A NOVEL DESIGN FOR MTPA LNG TRAINS

Transcription

1 A NOVEL DESIGN FOR MTPA TRAINS Sander Kaart Wiveka Elion Barend Pek Rob Klein Nagelvoort Shell Global Solutions International B.V. P.O. Box 541, 2501 CM The Hague, The Netherlands ABSTRACT Shell believes, along with many others, that the projected growth in markets will translate into a demand for larger train sizes. This is primarily driven by economies of scale in terms of equipment costs, construction costs and project management. In this paper, we present a new design for a large train producing at a rate of about 11 Mtpa. The design is based on Shell s Parallel Mixed Refrigerant process, includes CO2 and sulphur treating, and will be flexible to reach heating values down to typical US specifications. Using large yet fully developed and proven gas turbines, and other key equipment, maximizes economies of scale. Care has been taken to retain multiple sourcing options for all equipment. Steam is used to integrate heat generation and demand plant-wide; this includes the waste heat recovery from the gas-turbine drivers, co-firing, and heat demand of the energy intensive treating train and heat production by the sulphur-recovery unit. The heat recovered is utilized for process heating and to produce mechanical and electrical power. The full utilization of waste heat from the gas-turbine exhausts enables a step-change in plant efficiency and reduces the specific CO 2 emissions considerably, compared to conventional plant design. In this paper, conceptual design choices are presented, followed by a description of the waste heat recovery system, key equipment considerations and a summarizing discussion. Shell Global Solutions is a network of independent technology companies in the Shell Group. In this material the expression 'Shell Global Solutions' is sometimes used for convenience where reference is made to these companies in general, or where no useful purpose is served by identifying a particular company. The information contained in this material is intended to be general in nature and must not be relied on as specific advice in connection with any decisions you may make. Shell Global Solutions is not liable for any action you may take as a result of you relying on such material or for any loss or damage suffered by you as a result of you taking this action. PS2-3.1

2 INTRODUCTION The fast growing world demand for clean and affordable energy translates into a large increase in production capacity in the next decade. At Shell, we see demand for natural gas growing by some 3% a year over the next 15 years, with demand for liquefied natural gas growing by some 8-10% a year [1]. The large number of projects underway has resulted in a constrained contractor market, a worldwide heavy demand for raw materials as well as issues around logistics of work force and products. These challenges call for large trains, particularly where large resources are involved as in the Middle East, Russia, Nigeria and Australia. Shell and others have already increased train sizes in recent decades from 1 Mtpa to 8 Mtpa, primarily driven by the desire to reduce capital expenditure. Application of large trains will also help to use the available contractor capability more effectively. Minimizing the effect of the CO2 emission rates from this increased liquefaction activity will require focus on efficiency of processes and drivers. In addition, novel approaches like CO2 sequestration are being considered. This paper presents a train design for the production of 11 Mtpa. The design is based on Shell s Parallel Mixed Refrigerant Process (PMR) with propane refrigerant in the pre-cool cycle (C3/PMR). A typical Middle East sour gas (Table 1) has been assumed for the concept development. A plant-wide integration of heat generation and demand is provided by steam. The full utilization of waste heat from the gas turbine exhausts enables a step-change in plant efficiency with respect to conventional plant designs and reduces the specific CO 2 emissions considerably. Table 1. Feed gas composition Component Composition [mol%] Methane 84 Ethane 5 Propane 2 Butanes 1 Higher Hydrocarbons 1 Nitrogen 4 Carbon dioxide 2 Hydrogen Sulphide 1 Mercaptans 500 ppm Beyond the design presented in this paper, there will be developments for which a smaller train capacity is more suitable; in particular, where gas reserves are limited, when there is a capital constraint, or when market opportunities are uncertain. The concept described in this paper is fully scalable from 11 to 6 MTPA by changing helper motor size or changing to smaller gas turbines. We are continuously improving our portfolio of processes (Figure 1) including small trains and offshore liquefaction plants [5-8]. The improvement of fuel efficiency by waste heat recovery is applicable to several designs, thus minimizing CO2 emissions. PS2-3.2

3 E- drive 4 x 4 E-drive x E - Drives PMR DMR - 3 x Electrical Drives PMR 3 x identical mechanical drivers DMR 2 x GE F7 or equiv. C3/MR 2 x GE F7 or equiv. Workhorses Capacity [Mtpa] CONCEPTUAL DESIGN CHOICES Figure 1. The Shell portfolio For the liquefaction, Shell s proprietary Parallel Mixed Refrigerant Process [11] has been selected, consisting of a 4 stage propane pre-cooling (C3/PMR), two parallel mixed refrigerant circuits followed by a common nitrogen rejection unit combined with an endflash system (Figure 2). This process conceptually provides higher efficiency than alternative 3 cycle processes, which translates into a higher production for fixed capital costs. Feed From Well CO2 Sulphur Gas Landing Treating & Dehydration Sulphur Recovery Condensate Stabilization GT Fuel Gas Field Condensate NGL Extraction Pre-cool cycle MR cycle End Flash storage ST MR cycle GT Frac. LPG Treating LPG Refrig Plant Condensate Figure 2. Process Block scheme The design presented in this paper is based on air-cooling, as this is well proven even in tropical climates and independent of the marine environment. Dedicated attention to hot air re-circulation and plot plan optimization will provide a robust design. Should cooling LPG PS2-3.3

4 water be available for a once through or re-circulating cooling system, this can be easily incorporated and will further improve fuel efficiency and, depending on cooling water supply complexity, also the specific cost. The design is suited to handle the CO2, H2S and mercaptans present in the feed gas, and it contains front-end LPG extraction, allowing a flexible HHV value down to the Btu/scf often required for US markets. The front-end NGL extraction unit also allows maximum refrigeration power and optimum liquefaction pressure. In an optimization like this, it is important to consider the full interaction of process units, from slug-catcher up to loading facilities. To meet the challenge of a CO2 constrained world as well as rising fuel value, the design was fitted with full waste heat recovery. All turbines, both in power generation and in liquefaction, are fitted with steam generating heat recovery systems (HRSG). The system is then optimized with respect to the use of this steam as process heat as well as for mechanical power and electricity generation. TREATMENT FACILITIES An integrated and optimized solution has been selected to remove acid gas components and mercaptans from the feed gas (Figure 3). Details regarding the optimization process have been described elsewhere [2-4]. Not surprisingly, total CAPEX for the removal of the contaminants is minimized if the acid gas removal unit (AGRU) and the molsieve unit (MSU) for dehydration and mercaptan removal are optimized as a single unit. It appears that Sulfinol-D is a very good solvent for this particular feed gas composition. MSU Treated Gas AGRU Absorber mixed MSU Regen Absorber mixed AGRU Regen. mixed Feed Gas AGEU Regen. aqueous AGEU Absorber aqueous Sulphur SRU Incinerator TGT aqueous Flue Gas Figure 3. Treating scheme The regeneration of the acid gas solvents from the AGRU and acid gas enrichment unit (AGEU) consumes low-pressure steam. The sulphur recovery unit (SRU) produces PS2-3.4

5 medium-pressure steam. Unconverted hydrogen sulphide is removed from the SRU tail gas in the tail gas absorber (TGT). After treating and mercury removal, the dry sweet natural gas is sent to a dedicated NGL extraction unit. NGL EXTRACTION FACILITIES The NGL extraction unit is based on the proprietary Shell Deep LPG extraction process (SHDL). The SHDL process (Figure 4) is a robust and flexible extraction scheme that yields high LPG recoveries for a large variety in feed gas compositions. For this study the SHDL process allows LPG recoveries up to 99% without requiring external refrigeration for the considered feed gas. With these high recoveries, HHV specifications of less than 1070 Btu/scf can easily be met. Booster Compressor Lean Natural Gas Rich Natural Gas External Refrigeration Figure 4. Shell Deep LPG extraction process Light Condensate High pressure treated and dried rich natural gas is first pre-cooled and partially condensed in a series of heat exchangers against lower pressure cold lean natural gas. The heat exchange with external refrigeration is optional in the scheme and is not required for the feed gas conditions discussed in this paper. After separation of the liquid from the partially condensed natural gas stream, the high-pressure vapor is expanded through an expander; this drives the re-compressor of the lean low-pressure natural gas stream. This expansion produces the required refrigeration to obtain the reflux for the de-ethanizer column and pre-cool the rich natural gas stream. The lean natural gas first pre-cools the rich natural gas and is then compressed by the expander driven re-compressor. A separate booster compressor further raises the lean natural gas pressure to the maximum allowed by the 600 lbs piping class. This integration of the NGL and liquefaction units maximizes LPG and production within equipment and power constraints. PS2-3.5

6 LIQUEFACTION Shell developed the Parallel Mixed Refrigerant (PMR) Process [11] to meet the challenge of the industry for larger train sizes. The interim temperature between pre-cooling and liquefaction is an important design parameter. Correct selection of this temperature balances the utilized power between the pre-cooling and the liquefaction cycles to the thermodynamically favored 1:2 ratio for the C3/PMR process. The ability to tune the power balance exactly to the installed mechanical refrigeration capacity in the C3/PMR process is an advantage over the conventional C3/MR process, where power requirement of the cooling cycles cannot be balanced with two equal sized gas turbines. Application of Shell s end flash system with nitrogen rejection [12] and a scheme to recover cold from the end-flash gas using lean natural gas have been integrated in the design. Figure 5 shows a schematic representation of the combined nitrogen rejection and end-flash system. Prior to expanding the high-pressure liquid natural gas over the expanders, it is first further sub-cooled against a liquid fraction of the expanded. The vapor thus produced, is used to strip low boiling point components (i.e. Nitrogen) from the. End Flash Gas Liquefied NG Figure 5. N2 stripper line-up [12] The parallel line-up of the liquefaction cycles improves the on-stream reliability of the train since the production can be designed to continue at 60% of the train capacity when one of the liquefaction cycles trips. Moreover, it allows high production capacity with only two refrigeration cycles in series, compared with the alternative of three cycles in series. This limits pressure drops and the number of cascades between cycles, and thereby again improving efficiency of the PMR process compared with other 3-cycle processes. With a single pre-cooling cycle and two parallel mixed refrigerant cycles, the capacity of the PMR process can be boosted up to 8.5 Mtpa in a tropical climate, when using 3 GE- Fr7 compressor drivers. The process can either use propane or mixed refrigerant in the pre-cool cycle. The well-proven refrigerant cycles can be used and the design can be applied today, without step changes in technology. With larger drivers like GE Fr9 or PS2-3.6

7 Siemens V94.2 gas turbines, capacity can be further increased up to 11 Mtpa, still within normal pressure drop constraints and equipment sizes. FULL, INTEGRATED WASTE HEAT RECOVERY The required process heat will largely depend on the concentration of acid gas contaminants in the feed gas and typically steam at low pressure will be required to provide the heat required for the regeneration of the acid gas solvent. Depending on the exact amount of high-pressure steam generated from gas turbine exhaust and lowpressure steam required by the regeneration process, the high-pressure steam could be utilized in backpressure or condensing steam turbines to generate power, either electrical or mechanical. This choice results from a detailed optimization that also considers other factors such as plot layout, sparing philosophy and the overall number of trains included in the development Low quality heat Heat and Power from Fuel [%] Process Heat Power CST & BPST BPST More Fuel Combined Heat and Power Generation improves overall fuel efficiency Heat to Power Ratio [MWProcessHeat/MWpower] Figure 6. Heat and Power integration The required process heat relative to the power requirement, determines the maximum potential fuel efficiency of the total process. Figure 6 illustrates this for a simple example system, based on the waste heat recovery from a 33% efficient gas turbine. Part of the heat contained in the gas turbine exhaust can be recovered to generate high-pressure steam. The high-pressure steam can subsequently be converted into LP steam and power by expansion through a backpressure steam turbine (BPST). Alternatively, a condensing steam turbine (CST) can be used to produce power and low quality heat that is of no further use to the process. In this simplified example, up to a heat-to-power ratio of 1.2, expanding part of the high-pressure steam through a BPST and the rest through a CST can generate all the required process heat. The exact limit will depend on many factors, like selected pressure levels in the steam system and gas turbine exhaust gas temperature. PS2-3.7

8 At higher required heat to power ratios, the need for heating steam prevents the use of CST s to generate power and only part of the steam can be expanded in a BPST. Another transition point occurs when no further power can be recovered from the steam. In the example of figure 6, this occurs at a heat-to-power ratio of 1.7, a value largely dictated by the gas turbine efficiency and process heat temperature levels. If even more heat is required, additional fuel will be required to generate this. For the case studied in this paper, the required heat to power ratio is below 1 and hence the produced HP steam can generate a significant amount of additional driver power. The propane compressor driver can be replaced by a steam turbine (Figure 7). This option has a distinct availability advantage in comparison with a gas turbine drive. The PMR train can continue to run at about 60 % of capacity while one of the GT-driven MR circuits is out for maintenance or has tripped due to an unscheduled event. Combining this feature with the low maintenance requirements of a steam turbine provides a significant increase in availability for this option. In addition, the variable speed of the steam turbine extends the operating window for the propane compressor. PROCESS E-Power - Fuel M FR9 MR Compr M FR9 MR Compr PR Compr GT Power Generation HPS SRU Booster ST Power Generation MPS LPS AGRU / FRAC. Condensate Figure 7. Example: Plant wide integration of heat and power An alternative would be to keep the three process turbines intact, but use the steam to generate electricity and minimize the helper power generated by the gas turbines. Obviously the start-up needs to be taken into consideration. To handle start-ups, additional boilers or some GT power generation may need to be included. A second alternative is to power smaller drivers by steam, like the booster compressor, the end flash compressor or helper motors. This would require a quite extensive steam infrastructure. In Figure 8, the CO2 emission from fuel of the current air-cooled design is compared with the performance of some base project train designs as published in 2003 [9]. For reference, Figure 8 also includes the result of the conventional air-cooled C3/PMR design PS2-3.8

9 with limited waste heat recovery. Proper optimization of the fuel and the steam balance can achieve a reduction of some 30% in fuel consumption; this results in a very competitive specific fuel CO2 emission from fuel of 0.21 ton CO2 /ton, for the aircooled train in a tropical climate with sour feed gas. The waste heat recovery and steam generated power contributes to environmentally sustainable development, and where fuel has a high value or CO2 trading rates apply, may give good pay-back. The result for the conventional air-cooled PMR process is very similar to the values shown in Figure 8 for the water-cooled base projects in Qatar, operating at similar gas compositions. This clearly illustrates the high efficiency of the PMR process, taking into account that a water-cooled version of the PMR process would show a further efficiency increase of up to 8 percent. Emissions, ton CO2/ton Qatar gas Ras gas Atlantic Nigeria Oman -30% Large Conventional Train Design Figure 8. Specific CO2 emissions compared [9] KEY EQUIPMENT CONSIDERATIONS Economies of scale and reliability call for the use of state of the art gas turbines. When aiming for capacities of around 11 Mtpa, high power output gas turbines should be considered, like the GE Fr9 or Siemens V94.2. Compressors able to absorb the high shaft powers are available from several vendors. It is however essential to define the exact design parameters in discussion with vendors, rotating equipment specialists and process designers. The lower rotational speed (3000 rpm) of the Fr9 and V94.2 machines allows for higher volume flows than the 3600 rpm required in F7 based designs. In addition, we apply the proprietary SplitPropane process [10] that allows higher propane circulation within the volumetric flow constraints of the compressor wheels. PS2-3.9

10 M GT LP MP HP HHP Figure 9. SplitPropane line-up As the PMR process utilizes two parallel mixed refrigerant circuits, pressure drop or cryogenic exchanger limitations are not experienced. The required spiral wound heat exchangers are well within existing manufacturing capabilities. In depth process development work shows that with high but realistic constraints for compressor suction flows and MCHE area, capacities of 11 Mtpa can be realized. The remaining equipment is also proven. CONCLUSION In this paper we have introduced a novel design for a very large train with the following characteristics: Capacity of 11 Mtpa Economies of scale both with respect to capital as well as operational costs Proven equipment High availability, provided by the steam driven propane compressor Fuel consumption some 30 % lower than open cycle based designs The key to achieving this is the ability to assess and utilize the full capabilities of, in particular, rotating and heat exchange equipment. Secondly, a full understanding of the complete process, including treating and LPG extraction, is required to provide optimal heat recovery. The start-up and operation of this large plant is comparable to conventional designs. The designs of the waste heat recovery and electrical system need to be robust against start-up and trip scenarios. While absolute costs are difficult to predict in today s overheated contractor market, we are utilizing full economies of scale for all equipment items. At the same time, care has been taken not to rely on a single vendor for any of the equipment. The high efficiency of the PMR design makes optimal use of expensive turbine power to generate. This design for an 11 Mtpa train represents another major technology step that will meet the world s need for in the coming decades. PS2-3.10

11 REFERENCES CITED [1] Linda Cook, Forging strong Links enabling the global expansion of natural gas, SPE Technical Conference, Dallas 10 th October (2005) [2] J van de Graaf, J. Klinkenbijl, Optimized treating configurations for the combined removal of H2S, CO2 and mercaptans from Natural Gas for and GTL applications, GPA, San Antonio (2004). [3] J. Klinkenbijl, H.F. Grootjans, Best Practices for deep treating sour natural gasses (to and GTL), GasTech, Bilbao (2005). [4] E. Bras, G van der Zwet, J. Klinkenbijl, P. Clinton, Treating Difficult Feed gases to Plants, -15, Barcelona (2005). [5] J. van de Graaf, B. Pek, Large-Capacity Trains The Shell Parallel Mixed Refrigerant Process, Review (2005). [6] B. Pek, A van Driel, E de Jong, R. Klein Nagelvoort, Large Capacity plant Development, -14, Qatar (2004). [7] M. Pesaud, G. Chamberlain, S. Kauffman, Safety drivers in the lay-out of Floating Plants, AIChE New Orleans (2003). [8] C. Groothuis, Fletcher, R. Klein Nagelvoort, Changing the Game, -13, (2001). [9] C. Yost, R. DiNapoli, Benchmarking study compares plant costs, Oil & Gas Journal, April 14 (2003) pg [10] H.F. Grootjans (Shell), Compression Apparatus for gaseous refrigerant, US Patent No. 6,637,238 (2003). [11] R. Klein Nagelvoort (Shell), Plant for Liquefying Natural gas, US Patent No. 6,389,844 (2002). [12] W.E. Elion, R. Klein Nagelvoort, J. Vink, Reducing the amount of components having low boiling point in Liquefied Natural Gas, US Patent 6,014,869 (1998). [13] C. Buijs, W. Dam, E. de Jong (Shell), Method and Apparatus for Liquefaction of a Natural Gas stream, Patent application WO (2006). PS2-3.11