Feasibility Study of Production of Methanol and Dimethyl Ether from Flare Gas Sho Fukuda, Kazutoshi Chaki and Toshiya Wakatsuki, Japex Research Center, Technical Division, Japan Petroleum Exploration CO.,LTD., Chiba, Japan Abstract Much of the gas associated with oil production is ignited and released into the atmosphere at certain oil fields due to limitations associated with, for example, specific locations and products [1]. The more effective utilization of associated petroleum gas (APG) will be critical for reducing CO 2 emission and conserving energy in the future, which is the focus of this paper. We evaluated the economic efficiency of producing methanol and dimethyl ether (DME) from the off gas. This off gas is discharged from liquid petroleum gas (LPG) recovery process in which the APG is used for source gas. The conditions of this economic evaluation were equivalent to those of an actual oil field, where the remoteness of the site makes acquiring utilities difficult. The results of our evaluation estimated that the process s internal rate of return (IRR) was approximately 10% and not high. However, this process is not unfeasible, because this process is related to the LPG recovery process which is profitable and because reduction of the flaring APG is achieved without its injection into, for example, oil reservoir and storage reservoir. Therefore, this process could promote the effective utilization of APG and reduce CO 2 emission. In this paper, the utilization of LPG and its economic feasibility is reported. Keyword: CO 2 emission, Energy Conservation and Efficiency, Engineering Economics, Flare gas and Methanol Introduction When crude oil is produced, APG comes to the surface from the oil reservoirs. In most cases, this APG is used on-site as generator fuel or transported by pipeline to be sold elsewhere. However, in some areas far from gas markets, much of the APG is ignited and released into the atmosphere. This is because, in remote areas and/or at small-scale oil fields, the high cost of constructing pipelines makes it difficult to recover construction costs through APG sales. Globally, APG is produced at 5.3 trillion ft 3 /year, equivalent to 25% of the USA s gas consumption. The burning of APG produces 400 billion ton/year of CO 2 emissions, equivalent to about 1.2% of global CO 2 emissions [1]. Because the production of these emissions has serious consequences for the environment, reducing the amount of APG flared at oil fields without the use of pipelines is a priority. As a method for reducing the amount of flared APG, we considered whether LPG recovery from flared APG could be
feasible in remote areas. Heavy hydrocarbons like LPG can be separated by cooling, compression, or absorption. Separated gases can be easily liquefied and transported by truck. Given the high costs of constructing pipelines, we assumed that transporting gas by truck would be more feasible. In our other economic study, LPG recovery process, of which feed gas capacity is smaller than it of this paper, is profitable at certain oil field. In this LPG recovery process, we calculate that the IRR is over 20%. Thus, it may be possible to decrease a portion of the flared APG without using pipelines through the LPG recovery process. However, light hydrocarbons in APG are exhausted through the LPG recovery process. The exhausted gas, known as off-gas, will be referred to as lean gas throughout this paper. The commercial utilization of lean gas would lead to zero flaring in the future if the lean gas is not injected into the oil reservoir, etc.. Because this would lead to zero flaring, we considered the effective utilization and economic feasibility of lean gas. Because it is difficult to transport gas from remote extraction areas to consumption areas, APG is not typically used. Although the liquefaction of gas can improve its transportability [2], off-gas consists of light hydrocarbons, which are not easily liquefied through physical phase changes. Thus, we considered chemical reactions that could liquefy APG. We assumed that the production of liquid fuel from lean gas would be a feasible method for improving the transportability of gas with zero flaring. Economic evaluation In our study, the gas composition and local environmental conditions considered were equivalent to those of an actual West African oil field. This oil field is situated onshore in a remote area where it is difficult to receive electric and industrial water supplies. Table1. Composition of lean gas Component Content (vol %) Component Content (vol %) Methane 77.86 C6+ 0.75 Ethane 18.3 Nitrogen 1.59 Propane 0.33 Carbon dioxide 0.27 Butane 0.57 Water 0.01 Pentane 0.32 Sulfer compiunds a few ppm by volume Feed-gas, Fuel-gas We assumed a baseline feed-gas amount of 53 million ft 3 /day, which is estimated referring the condition of an actual West African oil field, and that 0.16 TCF of lean gas would be required for the continuous operation of the site for 10 years. Thus, this process would not need a large-scale oil field, one objective in employing this process. Target of this process is disusing APG. The main component of lean gas (Table 1) includes light
hydrocarbons given that this gas is produced from the LPG recovery process. Fuel-gas used to run equipment is supplied from the lean gas and recycling gas which is discharged from syngas production and synthesis of chemical. Adoption of process The products of the process described in this paper include methanol or DME. The production of syngas is necessary for the synthesis of methanol and DME from hydrocarbons. Therefore, two kinds of processes, which is steam reforming (SR) and partial oxidation (POx), is used for syngas production. We developed a process flow based on the concepts described above and on the actual conditions at one oil field. We considered and evaluated the following four process types in this paper. The product volumes for each case were estimated according to baseline conditions described in Table2. Case A: Methanol synthesis via syngas production by POx Case B: DME synthesis via syngas production by POx Case C: Methanol synthesis via syngas production by SR Case D: DME synthesis via syngas production by SR Table2. Annual production Case A Case B Case C Case D Rate (kt *1 / year) 530 *2 370 *3 554 *2 387 *3 *1 kt= kilo metric ton, *2 as methanol, *3 as DME Methanol is used in the manufacture of various chemicals and liquid fuels and is globally in demand [3]. Although the market for DME is currently not large, this market has the potential to increase given that DME is expected to become a substitute for LPG [4]. Accordingly, methanol and DME was adopted the product of the process for effective utilization of lean gas. SR, which produces syngas from hydrocarbons and steam, is one of the most common techniques for producing syngas [5]. In this paper, our developing catalyst is used for steam reforming process. Our catalyst doesn t need large amount of steam for steam reforming reaction [6]. Thus, our catalyst is more suitable to the conditions of this evaluation than conventional catalyst. In contrast, because the objective of this study is to use APG in remote onshore areas, where it is difficult to supply industrial water for the production of steam, conventional SR may not be suitable for producing measurable quantities of syngas. Thus, POx, which uses oxygen for feed, may be a more suitable technique for producing syngas of this condition. Some POx processes have been developing. Advanced auto thermal gasification (AATG), is one kind of POx process. AATG has a unique and fine character for syngas production and brings advantage for the cost of process [7].
Main equipment The four processes consist of four main parts: (1) syngas production by POx, (2) syngas production by SR, (3) methanol synthesis, and (4) DME synthesis. Syngas production via POx requires desulfurization, a partial oxidation reactor, a waste heat boiler (WHB), and equipment to adjust the amount of H 2. Syngas production by SR requires desulfurization, a reformer and WHB. In the POx process, adjusting composition ratio of H 2, CO and CO 2 in syngas is necessary for efficient synthesis of methanol. However, in the SR process, the adjusting equipment is not necessary, because we can adjust composition ratio of syngas by adjusting composition of feed gas. The character of our catalyst, of which permissible range for feed gas composition is unique, allows adjusting composition of feed gas. The methanol synthesis utilizes a compression section, a synthesis reactor, and a distillation section. The DME synthesis utilizes a synthesis reactor, a DME purification section, and a methanol recovery section. Electricity Since electricity is not available, own power generation facility with suitable capacity shall be installed. Electricity is required for electric motors of rotary machineries and air fin cooler etc. Steam turbine generator is provided for the generation of electricity in this Lean gas conversion plant. Steam Steam is produced by WHB and Heat Recovery Section associated with SR or POx, which is through from the steam drum. Deficient steam, which is mainly used in steam turbine generator and cooling water chiller, is produced by packaged steam boiler. Utility Water Because industrial water is generally not available in this evaluation, any required water must be generated as part of the process through, for example, recycling process condensates. The amount of required process water was calculated as the difference between the maximum recycling water and the consumption of process water (Table 3). The amount of required water indicates the demand for industrial water supplied from the outside. Table3. Demand of Industrial Water Case A Case B Case C Case D Amount of Industrial water (MT *1 / hour) -18.9-30.4 43.8 24.8 *1 MT = metric ton Results showed that the demand for industrial water in Cases A and B was negative. Therefore, Cases A and B did not require an external supply of industrial water during steady
operation. The external supply of industrial water is necessary for starting up the process. However, the demand for industrial water in Cases C and D was positive, and an external supply of water would be necessary for these processes. This external water has to be supplied, for example, by truck. The differences in water requirements among the cases were due to the fact that POx uses oxygen for its oxygen source while SR uses steam for its oxygen source. For this reason, POx may be a more profitable method in remote areas compared to SR. Economic condition We also assumed that the price of lean gas was 0 US$/MMBTU. We made this assumption, because the value of APG was lower than that of conventional natural gas and because the lean gas was produced as the off-gas of the profitable LPG recovery process. The prices of methanol and DME were calculated according to 2011 price trends [8]. We assumed an operation and depreciation period of 10 years. Finally, we considered the physical life of the equipment at >10 years. Therefore, it would be possible to extend the operation period and relocate a facility according to production status. Item Assumption Item Assumption Lean gas price 0US$ / MMBTU *2 Inflation 0% / year Product methanol price 350US$ / MT *1 Income tax 30% Product DME price 550US$ / MT *1 Maintenace cost 3% of CAPEX / year Equity 100% Labor cost 3% of CAPEX / year Operation period 10 years Insurance cost 1% of CAPEX / year Depreciation 10 years *1 MT = metric ton, *2 MMBTU =million british thermal unit Basic Economic study The IRR of each case was calculated on the basis of incomes and costs. Table 5 shows the CAPEX, OPEX, and IRR for each case. Results showed that the IRR was not high for any case. However, reductions in the flaring of lean gas without its injection would provide an advantage. Furthermore, this process is related to the profitable LPG recovery process. Given these advantages, we conclude that the implementation of this process would be feasible. Table4. Prerequisite Conditions Table5. CAPEX and OPEX for each case Case A Case B Case C Case D CAPEX *1 (MMUS$ *2 ) 576 684 648 756 OPEX *1 (MMUS$ *2 / year) 45.2 53.4 52.8 59.7 IRR (%) 11.5 9.8 9.6 8.5 *1 CAPEX and OPEX are calculated on basic conditions in table4., *2 MMUS$= Million of U.S. Dollars.
Sensitivity analysis In this paper, we conducted a sensitivity analysis in which we varied several parameters. We evaluated the effect on economic efficiency regarding to the product price, the lean gas price and, the lean gas capacity. Sensitivity for Price of product methanol and DME First, we varied methanol prices at 280 US$/MT, 315 US$/MT, 350 US$/ MT (baseline price), 385 US$/MT, and 420 US$/MT. Given present price trends, we considered these methanol prices reasonable future estimates. In the baseline scenario, the IRR was over 10% (Figure 1). We also varied DME prices at 440 US$/MT, 495 US$/MT, 550 US$/MT (baseline price), 605 US$/MT, and 660 US$/MT (Figure 2). Because DME is generally produced from methanol, we assumed that DME price was related to methanol price such that the DME price was calculated by methanol price and assumed cost for production. The IRRs for Cases C and D were lower than those for Cases A and B, namely the production of DME did not result in a profit. Therefore, DME price must be recalculated for reasonable evaluation. DME production may be an option if the price of and demand for DME increase in the future. Sensitivity for Feed price IRR (%) 20 15 10 5 0 280 300 320 340 360 380 400 420 Methanol Price (US$/MT) Fig.1.Sensitivity analysis for methanol price. CaseA :Methanol synthesis via POx, CaseC :Methanol synthesis via SR, Evaluation conditions; Lean gas capacity: 53million ft 3 /day, Lean gas price: 0US$/MMBTU. IRR (%) 20 15 10 5 0 440 460 480 500 520 540 560 580 600 620 640 660 DME Price (US$/MT) Fig.2.Sensitivity analysis for DME price. CaseB :DME synthesis via POx, CaseD :DME synthesis via SR, Evaluation conditions; Lean gas capacity: 53 million ft 3 /day, Lean gas price: 0 US$/MMBTU. We varied raw lean gas prices at 0 US$/MMBTU, 1 US$/MMBTU, 2 US$/MMBTU,
3 US$/MMBTU, 4 US$/MMBTU, and 5 US$/MMBTU (Figure 3). In the baseline scenario, the IRR was approximately 10%. Given their relationship, the IRR value decreased as gas prices increased, and free gas would be essential for the profitability of these processes. We concluded that acquiring free gas would be reasonable given that lean gas is the off-gas produced through the profitable LPG recovery process. Sensitivity for capacity of feed gas In addition, we varied the lean gas capacity at 26.5 million ft 3 /day, 53 million ft 3 /day, and 80 million ft 3 /day (Figure 4). Because the gas reserve would need to be 0.08-0.24 TCF for continuous operation over 10 years, this process would not require large-scale oil fields. As the lean gas capacity increased, the IRR increased by the merit of expanding equipment. However, the merits for expanding each process were similar. The lean gas capacity of the baseline scenario would be necessary to achieve an IRR >10%. As shown in the figure 4, POx was more effective than SR considering the profitability of the process. A lower demand for industrial water made POx a more feasible process. In this paper, we evaluated the merits of each process considering only economic evaluation. Therefore, we did not evaluate whether external supplies of industrial water is feasible. IRR (%) 20 15 10 5 0 0 1 2 3 Price of feed gas (US$/MMBTU) Fig.3.Sensitivity analysis for feed gas price. CaseA :Methanol synthesis via POx, CaseB :DME synthesis via POx, CaseC : Methanol synthesis via SR, CaseD :DME synthesis via SR, Evaluation conditions; Lean gas capacity: 53 million ft 3 /day, Methanol price: 350 US$/MT, DME price: 550 US$/MT. IRR (%) 20 15 10 5 0 0 20 40 60 80 100 Capacity of Feed gas (million ft 3 /day) Fig.4.Sensitivity analysis for feed gas capacity. CaseA :Methanol synthesis via POx, CaseB : DME synthesis via POx, CaseC : Methanol synthesis via SR, CaseD :DME synthesis via SR, Evaluation conditions; Lean gas piice: 0 US$/MMBTU, Methanol price: 350 US$/ MT, DME price: 550 US$/MT.
Conclusion In this paper, we considered the effective utilization of APG for the reduction of CO 2 emissions and improved energy conservation. We determined that LPG recovery would be a suitable method for reducing the amount of flared APG. However, the utilization of lean gas would be necessary to achieve zero flaring without its injection. Therefore, we considered the economic feasibility of producing methanol and DME from lean gas. We considered the processes comprised syngas production, methanol synthesis and, DME synthesis in this paper. Result of the evaluation, the IRR of this process was not high. However, reductions in the flaring of lean gas without its injection would provide an advantage. Furthermore, this process is related to the profitable LPG recovery process. Given these advantages, we conclude that the implementation of this process would be feasible. Although the feasibility for utilization of APG is conditional on the further demand for flaring gas reduction and the economic conditions, we expect that this process will be suitable to effective utilization of APG. Reference 1. The World Bank, (2011) Improving energy efficiency and mitigating impact on climate change http://siteresources.worldbank.org/intggfr/resources/ggfr _NewBrochure(Oct2011).pdf. 2. J.J.H.M. Font Freide, (2004) Gas conversion - its place in the world Natural Gas Conversion VII, Elsevier, v. 147, p. 61 66. 3. T. Okubo, Y. Fujita, (2013) Chemical economy March 2013 (kagaku keizai 3gatsu zoukangou) The Chemical Daily Co., Ltd. p. 61 64. 4. C. Arcoumanisa, C. Baeb, R. Crookesc, E. Kinoshitad. (2008) The potential of di-methyl ether (DME) as an alternative fuel for compression-ignition engines Fuel, Elsevier, v. 87, p.1014-1030. 5. J. Rostrup-Nielsen, (2004) Steam reforming of hydrocarbons. A historical perspective Natural Gas Conversion VII, Elsevier, v. 147, p. 121 126. 6. H. Okado, T. Wakatsuki, K. Inaba, H. Hirano, Japan Patent 4355047. 7. Y. Watanabe, N. Yamada, A. Sugimoto, K. Ikeda, N. Inoue, F. Noguchi, Y. Suehiro, (2007) Advanced auto-thermal gasification process Studies in Surface Science and Catalysis, Elsevier, v. 167, p. 439 444. 8. Methanex, (2013) Historical Methanex Posted Prices http://www.methanex.com /products/documents/mxavgprice_aug302013.pdf.