Fiber Adsorbents for Odorant Removal from Pipeline Grade Natural

Apr 2, 2014 - Removal of the odorant tert-butyl mercaptan (TBM) by selective adsorption with fiber sorbent modules and removal with pellet packed beds...
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Fiber Adsorbents for Odorant Removal from Pipeline Grade Natural Gas Grace Chen, Ryan P. Lively, Christopher W. Jones,* and William J. Koros* School of Chemical & Biomolecular Engineering, Georgia Institute of Technology, 311 Ferst Drive, Atlanta, Georgia 30332-0100, United States S Supporting Information *

ABSTRACT: Sulfur odorant removal from pipeline natural gas can prevent or delay corrosion in gas turbines to increase their lifetime and efficiency. Removal of the odorant tert-butyl mercaptan (TBM) by selective adsorption with fiber sorbent modules and removal with pellet packed beds are compared in terms of capital and operating costs. Capital costs are estimated based on sizing the equipment items needed for each system, which varies depending on the regeneration gas used. Operating costs are estimated based on the utilities needed to run each system, again varying depending on the regeneration gas used, and also on whether heat integration is considered. Using a fraction of the product gas for regeneration is safer, simpler, and more economical than compressed air or nitrogen. Due to the need for more adsorber beds to process the same amount of TBM-containing pipeline natural gas, the capital cost associated with the pellet packed bed system is significantly higher than that of the fiber sorbent system. Heat integration with the sorption system by using the energy generated from waste gas combustion to produce steam dramatically decreases the operating cost by reducing the parasitic load. Overall, this process analysis shows that the fiber sorbent system with heat integration can be an attractive technology compared to packed bed systems for TBM removal.

I. INTRODUCTION Increasing global demand for energy, coupled with energy sustainability and environmental concerns, has encouraged a conversion from coal-fired power plants to natural gas fueled power plants for electricity generation in the United States.1,2 Natural gas plants often employ combustion gas turbines in a combined cycle with steam turbines to transform mechanical energy into electricity. While there is an ample supply of pipeline natural gas for this application, the combustion of trace amounts of sulfur odorants such as tert-butyl mercaptan (TBM) present in the fuel (typically 10 ppm or less) with alkali material (typically salt) from the environment results in a corrosive residue that reduces the lifetime and overall efficiency of the gas turbine.3,4 Several corrosion prevention strategies have been proposed to extend turbine lifetime, including removing alkali material from the air, using corrosion resistant alloys in the turbine, reconditioning corrosion-affected areas, and removing sulfur compounds from the natural gas.3−5 Desulfurization of pipeline natural gas before it is fed into the turbine offers a simple, continuous, and flexible way to mitigate corrosion. Some of the difficulties associated with sulfur removal from pipeline natural gas include the large amount of high pressure gas that needs to be processed as well as the ultralow concentrations of odorants generally present. Traditionally, in hydrocarbon applications, sulfur removal has been done with techniques such as catalytic hydrodesulfurization (HDS) and selective catalytic oxidation (SCO).6 However, these processes are very energy intensive due to the need to operate at high temperatures and pressures, and HDS is not as suitable for low concentration systems.7,8 Selective adsorption has been gaining increased attention for the desulfurization of natural gas because of its ability to operate at low temperatures and pressures. © 2014 American Chemical Society

Some common solid sorbents used in selective adsorption of sulfur compounds from fuels include ion-exchanged or metalcontaining zeolites, supported metals, metal oxides, metalcontaining aluminum oxide, activated carbons, and modified mesoporous silica.9−12 Zeolites are attractive sorbents due to their large pores and surface area, polarity, high thermal stability, and surface sites that lead to high capacities for sulfur removal. Zeolites X, Y, ZSM-5, and USY have all been used successfully in many studies for adsorbing various sulfur compounds from different fuels.13,14 Zeolites can be easily regenerated with heat or vacuum, and can be pressed into pellets for use in a fixed bed or spun into fibers for use in a fiber module.15,16 Much of the previous work in the area of odorant removal from pipeline natural gas has been for the purpose of providing ultralow sulfur fuel for fuel cells, and has focused extensively on the development of suitable sorbents.17,18 However, the overall process design and economic feasibility of a sulfur adsorption system for a high volume application as in gas turbines has not been considered. In this work, we have considered the capital and operating costs associated with fabricating and implementing a fiber sorbent system for TBM removal from pipeline grade natural gas. The effectiveness of a fiber sorbent system was compared with a traditional pellet packed bed adsorber system in terms of pressure drop and mass transfer resistances, and the systems were optimized around these physical aspects. Once an acceptable design was created for each system, their capital and operating costs were compared to each other, and Received: Revised: Accepted: Published: 7113

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finally compared with the cost of premature turbine replacement due to corrosion without such a system. Several regeneration and heat integration options were considered for each system, and are presented in this paper. Often the biggest impediment to the implementation of lab-scale technologies at commercial scale is cost. This current study seeks to provide evidence that low-cost sulfur removal from pipeline natural gas is possible with the use of fiber sorbents and heat integration.

specifications, safety considerations, available space, and a balance between capital and operating costs. Figure 1 shows the adsorption, regeneration, and cooling steps that comprise one full TSA cycle in a fiber sorbent

II. BACKGROUND Fiber sorbents are organic−inorganic composite materials that can be made using a dry-jet, wet-quench technique to incorporate a powder adsorbent such as a zeolite into a continuous porous polymer matrix with desired gas separation properties.19 In many cases, these fibers are made hollow, with a barrier layer added to either the lumen or shell side of the fiber after spinning.20 This barrier layer allows for a heating or cooling fluid to be passed on one side of the fiber for temperature control while the feed gas is passed on the other side.21 However, in this odorant removal case with trace amounts of an adsorbing species in an otherwise inert gas feed, the overall heat of adsorption is so low that the fibers stay nearly isothermal during the sorption step without the use of a cooling fluid. In this case, the fibers can be spun as solid f ibers instead of hollow f ibers with hot and cool inert gas streams as the heating and cooling media for regeneration. In this study, the fiber sorbents were assumed to be created from zeolite 13X crystals, which have a high capacity for sulfur species, spun with cellulose acetate (CA) polymer. Both of these materials are commercially available at large scale with reasonable cost, and CA fibers embedded with 13X have been successfully created in previous studies.22 Fiber sorbent modules can offer several advantages over traditional beds packed with spherical pellets. One of the most important advantages of the fiber approach is a lower pressure drop across the bed.23 This is important for maintaining the high delivery pressure of the pipeline natural gas, so that no additional pumps or compressors are needed to feed the treated gas to the gas turbine, therefore reducing the operating cost. Another potential advantage is faster heat and mass transfer equilibration times due to the smaller critical dimensions that can be achieved for fibers as well as a more uniform flow path.24 The above advantages are valuable for high flow rate applications such as pipeline natural gas where large volumes of gas must be processed quickly and continuously. Because of the more uniform flow path in a fiber module as compared with a pellet packed bed, channeling and dead spaces within the fiber bed are minimized.25 For sorbent regeneration, a thermal cycling method commonly referred to as temperature swing adsorption (TSA) is ideal for feed gases with low concentrations of adsorbate,26 and full regeneration of faujasite type zeolites is possible in various regeneration media. Alternatively, a pressure cycling method known as pressure swing adsorption (PSA) can be used; however, for such a high pressure, high flow rate, and low concentration system as in pipeline natural gas, this option would probably be expensive due to the significant vacuum that would be required for desorption and the subsequent repressurization that would be needed.27,28 For TSA, hot purge gases including air, nitrogen, a fraction of the purified hydrocarbon feed gas, and steam (with a barrier layer) have all been successfully employed for regeneration of zeolite sorbents.20,29−33 The final choice depends on process

Figure 1. Schematic of the inlet and outlet streams of a solid porous fiber bed cycling through the continuous steps of adsorption and desorption.

module. The top left bed shows the first step, adsorption, where pipeline natural gas (assumed to contain 10 ppm TBM in methane) is fed at the inlet of the module while treated product gas exits on the opposite end. Real pipeline grade natural gas is highly processed to remove much of the water and acid gases that are naturally present in the raw natural gas; however, trace amounts of water, CO2, and H2S may still be present. These species would preferentially be adsorbed over TBM in 13X, such that this material might not practically be used in the real system without either pretreatment of the gas or 13X modification. These costs are not considered in this proof-ofconcept paper focusing on system configuration, but it would be reasonable to assume that an additional guard bed or selective membrane for dehydration and CO2 removal could be added into the TBM removal process. Another option to be considered in an upcoming paper is the use of more hydrophobic and selective materials rather than 13X. The top and bottom right beds in Figure 1 show the second step, regeneration, where hot regeneration gas is fed at the inlet. Initially, the regeneration gas will displace the interstitial gas left over from the adsorption step. Then, the fibers will be heated to the desorption temperature of 90 °C by the hot gas (at 120 °C) and TBM will be desorbed and carried out of the bed as a TBM-rich waste gas stream. This low desorption temperature was chosen so that a more economical polymer could be used for fiber creation and the system could employ a smaller temperature swing, which in turn lowers the capital and operating costs of the system. The TBM-rich waste gas is then simply burned, and the heat can be recovered for productive use. The bottom left bed shows the third and final step, cooling, where cooling gas is fed at the inlet of the bed to return the fibers to the adsorption temperature while the same cooling gas simply exists at a higher temperature. In designing a fiber module adsorption system for odorant removal from pipeline natural gas, many essential parameters that affect key optimization points, such as system geometry, 7114

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their TBM saturation capacity. This was directly related to the mass transfer resistances present in the two types of beds and limited the superficial velocities at which the natural gas feed could enter the beds. All cost estimates are reported in terms of 2011 U.S. dollars.

fabrication, and operation, must be considered. A cost-effective, simple system with a low pressure drop, high heat and mass transfer rate, and low fiber temperature rise due to the heat of adsorption was desired. To minimize the pressure drop down the module, fibers with a diameter of 300 μm and a length of 1.4 m were used in this analysis. Additionally, these fibers were assumed to be spun with a porosity of 0.44 and a zeolite 13X loading of 75 wt % to make the fibers as efficient as possible. Fibers with such characteristics have been successfully created in previous studies.22 Contact or residence time is also important to ensure the TBM odorant will have sufficient time within the bed to be adsorbed by the fibers. This is controlled by the total crosssectional area of the modules through which the pipeline natural gas feed will flow. The fibers were assumed to be bundled together in cylindrical beds employing a parallel flow pattern. For this study, a module diameter of 0.4 m and a module void fraction of 0.35 were used, making the effective cross-sectional area of one module approximately 0.04 m2. These dimensions allow the fibers to be close enough together to minimize the effects of external (or bulk) mass transfer resistance.34 An 85 MW General Electric 7EA gas turbine was used as the basis for the TBM removal system. From the specifications of this turbine, the adsorption system was assumed to need to process 15 000 scfm pipeline natural gas feed at a concentration of 10 ppm TBM at 250 psig and 30 °C. As there is a range of odorant concentrations in real pipeline natural gas, this TBM concentration of 10 ppm was chosen as the upper limit, or the maximum concentration that an adsorption system would have to handle. To handle this large amount of natural gas, the incoming stream was assumed to be split among three fiber sorbent modules in parallel for the adsorption step. For this configuration, one additional fiber module was necessary for the process to be continuous. This module would run in phase with the other three active modules, and be in desorption mode (regeneration and cooling steps) while the other three modules are in adsorption mode. Staggered start-up and careful timing of these modules, as shown in Figure 2, would ensure the four beds are active at all times with three beds in adsorption and one bed in desorption. The specifications for the 85 MW turbine were also used as the basis for the design of an equivalent pellet packed bed system for comparison. The two technologies were evaluated against each other based on the beds reaching about 95% of

III. RESULTS AND DISCUSSION III.1. Comparison of Fiber Sorbent Modules and Pellet Packed Bed Adsorbers without Heat Integration. For the purposes of this study, the intrinsic heats associated with each adsorption process were neglected. Due to the low concentration of TBM odorant in pipeline natural gas, the heat released during adsorption was estimated to be relatively low and the adsorption step was considered to be isothermal without any temperature control (details in the Supporting Information). Therefore, the energetic cost of the adsorption system, which is directly related to operating costs, included the heat required for heating the sorbent material up to the temperature of desorption and the utilities required for cooling the sorbent material down to the adsorption temperature. Capital cost estimates were factored based on appropriately sized major equipment items, while operating costs were estimated based on the utilities needed for regeneration and cooling. Table 1 summarizes some important parameters in Table 1. Summary of the Step Times and Bed Number Comparison between Fiber and Pellet Adsorbersa adsorption time (min) regeneration time (min) cooling time (min) total cycle time (min) no. of beds in adsorption total no. of active beds

fiber modules

pellet beds

42 1 5 48 3 4

251 16 86 353 18 24

a

The cycle times are much longer for the pellet bed and the number of beds are much higher because of the slower superficial velocity required.

these cost estimates for both fiber and pellet packed beds. The method used to compute cycle times and bed numbers is detailed in the Supporting Information. The fiber sorbent approach is attractive because the times associated with each of the three steps are much shorter in fiber beds than in pellet beds due to the much slower superficial velocity required through the pellet beds. For fiber adsorbents, a superficial velocity of 1.15 m/s through three parallel beds was sufficient to process the 15 000 scfm incoming natural gas. For pellet adsorbents, a slower superficial velocity of 0.21 m/s was needed to process the same amount of natural gas due to mass transfer limitations in the pellets. Because of this superficial velocity constraint, 6 times more pellet beds were needed than fiber beds. The difference between the total number of active beds and the number of beds in adsorption mode in the last two rows of Table 1 indicates the number of beds that will be in regeneration or cooling mode at any time, again, given proper staggered bed start-up and timing. In the capital cost analysis of both systems, one extra inactive bed is also included as a standby bed in case of an emergency. Figure 3 illustrates the relative time a fiber module would spend in the adsorption step versus the regeneration and cooling steps as compared to a pellet packed bed. Though the actual time for a pellet bed to complete a full cycle is longer due

Figure 2. Difference in front positions of the three adsorption beds with staggered start-up. 7115

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Table 2. Summary of the Equipment Items and Purchased Equipment Costs (Directly Related to Total Capital Cost) Associated with the Three Different Regeneration Gases Considered for the Fiber Module System Onlya desorption equipment compressed air air compressor compressed nitrogen air compressor air dryer air filter air tank nitrogen PSA generator nitrogen tank high pressure compressor total product gas heat exchanger

Figure 3. Comparison of the fraction of one full adsorption− desorption cycle time that a fiber module or pellet packed bed spends in each of the three steps.

to the slower superficial velocity through the bed, the pellet bed system spends a larger fraction of its total cycle time in regeneration and cooling modes because of the difference in the critical dimensions of the fibers versus the pellets, and also the difference in the binder/support material used. With a pellet diameter of 1 mm versus a fiber diameter of 300 μm, it takes longer for a pellet to reach the desired temperature than a fiber because of the larger critical dimension of the pellet. Also, the fibers use cellulose acetate polymer as the support material for the zeolite sorbent while the pellets use kaolin clay as the binder material, which has a much higher heat capacity than cellulose acetate and therefore requires more heat exchange to completely heat and cool the pellets. These cycle times directly affected the annual heating and cooling utility costs in both systems. The capital costs of both fiber module and pellet packed bed systems were estimated using cost correlations and heuristics found in works by Tedder and Peters.35,36 The capital cost of a single fiber module was estimated based on the cost of the raw materials needed to create a module and then scaled up from the raw material cost using an average of two different factoring methods (Guthrie and Page) that take into account labor, construction equipment, overhead, and other indirect costs (details in the Supporting Information).36 The capital cost of a single pellet packed bed was estimated with a cost correlation of a packed bed based on reactor volume plus an estimation of the cost of the pellets to fill the bed. The cost of these beds in dollars per amount of mass transfer area was found to be $11.50/m2 for the fiber beds and $23.10/m2 for the pellet beds. Besides the adsorber beds, other equipment items were necessary to run the system depending on the type of regeneration gas used, as listed in Table 2. The operating costs of both fiber and pellet packed bed systems without heat integration included two major contributing costs: utilities and the parasitic load incurred if product gas is wasted. Labor costs were considered with operating costs in an initial estimate, but were finally omitted due to reasoning that the adsorption system is easily automated and no extra workers need specifically be hired to operate it. Instead, it was assumed that the personnel already employed at the plant can be given the extra responsibility of intermittently checking the system, and that the system does not need continuous supervision once it has been started. Other costs that were also considered but finally omitted from the final operating cost estimates were the cost of purchasing the pipeline natural gas feed because this is a cost that would be incurred even without the sorbent system and the cost of compressing the final product to the high pressure necessary for introduction into the gas turbine based on similar reasoning

purchased equipment cost ($) 89,000 85,000 33,000 9,000 6,000 34,000 7,000 95,000 269,000 22,000

a

The purchased equipment cost is a factored cost estimate based on the equipment items necessary to support the continuous supply of each gas, and takes into account the high operating pressure of the system (see the Supporting Information for details).

that this is a cost that would be incurred anyway. Finally, the cost of a treatment system for the SO2 gas produced from the burning of the TBM-rich waste gas stream after sorbent regeneration was also not included because the amount of SO2 produced would be relatively small and could simply be handled by dilution with the much larger amount of flue gas produced by the gas turbine. The environmental impact of this amount of SO2 should not differ from that from burning the original odorant-containing stream in the turbine. If the volume of SO2 produced would require other treatment, that facility would already be present at the site. Three different regeneration gases were considered for the regeneration step in the fiber modules. Tables 2 and 3 compile Table 3. Summary of the Annual Operating Costs Associated with the Three Different Regeneration Gases Considered for the Fiber Module System Onlya desorption gas

annual operating cost ($)

compressed air compressed nitrogen product gas

2,000 14,000 54,000

a

The compressed air desorption shows the lowest cost, but was eliminated from consideration due to safety issues.

the relative capital and annual operating costs of using three different regeneration gases, based solely on the equipment items and the utilities needed to produce each gas at 120 °C and 250 psig. While using compressed air would be the best option in terms of cost, this option was eventually eliminated due to the safety issues that arise from the possible contact of large quantities of hot compressed air with natural gas. To decrease the risk of explosion, it was desired to have a regeneration gas that is free of oxygen. Using compressed nitrogen for regeneration was another option, but use of the product gas provided an option that was less expensive overall while simplifying the process by not having to introduce an onsite nitrogen generation system. For these reasons, a fraction of the product gas was chosen as the regeneration media for the 7116

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remainder of this study. To bring the product gas up to the temperature of desorption, a heat exchanger utilizing steam as the heating medium is envisioned to heat the product gas. The adsorption systems were first evaluated without heat integration considerations, meaning that the product gas used for regenerating the sorbent was considered as a parasitic load on the system and counted into the annual operating cost. In section III.2, heat integration options were considered to lower the operating cost by using the heat generated from combusting this product gas to produce steam. After choosing the regeneration gas to be a fraction of the product gas, the capital costs associated with both adsorption systems were estimated using Guthrie and Page correlations, which gave system cost estimates as percentages of the base and purchased equipment costs.36 For the system in general, it was assumed that the adsorption step does not require a compressor or pump because the feed gas is already at a high pressure of 250 psig, and can be fed directly into the adsorber beds. A fraction of product gas was chosen as the cooling gas without consideration of other gases, as it greatly simplifies the process, it does not waste any product, and natural gas (composed mainly of methane) has a higher heat capacity than either air or nitrogen. It is necessary to cool the product gas stream somewhat before using it to cool the sorbent bed to decrease the cooling step time. This can be accomplished by using a second heat exchanger to cool the product gas with cooling water. For this study, the product gas was assumed to exit the adsorber beds at 30 °C, the same temperature as the incoming natural gas feed. Water was assumed to enter the heat exchanger at 15 °C, cooling the product gas to 25 °C for use in the cooling step. To estimate the capital cost of the system, the equipment items (the adsorber beds, the “hot” heat exchanger, and the “cold” heat exchanger) were first sized and the cost was estimated using Guthrie equipment cost factors, which also accounted for the high operating pressure of the system.35,36 Then, both Guthrie and Page factoring methods were used to estimate other direct and indirect costs as percentages of the equipment cost. These factors account for other costs that are necessary to plant construction such as piping, labor, materials for construction, safety, taxes, delivery, overhead, and engineering. Figure 4 presents the various capital costs associated with each equipment item in both fiber and pellet adsorber beds. The pellet packed bed system, at a total capital investment of $2,792,000, costs about 3 times more than the fiber module system at a total capital investment of $819,000. The major contribution to the total capital investment of both systems was the cost of the adsorber beds. Figure 5 compiles the various operating costs associated with both fiber and pellet adsorber beds using product gas for both regeneration and cooling. The total annual operating cost for the pellet packed bed system was about 3.5 times greater than the operating cost for the fiber module system. The operating costs for the pellet bed system were greater than those for the fiber bed system because many more pellet beds were needed, which then required a greater amount of all utilities for the heating and cooling steps. III.2. Comparison of Fiber Sorbent Modules and Pellet Packed Bed Adsorbers with Heat Integration. If heat integration is considered, the total operating cost for the fiber system could be lowered significantly. With heat integration, a fraction of the heat generated from the combustion of the

Figure 4. Capital cost (purchased equipment cost only) comparison between a fiber module adsorbent system and a pellet packed bed adsorbent system.

Figure 5. Annual operating cost comparison without heat integration between a fiber module adsorbent system and a pellet packed bed adsorbent system.

TBM-rich waste gas stream (which still contains a large amount of methane) could be used to create steam, which could be used to heat the product gas in the regeneration step. This would eliminate the cost of purchasing steam as a separate utility and lower the amount of product gas wasted, which would in turn lower the cost of the parasitic load. Additional water would then have to be purchased to create the steam, but this presented a lower cost increase than the savings gained from lowering the parasitic load and not purchasing steam. This option, referred to as method 1, would create only enough steam to cover the cost of regeneration. Figure 6 presents the new operating costs associated with the two adsorption systems if only enough steam is created this way for use in the regeneration step of the process. A second option for heat integration, referred to as method 2, is to use all of the energy from the waste stream combustion to create steam. Because the amount of steam needed for the regeneration step is only a small fraction of the total amount of steam that could be created from all of the waste gas heat, there would be a large amount of excess steam produced. This excess steam could be used in a separate steam turbine to generate 7117

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create enough useful product that the profit gain is greater than the utility cost. III.3. Potential Savings on Turbine. The capital cost of an 85 MW gas turbine was estimated to analyze the relative cost of implementing the fiber adsorbent system designed in this study. A cost correlation was drawn from 2007−08 Gas Turbine World Handbook, as shown in Figure 8.37 For an 85 MW turbine, the

Figure 6. New annual operating cost comparison with heat integration method 1 between a fiber module adsorbent system and a pellet packed bed adsorbent system. This heat integration method results in an operating cost reduction of approximately 10% in both systems.

electricity in a fashion similar to that of a combined cycle power plant, or integrated with the primary steam turbine process. With method 2, much of the parasitic load on the system would be eliminated, in addition to eliminating the cost of purchasing steam for the regeneration cycle. The annual cost of water would increase significantly due to the need to purchase extra water to create the steam; however, this is counterbalanced by now having electricity as a useful end product. To account for the cost of all the power generation equipment in this heat integration method, including the turbine, the selling price of electricity was taken as $0.04/kWh. This is price is reasonable for electricity produced and used at the power plant. Figure 7 shows the new operating costs associated with the two adsorption systems if all of the energy from waste stream combustion was used to create steam, with the excess steam being used to generate electricity for profit. The negative sign present in the product electricity columns indicates an annual net profit instead of a net cost. In other words, heat integration has the potential to not only lower the operating cost, but also

Figure 8. Correlation between gas turbine capacity and its capital cost for a simple cycle plant. Adapted from ref 37.

price was extrapolated to be about $300/kW in 2007 U.S. dollars. The total capital cost of the turbine was then estimated to be approximately $28.4 million in 2011 dollars. The cost per million Btu was estimated to determine the economic feasibility of implementing a TBM removal system. First a yearly cost of the system was estimated, taking into account both the total capital investment over the lifetime of the fiber adsorbent system (assumed to be 5 years) and the annual operating cost. This yearly cost was converted to cost per million Btu by taking into account the flow rate of natural gas through a single turbine. It was found that implementing the fiber module adsorber system would cost about $0.03/ MMBtu without heat integration and about $0.02/MMBtu with heat integration method 2. In contrast, implementing the pellet bed adsorber system would cost about $0.10/MMBtu without heat integration and about $0.06/MMBtu with heat integration method 2. Additionally, not considering turbine or fiber system lifetimes, the capital cost of the fiber sorbent system was found to be about 3% of the capital cost of the 85 MW turbine, which is not prohibitively high. Alternatively, the capital cost of the pellet bed sorbent system would be about 10% of the capital cost of the gas turbine. In other words, the capital cost of the fiber sorbent system was about 30% of the packed bed adsorber system. In contrast, the potential savings incurred by implementing the fiber sorbent TBM removal system could be significant, as shown in Figure 9. Figure 9a shows the potential savings without heat integration, while Figure 9b shows the potential savings with the more cost-effective of the two heat integration methods considered: method 2. Savings are greatest when the original turbine lifetime (without implementing the TBM removal system) is short and the life extension with TBM removal system implementation is long. Without heat integration, the “worst case scenario” with a turbine life

Figure 7. New annual operating cost comparison with heat integration method 2 between a fiber module adsorbent system and a pellet packed bed adsorbent system. The negative numbers indicate a profit rather than a cost. 7118

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associated with sulfur odorants in natural gas, the combined capital and operating costs of the fiber sorbent system were found to be low enough to offer an attractive method of removing the odorant to increase turbine lifetime and increase profitability.

IV. CONCLUSIONS A fiber adsorbent system has been designed to remove the odorant tert-butyl mercaptan from pipeline grade natural gas for the purpose of delaying or preventing hot corrosion in gas turbines. The system was found to be economically feasible in terms of its relatively low capital and operating costs compared to the cost of turbine replacement, low spatial requirements, and its potential to provide significant savings by increasing the normal lifetime and efficiency of the turbine. This novel fiber sorbent system has been compared to a traditional pellet packed bed adsorber system, which suffers from high pressure drop and low mass transfer rates. The fiber module configuration was found to require less space and was economically advantageous compared to a pellet packed bed system for processing the same amount of pipeline natural gas, making it a promising alternative. Heat integration strategies can be employed to lower the operating costs associated with the sorbent system. By using the heat generated from waste gas combustion to create steam, this waste stream can be converted to a useful product. The steam generated this way could be used to heat the fraction of product gas needed for regeneration and also used to power a steam turbine to generate electricity. With such a simple system with heat integration, the annual profit became greater than the cost, making such a sulfur removal system an attractive addition to new or existing natural gas fueled power plants.

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ASSOCIATED CONTENT

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AUTHOR INFORMATION

S Supporting Information *

Equations, example calculations, and additional figures are presented for the fiber sorbent modules and pellet packed bed. This material is available free of charge via the Internet at http://pubs.acs.org.

Figure 9. Potential savings per year by implementing the fiber sorbent system as a function of original turbine lifetime and length of turbine life extension (a) without heat integration and (b) with heat integration. Negative values indicate a net cost rather than savings.

extension of only 1 year with fiber system implementation, the fiber system was found to be not viable due to higher cost than savings for all original turbine lifetimes greater than 11 years. However, in the best case, with a turbine life extension of 5 years, the fiber system showed potential savings ranging from about $52,000 to $2,610,000 per year. With heat integration, the same “worst case scenario” would not be viable for all original turbine lifetimes greater than 13 years. The best case would offer potential savings between $122,000 and $2,680,000 per year. The major difference with heat integration was that most scenarios implementing the fiber sorbent system became viable (having a savings greater than zero). Net savings of at least $23,000 per year is possible with a turbine life extension of 3 years or more. A turbine life extension of 4 years with heat integration can be viable if the original turbine lifetime is 17 years or less. While the fiber adsorbent system both with and without heat integration can offer significant savings on the cost of the gas turbine by extending its lifetime, it is clear that heat integration would offer greater savings in all scenarios and is a practical way to lower the environmental impact of the system. Compared with the cost of replacing the turbine due to corrosion

Corresponding Authors

*E-mail: [email protected]. *E-mail: [email protected]. Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS The authors thank General Electric for funding this research and Robert Taylor (GE), Matthew Realff (GT), and Yoshiaki Kawajiri (GT) for their comments and suggestions on this project.

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REFERENCES

(1) Annual Energy Outlook; AEO2012; U.S. Energy Information Administration: Washington, DC, 2012. (2) Natural Gas Year-in-Review. In Natural Gas Monthly; U.S. Energy Information Administration: Washington, DC, 2012. (3) High Temperature Corrosion and Materials Application; ASM International: Materials Park, OH, 2007; pp 249−258. (4) Casanova, M. Corrosion problems in turbines. Proceedings of the Second Turbomachinery Symposium; Boyce, M. P., Ed.; Texas A&M University: College Station, TX, 1973; pp 83−90. 7119

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dx.doi.org/10.1021/ie500069y | Ind. Eng. Chem. Res. 2014, 53, 7113−7120