CHEMICAL ENGINEERING TRANSACTIONS VOL. 57, 2017 A publication of The Italian Association of Chemical Engineering Online at www.aidic.it/cet Guest Editors: Sauro Pierucci, Jiří Jaromír Klemeš, Laura Piazza, Serafim Bakalis Copyright © 2017, AIDIC Servizi S.r.l. ISBN 978-88-95608- 48-8; ISSN 2283-9216 Effects of Impurities on CO2 Pipeline Performance Suoton P. Peletiri, Nejat Rahmanian*,Iqbal M. Mujtaba Chemical Engineering Program, School of Engineering, University of Bradford, Bradford. BD7 1DP, UK n.rahmanian@bradford.ac.uk Carbon dioxide (CO2) is a chief constituent of greenhouse gases and should be captured, transported and stored in saline aquifers or used for enhanced oil recovery. This study is focused on pipeline transportation of impure CO2. The major impurities in captured CO2 from power plant stations and gas processing facilities are mainly nitrogen, methane, hydrogen sulphide, and water. Impurities affect the density and viscosity of the CO2 stream thereby impacting on the fluid phase, pressure and temperature of the stream. CO2 pipeline models, however, rarely consider the effects of impurities in the determination of design parameters. Aspen HYSYS (ver.9) is used to model the effect of impurities on the pressure drop, phase envelope and critical pressure and temperature of captured CO2 fluids flowing in pipelines. Cortez, Canyon Reef and Choctaw pipelines in the USA and Weyburn pipeline in Canada were selected as the case studies. The results show that the pressure drop increased in these pipelines due to the impurities with the highest pressure drop occurring in the Canyon Reef pipeline. The impurities increased the pressure drop by about 0.09 bar/km, 0.2 bar/km, 0.10 bar/km and 0.04 bar/km for Cortez, Canyon Reef, Choctaw and Weyburn pipelines respectively. The lower molecular weight gases were found to decrease the mixture density and increase the pressure drop. The results also reveal that the bubble point pressure was increased by impurities in three pipelines but slightly reduced in the Weyburn pipeline and the critical temperature was reduced in all pipelines. Keywords: Impure CO2, phase envelope, CO2 transportation, pressure drop. 1. Introduction As the emission of greenhouse gases rises, the need for global warming mitigation efforts are expected to increase. This need was brought to the fore once again in the recent Paris agreement which entered into force on 4 November 2016 where 193 signatories signed onto the agreement (United Nations, 2015). It is hoped that most of these countries would take practical steps in capturing CO2 and transporting it to storage sites or for enhanced oil recovery (EOR) operations or other uses. Up to 360,000 km of pipelines may be required to transport the CO2 captured from industrial processes by 2050 (IEA GHG, 2014). The United States, the leading country in CO2 pipeline infrastructure, is projected to construct additional CO2 pipelines of between 17,700 and 37,000 km before 2050 (Dooley et al., 2009). Therefore, more pipelines would be constructed to transport the increased volume of CO2 captured from large point sources (Mazzoldi et al., 2008). There were just over 6,500 km of CO2 pipelines worldwide with most transporting CO2 for enhanced oil recovery in the United States (Dooley et al., 2009, Noothout et al., 2014, IEA GHG, 2014). CO2 is transported in pipelines above the supercritical pressure of 73.8 bar and temperature of 31.1 oC to keep it in supercritical state. Some researchers reported pipeline operating pressures and temperatures to range from 86.2 to 151.7 bar (Forbes et al., 2008), 100 to 150 bar and 15 to 30 oC (Patchigolla and Oakey, 2013) and 85 to 150 bar and 13 to 44 oC (Kang et al., 2014). CO2 pipeline streams are usually impure and may contain several impurities. Porter et al. (2016) classified CO2 stream impurities into three main categories arising from fuel oxidation, excess oxidation/air ingress and process fluids. These impurities affect both the physical and thermodynamic behaviour of the CO2 fluid. Table 1 shows CO2 captured from both natural and industrial sources. The type and percentage of the impurities depend on the source (naturally occurring or fuel type) and type of capture (pre-combustion, oxy-fuel or post- combustion). CO2 pipeline streams may contain nitrogen, methane, hydrogen sulphide, carbon monoxide, DOI: 10.3303/CET1757060 Please cite this article as: Peletiri P.S., Rahmanian N., Mujtaba I.M., 2017, Effects of impurities on co2 pipeline performance, Chemical Engineering Transactions, 57, 355-360 DOI: 10.3303/CET1757060 355 nitrogen oxide, oxygen, sulphur oxide, hydrogen, water, etc. (Li et al., 2011), these impurities may arise from combustion products, fuel type, air ingress, CO2 capture materials and chemicals (Porter et al., 2015). Table 1: CO2 pipelines with impurities in mol % (Patchigolla and Oakey, 2013). Canyon Reef Carriers Central Basin Pipeline Sheep Mountain Cortez Pipeline Weyburn CO2 85 – 98 98.5 96.8 – 97.4 95 96 CH4 2 -15 2 – 15 1.7 1 – 5 0.7 N2 < 0.5 < 0.5 0.6 – 0.9 4 < 0.03 H2S < 0.02 < 0.02 wt 0.002 0.9 C2+ 0.3 – 0.6 Trace 2.3 CO 0.1 O2 < 0.001 wt < 0.005wt H2 Trace H2O 0.005 wt 0.0257 wt 0.0129 wt 0.0257 wt 0.002 v To effectively design a CO2 pipeline, several factors are taken into consideration, including flow assurance, pipeline integrity, pipeline operations and health and safety (Lazic et al., 2014). The physical properties, density and viscosity, of the flowing fluid are either direct or indirect input parameters into the pressure calculation equation of CO2 pipelines and must be determined correctly. Density of CO2 increases if the pressure increases or temperature decreases, while the viscosity increases with increase in pressure (Yener et al., 1998) and increase in temperature. Since CO2 is transported in the supercritical phase in pipelines, the critical pressure and temperature need to be determined. The change in the critical pressure and temperature may not be significant due to the high content of CO2. However, for design purposes, the pressures and temperatures that will cause a change in phase, temperature and pressure variations has to be known. The Peng-Robinson EOS, which had the least absolute average deviation (AAD) among the cubic EOS for predicting density of binary CO2 mixtures (Mazzoccolia et al. 2013) and the best in calculating critical temperature and pressure of CO2 (Zhao and Li, 2014), was used in Aspen HYSYS (ver.9). The following assumptions were made:  Pipelines are horizontal though recognising that the pipelines considered may not be horizontal for the entire length.  The input (maximum) pressure for all pipelines is 150 bar.  Minimum operating pressure is 100 bar. 2. Critical points CO2 pipelines operate above the critical pressure and temperature to keep the fluid in a single phase during transportation. It is therefore imperative to know the critical pressure and temperature of the streams in pipeline fluids for effective operation. All impurities increase the critical pressure and only SO2 and H2S increase the critical temperature while all others reduce the critical temperature. An increase in critical pressure requires more energy for compression of the fluid to supercritical state. Table 2 lists the critical pressure and critical temperature of a stream of 10 % impurity in 90 % CO2. Table 3 shows the critical pressure and temperature of pure CO2 and the four pipelines. Table 2: critical pressure and critical temperature of pure components. Components CO2 CH4 N2 H2S O2 SO2 CO NO H2 Critical pressure (bar) 73.7 79.39 88.15 74.53 86.44 85.11 87.83 89.1 107.7 Critical temperature (oC) 30.95 23.25 23.61 33.29 24.41 49.84 23.48 24.83 28.34 Table 3: critical pressure and critical temperature of pipelines Pipelines CO2 Cortez Weyburn Choctaw Canyon Reef Critical pressure (bar) 73.7 78.88 73.38 79.51 80.30 Critical temperature (oC) 30.95 27.57 29.17 26.51 22.46 356 3. Pressure drop Rich CO2 pipelines are usually in the dense phase with pressures above the critical pressure value, without discontinuities in the fluid properties when the temperature drops below the critical value (Raimondi 2014). In CO2 pipeline design, CO2 flow rate is ascertained and pipeline pressure drop and optimal pipeline diameter are calculated. Several researchers have proposed different forms of similar equations for the determination of pipeline diameter and/or pipeline pressure drop. The one given in IEA GHG (2002) is presented in Eq(1). ∆P=2.252 f L ρ Q 2 Di 5 (1) where ΔP = pressure drop (bar), f = friction factor, L = pipeline length (km), ρ = fluid density (kg/m3), Q = flow rate (l/m) and Di = pipeline inner diameter (mm). The equation presented by Chandel et al.,( 2010) incorporating elevation changes is given in Eq(2). ∆P= f ρ l u 2 2 Di + ρ g ∆z (2) where ∆P is pressure drop (MPa), f is friction factor, l is the length (m), u is velocity (m/s), Di is the pipeline internal diameter (m), ρ is the fluid density (kg/m3), g is acceleration due to gravity (m/s2) and ∆z is change in elevation (m). Both density, ρ and friction factor, f are functions of fluid composition and the amount of impurities in the stream affect both of these parameters. Impurities in CO2 pipelines may range from 0.1 % to above 10 %. Kaufmann (2011) stated that as long as the impurities concentration is not much greater than 2.5 %, the critical pressure increase also remains below 5 %. This marginal increase in critical pressure is important for design purposes and most pipelines contain more than 2.5 % impurities. Most impurities cause an increase in the critical pressure and pressure drop in CO2 pipelines. This is of great concern as it increases both the capital cost and operations and maintenance (O&M) cost of CO2 pipelines. Hydrogen (H2) when present causes the most pressure drop and sulphur dioxide (SO2) has the highest reduction of pressure loss. Figure 1: Relative pressure drop due to pure components Figure 2: Relative pressure drop of 10% single impurity in Co2 fluid 357 Figure 1 shows the pressure drop of pure impurities in a 70 km, 457.2 mm diameter pipeline with a flow rate of 100 kg/s and input pressure of 150 bar. The pressure losses of a pure hydrogen pipeline is 87.5 times that of pure CO2 and SO2 has only 0.66 times that due to pure CO2. Figure 2 shows a comparison of 10 mol % single impurity and 90 mol % CO2 stream. Though the presence of water is undesirable because it may cause pipeline corrosion, two-phase flow or block the pipeline due to hydrate formation (Chapoy et al., 2013), it reduces the pressure loss. Single components in a similar pipeline showed the following pressure drops in comparison to pure CO2. SO2 – 65 %, H2O – 94 %, H2S - 112 %, O2 – 396 %, NO – 451 %, N2 – 489 %, CO – 490 %, CH4 - 734 % and H2 – 8039 %; see Figure 1. For 10 % single impurity, the binary component fluids showed the following percentages of pressure drop relative to pure CO2. SO2 – 89.5 %, H2O – 94.3 %. H2S – 100.3 %, O2 –119.3 %, NO – 121.4 %, CH4 – 122.4 %, CO – 125.8 %, N2 – 125.5 % and H2 – 142.7 %; see Figure 2. 4. Phase envelopes Though CO2 pipelines are defined as pipelines with 90 % or more of CO2 at supercritical pressures, there are some advantages of transporting liquid CO2 over supercritical CO2 including increased volume transported due to increased density and reduced pressure losses (Zhang et al., 2006). CO2 fluids enter the liquid phase if the temperature drops below the critical temperature when pressures are above the critical pressure. All pipelines considered here show reduced critical temperatures. Figure 3 shows the phase diagrams of the four pipelines. Figure 3: Phase envelopes of Cortez, Canyon Reef, Choctaw and Weyburn pipeline fluids. The dew point curves of all pipelines closely matched the liquid – vapour line of pure CO2. The two – phase region widens as the percentage of impurities and fraction of lighter gases increase. The P – T diagram of the Weyburn pipeline closely matched that of pure CO2 because it has the least percentage of impurities and a 0 20 40 60 80 100 -200 -150 -100 -50 0 50 P re ss u re ( b a r) Temperature (oC) Cortez Bubble point Dew point Pure CO2 0 20 40 60 80 100 -200 -150 -100 -50 0 50 P re ss u re ( b a r) Temperatire (oC) Canyon Reef Bubble point Dew point Pure CO2 0 10 20 30 40 50 60 70 80 90 -200 -150 -100 -50 0 50 P re ss ur e, (b ar ) Temperture (oC) Choctaw Bubble point Dew point Pure CO2 0 10 20 30 40 50 60 70 80 -150 -100 -50 0 50 P re ss u re ( b a r) Temperature (oC) Weyburn Bubble point Dew point Pure CO2 358 fairly high fraction of C2+ which is not in other pipelines. The wider the bubble and dew point curves, the easier the fluid enters the two – phase region during transportation due to a reduction in temperature and/or pressure. The pressure drop due to impurities under the above assumptions, increased the number of booster stations from four to five for Cortez, 2 to 3 for Canyon Reef, but no change at two each for Choctaw and Weyburn pipelines. 5. Conclusions For optimum operation of CO2 pipelines; flow rates, pressures, temperatures and impurities in the stream must be adequately known. These factors are then used in the design and operation of the pipelines. The effect of impurities on the phase envelope, pressure drop and critical pressure and temperature has been studied and the following conclusions are reached.  No impurity is desirable because they create a two-phase region.  The lighter components than CO2 cause an increase in pressure losses.  The relative pressure drop due to impurities in the pipelines range from 4 % to 20 % a. Cortez pipeline – 9.03 % b. Canyon Reef – 20.25 % c. Choctaw – 10.25 % d. Weyburn – 4.02 %  H2, though not present in any of the pipelines considered, when present causes the highest increase in pressure drop followed by CO, N2, CH4. NO, O2 and H2S while H2O and SO2 cause a decrease in pressure loss.  All common impurities increase the critical pressure of the CO2 fluid. Only the Weyburn pipeline showed a reduction in critical pressure and this may be due to the presence of C2+ represented by C2H6. An increase in critical pressure requires higher operating pressures and consequently stronger or thicker pipes and higher energy requirements for compression to keep the fluid in the supercritical state.  All pipelines showed critical temperatures lower than the critical temperature of pure CO2. However, when pressures are above the critical pressure, the temperature is not a serious consideration unless temperatures drop low enough for solid formation. 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