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Shale gas processing integrating with ethylene production: Novel process designs, exergy analysis, and techno-economic analysis Chang He, and Fengqi You Ind. Eng. Chem. Res., Just Accepted Manuscript • DOI: 10.1021/ie5012245 • Publication Date (Web): 24 Jun 2014 Downloaded from http://pubs.acs.org on June 29, 2014

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Industrial & Engineering Chemistry Research

Shale gas processing integrating with ethylene production: Novel process designs, exergy analysis, and techno-economic analysis Chang He,a,b Fengqi Youa* a

Department of Chemical and Biological Engineering, Northwestern University, Evanston, IL 60208 b

Department of Chemical Engineering, China University of Petroleum, Changping, Beijing 102249

Abstract An important impact of shale gas on the chemical industry is the production of value-added chemicals from natural gas liquids (NGLs, C2H6, C3H8, C4H10, C5+). In this paper, three novel process designs are proposed for integrating shale gas processing with ethylene production. The unique feature of the proposed process designs is the co-processing of shale gas and ethane cracking gas. Based on detailed process modeling and simulation, we develop detailed thermoeconomic models and exergy analysis for the process designs. The results show that the proposed process designs using NGLs-richer shale gas have an adverse impact on both the overall exergy efficiency and total capital cost, compared with conventional shale gas processing design. However, technology integration and better quality of raw shale gas can significantly increase the profitability of the proposed process designs. The estimated net present values (NPVs) of proposed designs are 1.7-2.4 times greater than that of the conventional one. Besides, the NGLsricher shale gas generally results in 3.17-5.12 times higher NPV than that of NGLs-leaner one.

*

To whom all correspondence should be addressed. Phone: (847) 467-2943; Fax: (847) 491-3728; E-mail: [email protected]

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1. Introduction With the seemingly inevitable depletion of natural gas reserves, tapping unconventional gas resources—from shale, low-permeability sandstone and coal beds—has become a remarkable energy story in the 21st century. Due to the abundant shale gas resource, in 2009 the total gas production in the U.S. was back up almost to the 1970’s peak.1 More recently, the Potential Gas Committee (PGC) estimated that U.S possessed nearly 2,700 trillion standard cubic feet (tscf) potential natural gas supply, 40% of which is extractable shale gas.2 This translates into an additional supply of 47 years at current rates of consumption, which is about 23 tscf per year. In 2009, sharp growth in shale gas production allowed the U.S. to reduce its gas import share to 13% and become a net exporter of liquefied petroleum gas (LPG) in 2012. In addition, partly due to the replacement of coal-fired power plant by shale gas power plant, the International Energy Agency (IEA) announced that CO2 from fossil fuel consumption in the U.S. has fallen by 430 million tons from 2006 to 2011 (7.7%), the largest reduction of all countries/regions surveyed.3, 4 Similar to conventional natural gas, CH4 is always the dominant component in the shale gas (typically 75~90% of the total). The remaining components include varying amounts of natural gas liquids (NGLs, C2H6, C3H8, C4H10, C5+), acid gases (CO2 and H2S), as well as N2, He, and H2O. The major product of shale gas processing plant is sales gas (pipeline natural gas, mainly CH4). Sales gas is received and transported by the major intrastate and interstate mainline transmission systems, and must meet the strict quality standards (heat content, dew point, impurities content, etc.) specified by the pipeline companies. Besides, since some processing equipment (e.g., demethanizer) operate in cryogenic environment, H2O and CO2 must be essentially removed in advance in order to avoid potential freezing problem. Typically, four gas treatment steps including acid gas removal (AGR), sulfur recovery, dehydration and nitrogen rejection are employed to remove undesired components (H2S, CO2, N2, H2O and heavy hydrocarbons) from the raw shale gas. However, the shale gas has high composition variability from area to area even from well to well within the same area.5 Therefore, the technique employed to process the shale gas depends on the components to be removed as well as with the properties of the gas stream (e.g., composition, temperature, pressure and flow rate).5-8 It is noteworthy that, most of the shale gas formations (e.g., Bakken formation) in the U.S. are reported to be rich in ethane and other NGLs contents, which typically have substantially higher market values than the methane gas.9 Light NGLs, such as ethane, propane and butanes 2 ACS Paragon Plus Environment

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can be used as feedstocks to petrochemical plants, while the heavy fractions can be used as gasoline blending stock. Because ethane is relatively cheaper and cleaner than oil-based feedstock (naphtha), 99% of ethane derived from NGLs is currently used as the primary feedstock to produce ethylene. As one of the most common building block, ethylene is used to make thousands of chemical products like plastics, synthetic rubber, adhesives, etc.10 However, the majority of NGLs compounds, especially ethane, are not suitable for long-distance transportation, because their transportation costs increase significantly when they are offshored or pipelined. As a result, it is more reasonable and cost-effective to use ethane as the feedstock of the domestic/local petrochemical plants. Apart from ethylene, NGLs are profitable to produce other value-added products, consisting of propane, butanes and pentanes. Given the above advantages, the NGLs processing is currently receiving substantial attention and new infrastructure are under development to produce ethylene from shale gas formations. There are very limited research works investigating downstream utilization of shale gas as a profitable chemical industry feedstock.10 Existing literature concerned with the process design and operation of shale-gas-based energy systems are reviewed below. EI-Halwagi and coworkers11 addressed the process synthesis, simulation, and integration of a shale gas-to-methanol plant resulting in a desirable 31.0% return on investment (ROI) with the selling prices of $2.00/gal for methanol and $3.50/kscf for shale gas. Martín and Grossmann12 presented a superstructure optimization approach for the simultaneous production of liquid fuels and hydrogen from shale gas and switchgrass. A highly efficient cold energy integration scheme was recently proposed by integrating NGLs recovery from shale gas and LNG re-gasification at receiving terminals.13 To the best of our knowledge, none of the existing publications considers the technology integration, evaluates the techno-economic performance of shale gas-based polygeneration system, or their possible integration with ethylene manufacturing. The objective of this paper is to first develop novel shale gas-based process designs by integrating shale gas processing with ethylene production for polygeneration of sales gas, ethylene, propane, butanes, pentanes, as well as by-products (hydrogen, propylene and sulfur, etc.). Specifically, the novel process designs include shale gas sequential processing (SSP), ethane cracking gas (a processable mixture including C2H4, H2, C2H6, CH4, etc., which is short for “cracking gas” below) recycling to NGLs recovery (CRN), and cracking gas recycling to dehydration (CRD) designs. All the three novel process designs are investigated and compared 3 ACS Paragon Plus Environment


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with the conventional gas processing (CGP) in order to determine the most energy-efficient and cost-effective process design. The unique feature of the proposed process designs is the coprocessing strategy of shale gas and cracking gas. We develop detailed thermo-economic models and conduct exergy analysis for the shale gas-based process designs based on the proven and available techniques. Eight related process units consisting of AGR, sulfur recovery, dehydration, NGLs recovery, fractionation train, nitrogen rejection, ethylene plant, and cracking gas separation are considered and modelled in details using HYSYS simulator.14 Among these, the modified process models of NGLs recovery and fractionation train capable of separating valuable products from the mixture of shale gas and cracking gas have not been considered previously in the literature to the best of our knowledge. In addition, the process models of sulfur recovery, dehydration, and nitrogen rejection have not been systematically reported before. The proposed process designs are applied to three types of shale gases with different NGLs content levels (medium, rich and superrich) in order to illustrate the application of the proposed process models and assess the thermo-economic performance. The rest of this paper is organized as follows. The overall process description and process models used for detailed simulation are presented in the next two sections, respectively. An indepth techno-economic analysis can be found in Section 4. Finally, concluding remarks are presented in the Conclusion section.

2. Overall Process Description We begin with a description of a well-known design for the conventional shale gas processing plant (see Figure 1), termed “CGP” design in this paper. In this design, the raw shale gas pipelined from reservoir/wellheads passes through an AGR area (A101) where the acid impurities, H2S and CO2, can be removed by amine absorption technology. In Area A201, the sulfur recovery and tail gas cleanup processes are employed to convert H2S to elemental sulfur in an environmentally acceptable manner. Next, the water vapor in the sweet gas is removed using the re-generable adsorption in liquid triethylene glycol (TEG) (A301). When the gas is upgraded, the products, NGLs, are recovered from sales gas in NGLs recovery area (A401) using the cryogenic distillation process. Due to the pipeline specifications, the excess nitrogen in substandard sales gas is then rejected using the cryogenic process (A601). The final step is to process the recovered NGLs stream through a fractionation train area (A501) including a series


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of distillation columns. Accordingly, multiple NGL products, including ethane, propane, butanes and pentanes, can be extracted in this process area.

Figure 1. The conventional shale gas processing plant (CGP design)

Based on the aforementioned CGP design, we propose three novel process designs that combine the shale gas processing plant with on-site ethylene production. (A) SSP design. As shown in Figure 2A, the first new design has the same shale gas processing plant as that of the CGP design, but the ethane extracted from NGLs is pipelined to a local ethylene plant area (A701), where ethane is converted into cracking gas using thermal steam cracking technology. The cracking gas is then introduced to a dehydration area (A801) followed by a cracking gas separation area (A901), where the unconverted ethane is recycled to the ethylene plant. Because shale gas is sequentially processed through the gas processing plant and ethylene production without recycle, this process design is termed “SSP” design in this paper.



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Figure 2. Three novel designs for multiple products produced from shale gas. (A) SSP design; (B) CRN design; (C) CRD design.

For better energy saving and equipment sharing, the rest two new designs focus on recycling the effluent stream from ethylene plant (A701) to shale gas processing plant, as shown in Figures 2(B) and 2(C). (B) CRN design. A recycling strategy included in the “CRN” design employs modified process areas including NGLs recovery (A402) and fractionation train (A502). The modified process areas can co-process the cracking gas from ethylene plant area (A701) and dry gas from dehydration area (A301). Specifically, ethylene, sales gas, hydrogen and NGLs are simultaneously extracted from the mixture of cracking gas and dry gas via the modified NGLs recovery. Therefore, the cracking gas separation area (A901) can be eliminated in this design. (C) CRD design. This design involves another recycling strategy. It has a similar ethylene plant area (A701) as that of the CRN design. However, in the CRD design, the produced cracking gas, together with sweet gas, are introduced to a centralized dehydration area (A301) for further gas purification and product separation. In this way, the cracking gas can share the same process areas, including dehydration (A302), NGLs recovery (A402), and fractionation train (A601), with sweet gas. In this work, we assume that 2,000 kmol/hr of raw shale gas is available at 30.0 bar, and 35 o

C. The quality of the raw shale gas, as determined by the compositions, plays an important role

in process design, configuration and project economics. According to NGLs content level 7 ACS Paragon Plus Environment


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(medium, rich and superrich), three typical raw shale gases derived from the Barnett,15 Eagle Ford16 and Bakken17 formations, respectively, are considered in this article. The corresponding compositions are given in Appendix Table A1. Note that almost no literature explicitly provides the H2S and H2O content of shale gas. H2S content is reported typically varying at a low H2S/CO2 molar ratio,18 so it is assumed to be 0.5 for the H2S/CO2 in this study. Moisture content associated with phase equilibrium is predicted using a correlation-based method by Bahadori et.al.19 To remove impurities (H2S, CO2, H2O, and N2) from the raw shale gas, we consider the rigorous impurity removal designs where the technique selectivity,20 process options, and separation extent/sequence mainly depend on the specifications of final products and wastes discharged to environment.

3. Process Modeling 3.1 Acid gas removal (AGR) Undesired acid gases like H2S and CO2 are first removed from raw shale gas before being introduced to NGLs recovery. A variety of commercial techniques that can be used in AGR process that an effective selection of technology becomes a critical concern.21,

22

Common

decisions can generally be simplified, so we focus on factors including the amount of impurities in the feed gas, targeted treatment capacity, sales gas standards, and downstream processing technology. Figure 3 illustrates the effect of H2S and CO2 concentrations in the feed gas on the choices of AGR technology.7, 23, 24 For the shale gases considered, no treatment is needed if H2S concentration is less than 4 ppm; otherwise, chemical absorption process with amine solvent has higher technological feasibility. Additionally, NGLs recovery process cannot tolerate the concentration of CO2 above 100 ppm.22 Predominantly this specification is to avoid CO2 freezing problem in the cryogenic distillations. Thus, we employ chemical absorption-based AGR process to deeply remove both H2S and CO2.


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Figure 3. Schematic diagram illustrating the H2S and CO2 concentrations in the gas on the choice of AGR technology.7, 23, 24 The H2S and CO2 concentrations are reduced to lower than 4 ppm and 100 ppm, respectively.

Diethanolamine (DEA) solvent is employed in the AGR process because it is nonselective and it can effectively react with both H2S and CO2. Figure 4A illustrates the process flowsheet of AGR process. Most of the H2S and CO2 in the raw shale gas are absorbed by the lean solvent as it passes through the AGR absorber. The off-gas from the top of AGR absorber is sent to a condenser at 35oC to remove liquid fraction. The resulting liquid stream, which contains very small portion of heavy hydrocarbons, goes to NGLs recovery area for increasing hydrocarbons recovery rate. The remaining stream, sweet gas, is sent to dehydration area for essential removal of water. The effluent stream from the absorber bottom containing rich DEA (38 wt%) passes through a pressure relief valve (V1) followed by a flash vessel (FV1) to knock out light hydrocarbons vapor (0.1~0.3 mol/hr), and then continues to depressurize to 2.1 bar via another valve (V2). After that, the rich DEA stream is preheated to 78 oC at a cross heat exchanger (cross HEX1) by cooling the lean solvent from the bottom of AGR stripper. The AGR stripper is used for DEA solvent regeneration, where the acid components dissolved in the rich solvent are stripped in the overhead sour gas. The regenerated DEA solvent along with makeup DEA/water



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is pumped to the first tray of the AGR absorber. After the AGR process, the H2S and CO2 concentrations are reduced to 0.05 mol% and 4 ppm in sweet gas, respectively.

Figure 4. Flowsheets of AGR area (A101) and enhanced TEG dehydration areas (A301, A302, and A801). 3.2 Sulfur Recovery In practice, the sulfur element present in the sour gas exiting from AGR area is required to be captured, if its amount exceeds a threshold limit specified by the local environmental regulations. In this study, we consider this limitation to be 5 ton/day, as suggested by Parks et. al.25 Supposing that the maximum sulfur recovery rate of 98 %,26 the amount of removed sulfur from Barnett, Eagle Ford and Bakken shale gases are projected to be 11.2 ton/d, 12.3 ton/d and 4.20 ton/d, respectively. Therefore, we only recover the sulfur present in the first two shale gases-derived sour gas, while the sour gas derived from Bakken shale gas is disposed by direct combustion in an incinerator. It should be noted that the sour gas rejected from AGR contains low H2S content (

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