rate per train at 500 t/h (4.2 MTPA). The fuel consumption is about 10% of the feed gas for LNG production. The power requirement per train is approximately 180 MW and the CO 2 emission per train is about 4,800 kg-mol/h. 4.1. Efficiency Improvements with Aero-Derivative Gas Turbines Most recent LNG plants have used industrial type simple cycle gas turbines, commonly called a Frame machine, to drive refrigeration compressors. Lighter duty, higher efficiency aero-derivative gas turbines have not been used in LNG refrigeration service, although they have been used extensively in electric power generation and some in pipeline compression facilities. Due to their low heat rates, use of aero-derivatives in place of the conventional Frame machines could reduce fuel consumption and associated CO 2 emissions by up to 20-30% with small increments in the total capital cost. For LNG plants, models such as the GE LM2500 or LM6000 can be considered. Aero-derivative turbines offer a significant reduction in fuel use and CO 2 emission rates compared to Frame machines due to their significantly higher efficiency. However, dry low NOx removal technology may be required for the aero-derivatives due to higher flame temperatures in their combustors and potential increased NOx emissions. Preferably, the LM6000 can be equipped with an air intake cooling system or water injection system to cool the inlet air to generate additional power for the refrigerant compressors. 4.2. Application of Combined Cycle Systems Recent improvements in technology have resulted in a thermodynamic efficiency close to 60% for a combined cycle power generation system. In a combined cycle, the waste heat from the gas turbine exhaust is used by a steam cycle to generate power or drive another turbine. The combined cycle system has been applied in the electric power industry. Greater reductions in fuel consumption and CO 2 emission rates may be achieved through the use of combined cycle power generation and electric motor drivers for LNG refrigeration compression. The added capital costs need to be evaluated and weighted against increased potential for improved efficiencies. They are also affected by the potential for increased economies of scale. It is possible to reduce fuel consumption and CO 2 emissions by 40-50% using combined cycle power generation in conjunction with electric motor driven refrigeration compressors in place of simple cycle Frame gas turbine drivers. This improvement would come at a significant increase in power machinery cost, and may be more attractive for large multi-train LNG complexes with total power requirements above 500 MW. Table 1 shows comparative data on typical Frame, aero-derivative gas turbines and combined cycle power generation arrangements [4]. 4.3. All Electric Drive System The entire LNG plant s electric power requirements, both for refrigeration compressor drivers and the balance of the plant can be provided by large generators in either the conventional gas turbine driven LNG plant or the combined cycle plant [5]. Large synchronous motors could be used to drive refrigeration compressors with speed-changing gears. The all electric drive option for baseload LNG plants has potential benefits of increased reliability and reduced maintenance cost for refrigeration compressor drivers, economies of scale for LNG train sizes larger than 5 MTPA, and elimination of separate, smaller gas turbine driven generators for the remaining plant electric power requirements. When a grid connection is available, an electric drive solution to a baseload LNG plant is becoming more attractive. Another advantage is that when the refrigerant compressors are driven by electric motors they can be restarted without depressurizing the casing, providing a faster restart following a trip or maintenance. Compressors driven by the single shaft Frame-6 or Frame-7 gas turbines need to be partially depressurized before restarts, resulting in loss of refrigerant inventory and additional flaring.

Model Gas Turbine Driver Frame Mechanical Drive ISO Rating, kw LHV Heat Rate, kj/kwh LHV Efficiency Relative CO 2 Emission 1F M5382C 28,337 12,309 29.3 1.03 2F M5432D 32,587 11,899 30.3 1.00 3F M6511B 37,800 11,120 32.4 0.93 4F M7111EA 81,557 11,022 32.7 0.93 Aero Mechanical Drive 1A LM2500+ 31,319 8,757 41.1 0.74 2A Coberra 6761 33,482 8,994 40.1 0.76 3A LM6000PC 44,619 8,452 42.6 0.71 4A Trent 800 DLE 52,549 8,479 42.5 0.71 Combined Cycle Power Generation S-206FA 2xMS6001FA 218,700 6,652 54.1 0.56 S-207FA 2xMS7001FA 529,900 6,373 56.5 0.54 2x1 701F 2xM701F 799,600 6,283 57.3 0.53 Table 1: Typical Gas Turbine Performance and Relative CO 2 Emission 5. APPLICATION OF LIQUID EXPANDERS 5.1. Liquid Expander Application in LNG Plants Cryogenic turbines expand liquefied gases from high pressure to low pressure converting the hydraulic energy into electrical energy to reduce the enthalpy of the liquefied gas and to recover energy. In conventional baseload LNG plants, liquid expanders are applied to the mixed refrigerant circuit and the LNG product circuit as shown in Figure 2. For LNG expanders installed between the main heat exchanger and the atmospheric pressure LNG storage tank, a variable speed liquid expander can be used also as a control valve to increase the process efficiency. Since 1996 many LNG plants have replaced the JT-valve with a cryogenic turbine to expand the condensed natural gas from high pressure to low pressure, and substantially improved the thermodynamic efficiency of the existing refrigeration process, contributing to an increase of the total LNG output by about 6% and also a reduction of the greenhouse gas emissions. Liquid expanders are typically applied to the heavy mixed refrigerant stream and the LNG stream from the cryogenic heat exchanger for the Air Products Propane Precooled Mixed Refrigerant process. More applications are anticipated in the future for other LNG processes, such as the Linde Multiple Fluid Cascade and Phillips Optimized Cascade processes. The advanced technology of LNG expanders was developed in the mid-1990 s. The first generation of basic turbine generator was used in LNG plants at Bintulu, Malaysia and in Nigeria. LNG expanders of the second generation used variable speed constant frequency converters and offer significant advantages over the basic fixed speed designs. Several variable speed liquid expanders in the power range of 1 MW are already in successful LNG plant operations. The current size is between 1.5 to 2 MW. The installation of variable speed LNG expanders enables the direct interaction between the liquefaction process and the LNG expander with the possibility to optimize the liquefaction over a wide range of LNG output [6]. Process and expander are interactively linked together to control the LNG output. The third generation of LNG expanders is in development. The

target is to expand cryogenic liquid partially into the vapor phase, while operating the expander in the two-phase region, to improve the cycle efficiency. Figure 2: Liquid Expanders Application in a Typical LNG Process using a Propane precooled Mixed Refrigerant Cycle 6. LNG CARRIERS 6.1. Current LNG Carrier Propulsion The current LNG carriers have usually retained traditional steam turbine propulsion. Its advantages are low maintenance and the ability to burn any mixture of heavy fuel oil (HFO) and the boil-off gas (BOG). However this system has the disadvantages of high fuel costs and excessive CO 2 emissions due to the low energy efficiency of the steam turbine plant. 6.2. Improved Propulsion and BOG Reliquefaction The dual fuel diesel-electric propulsion system, besides being more flexible in fuel choice, has been found to have a higher thermal efficiency of around 40% compared to the typical efficiencies on the order of 30% for a traditional steam turbine propulsion system. A diesel-electric LNG carrier fitted

with a BOG re-liquefaction unit will be the promising solution for future LNG carriers, with reduced emissions of greenhouse gas (CO 2, NOx and SOx) [7]. 7. LNG RECEIVING TERMINAL 7.1. Cold Energy Recovery Measures for cold energy recovery from LNG regasification may be considered. Cold energy of LNG could be recovered using an intermediate fluid such as propane to assist generation of electricity for in-plant use, thus reducing the burning of natural gas for power generation and also the CO 2 emissions. This practice can be further extended to the use of LNG cold energy for assisting adjacent air separation and other plants that require assistance in refrigeration [8]. Precooling the air intake to the CCGT with LNG cold is a possible means for increasing the efficiency and the power output of the gas turbine. However, this would require that the CCGT and LNG terminal be adjacent to each other. The temperature of the gas turbine inlet air affects the gas turbine efficiency and power output considerably. The LNG cold can be utilized to cool the inlet air to the gas turbine [9]. This benefit is more evident if the CCGT plant is located in warm to tropical climate areas. Again, assessing the local need for power generation or other plants not related to the LNG terminal, along with the capital costs and reliability reduction for this energy integration against the value of increased efficiency and reduced emissions ought to be conducted on a project specific basis. 7.2. Flare Reduction Flaring might be occurring during the unloading operation of LNG if the total recovery or use of excessive BOG is not possible. Options such as direct compression of BOG into the pipeline or onsite power generation using BOG may be considered. Capital cost of additional equipment required and operational aspects of peak BOG rate variations need to be evaluated for these flare reduction measures. 8. CONCLUSIONS This paper examines various technologies available to each segment of the LNG chain for minimizing the greenhouse gas emissions. The greenhouse gas emissions have the potential to be reduced through the proper application of best available technologies. However, the life cycle cost evaluation of the available options for reducing greenhouse gas emissions in each LNG segment will ultimately determine which technologies are economically sound for a particular project in the LNG chain.

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