CO2 capture from high concentration CO2 natural gas by pressure swing adsorption at the CO2CRC Otway site, Australia

International Journal of Greenhouse Gas Control 83 (2019) 1–10

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CO2 capture from high concentration CO2 natural gas by pressure swing adsorption at the CO2CRC Otway site, Australia Lefu Taoa,b,c, Penny Xiaoa,b,c, Abdul Qaderc, Paul A. Webleya,b,c,

T

⁎

a

Department of Chemical Engineering, The University of Melbourne, VIC 3010, Australia The Peter Cook Centre for Carbon Capture and Storage, The University of Melbourne, VIC 3010, Australia c The CO2CRC Limited, Carlton, VIC 3053, Australia b

A R T I C LE I N FO

A B S T R A C T

Keywords: PSA CO2capture Natural gas Otway CCS research facility Demonstration rig

Natural gas is one of the fossil fuels with the lowest CO2 emissions per unit energy produced. The removal of CO2 from natural gas is therefore extremely important to promote its use. For this purpose, CO2CRC Ltd., the leading CCS R&D organization in Australia, has designed and implemented a carbon capture demonstration skid at the Australian Otway National Research Facility. The skid includes a Pressure Swing Adsorption (PSA) rig designed to remove CO2 from a high CO2 content natural gas supply in the Otway basin. Two months of operation had been carried out from May 2017 to June 2017, with the feed natural gas containing CO2 in a range from 30% to 50% using commercially available adsorbents to obtain benchmarking data. The results of operation showed that the PSA rig can successfully capture CO2 from high pressure natural gas with a recovery of 66%. However, the purity of the final CH4 product was not sufficient to meet general natural gas requirement (only achieving 80% instead of 95%). This was attributed to the fact that the operating conditions were not optimal: a final desorption pressure of 1 bar abs was desirable but only 5 bar abs was achieved. Based on our preliminary PSA operating results, process simulation were also conducted to predict the separation performance at lower desorption pressures, and showed that a methane purity of over 98% can be achieved if the desorption pressure can be lowered to 1 bar.

1. Introduction The Paris Climate Agreement signed by 195 regions and countries set an ambitious target to keep the global temperature rise by the end of this century to below 2 °C above pre-industrial level and pursue a further aim of limiting the temperature increase to 1.5 °C. To accomplish this objective, a series of unprecedented mitigative emission measures have to be implemented globally. One feasible way to reduce the major emission source, CO2 from the use of fossil fuels, is to improve the fuel efficiency by replacing the traditional coals with lower emitting fuels such as natural gas. However, one challenge to access a sufficient amount of natural gas to fulfil the worldwide fossil fuels demand lies in that roughly half of the gas reservoir contains more than 2% sour gas, and gas reservoirs in the area of Southeast Asia and Northwest of Australia can contain more than 15% and up to 80% CO2 (Burgers et al., 2011). The presence of high concentration of CO2 and even H2S makes these gas reservoirs less desirable due to the inevitable economic, environmental and safety issues involved during the gas sweetening process.

⁎

Currently, the most mature and applied gas sweetening process is the solvent based absorption process and the combination of absorption and membrane system, neither of which, however, is sufficiently effective to deal with a gas source with both an elevated gas well-head pressure and highly soured contents. Adsorbent based processes may be applicable to separate CO2 from natural gas in high CO2 fields. Several previous studies have shown that higher concentration of CO2 facilitates the separation of CO2 through adsorption processes (Ling et al., 2015; Zhang et al., 2008; Huang and Eić, 2013). In addition, the elevated pressure occurring in conventional natural gas fields, which inherently provides the driving force for the separation, can potentially make the adsorption process a low-energy one. Adsorption processes are frequently applied in the areas of air separation and natural gas dehydration, but as to the applications of CO2 removal from natural gas, they are still in the R&D phase. There are two critical factors when implementing an adsorption based gas separation: an effective PSA cyclic process design and the selection of the appropriate adsorbents. Santos et al. carried out a biogas upgrading process on a two-bed

Corresponding author at: Department of Chemical Engineering, The University of Melbourne, VIC 3010, Australia. E-mail address: [email protected] (P.A. Webley).

https://doi.org/10.1016/j.ijggc.2018.12.025 Received 2 October 2018; Accepted 27 December 2018 1750-5836/ © 2018 Elsevier Ltd. All rights reserved.

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Fig. 1. Scheme of CO2CRC Otway Capture skid.

In industry, one of the early patents assigned by Air Products & Chemicals (Kumar, 1990) is to remove CO2 from natural gas using carbon-based porous materials in a pressure-vacuum swing adsorption (PVSA) process at a pressure of up to 35 bar (500 psia). Engelhard (now BASF Catalysts) applied their Molecular Gate™ technology initially for nitrogen rejection from natural gas using pressure swing adsorption (PSA) processes (Butwell et al., 2001), and later successfully for CO2 separation as well. The proposed adsorbents for this technology was a type of synthetic titanosilicate ETS-4. Xebec Adsorption Inc. developed a new approach named Rapid Cycle PSA (RCPSA™) (Allzadch-Khlavi et al., 2007) which significantly reduced the total footage of the separation units. Instead of bulky piping and valves, RCPSA™ used two rotary valves in a compact and integrated system, which allowed similar throughput but only in 1/20 of the conventional PSA process footprint. ExxonMobil refinery has built and operated a prototype of RCPSA™ units for obtaining high purity hydrogen production, and theoretically it could be repurposed for natural gas sweetening. CO2CRC’s National Research Facility at the Otway site contains 400,000 tonnes of in-situ CO2 and methane mixture, which could serve as a prefect source for long term testing of different natural gas sweetening processes at scale. The design of our Capture Facility provides a feed gas composition from 5% to up to 79% CO2, spanning the range of most naturally occurring natural gas wells. The CO2 capture demonstration skid at the Otway site is shown in Fig. 1, and will test new membranes and adsorbents for novel CO2 capture applications. The capture skid includes a two-bed adsorption unit, with provision for running a general adsorption cycle. In this work, inspired by the silicate material MCM-41, we used a commercially available high silica adsorbent, Sorbead WS, in the high pressure adsorption rig. The adsorption isotherms were first characterized experimentally, and the adsorptive selectivity and working capacity were calculated accordingly. We then examined and verified the concept and designs of the adsorption rig to separate CO2 from high sour content natural gas in field. The field outcomes were used to validate our process simulation which was then subsequently used for prediction.

PSA system, and studied the recycle effect of the pressure equalization and purge streams on the performance. They showed that the process with a pressure equalization step out-performed other processes (Santos et al., 2011). Kang et al. used a four-bed PSA experimental apparatus to separate CO2 from biogas (54.9% CH4 and 45.1% CO2) (Kim et al., 2015). By comparing with process simulation results, they found several general rules for guiding future CO2/CH4 adsorptive separation design using PSA processes. For both of the aforementioned studies, the highest pressure during the process was around 4 bar, which was far below the practical pressure for the application to natural gas sweetening. Grande and his colleagues have recently completed studies on high pressure CO2/CH4 separation using PSA processes. They designed a complex PSA cycle to achieve the required separation performance for the purpose of natural gas sweetening (Grande et al., 2013, 2017). According to their simulation results, a well-designed 12-bed PSA system could treat a natural gas feed stream with 10% CO2 at a flowrate of 500,000 m3/h and achieve a purity of 97.8% CH4 in the hydrocarbon product stream, which is just suitable for piping transportation, and a purity of 84.5% CO2 in the CO2 product stream. As the authors pointed out, however, the immense footage requirement of a 12-column PSA plant as well as the loss of methane in the CO2 product stream become the major drawback when compared with the conventional absorption based process. This study is the most relevant PSA technology study to separate CO2 from natural gas, but no corresponding trial rig was built to follow the research finding. The adsorbents used for removing CO2 from methane include activated carbon (Grande et al., 2013; Lopes et al., 2009), carbon molecular sieves (CMS) (Santos et al., 2011; Grande et al., 2017; Cavenati et al., 2005; Jayaraman et al., 2002; Rocha et al., 2017; Ribeiro et al., 2010), and zeolites (Cavenati et al., 2004; Gholipour and Mofarahi, 2016; Cavenati et al., 2006). Recently, highly-ordered silica (Belmabkhout et al., 2009; Belmabkhout and Sayari, 2009), zeolitic imidazolate frameworks (ZIFs) (McEwen and Hayman, 2013), and metal-organic frameworks (MOFs) (Furukawa et al., 2010; Saha et al., 2010) were studied as novel adsorbents to achieve CO2/CH4 separation, but few of these studies were applied to high pressure gas adsorptive separation. Grande et al. chose traditional adsorbents such as CMS and activated carbon for high pressure process evaluation, however, the separation performance was not satisfactory (Grande et al., 2013; Grande et al., 2017). MOFs showed outstanding CO2 to CH4 selectivity and capacity at high pressure. However, because of its vulnerable structures under moisture and elevated temperature, as well as its extraordinarily high cost, MOFs are still not feasible to be applied in large scale CO2/CH4 PSA separation processes. MCM-41, a periodic mesoporous silicate material, demonstrated promising properties for natural gas sweetening. Its selectivity of CO2 over CH4 at 45 bar 298 K could reach around 8, and with an increasing trend as the total pressure rises (Belmabkhout and Sayari, 2009).

2. Materials and methods 2.1. Adsorbents textural properties and isotherm measurements The adsorbent employed in this study was Sorbead WS, which is a alumino-silicate gel adsorbent in form of hard spherical beads. It is most frequently used as a protective layer to pre-dehydrate a gas stream before going to further gas processing units. After measuring the adsorption isotherms on Sorbead WS and calculating the working capacity, the results revealed it to be a potentially excellent adsorbent for CO2/CH4 adsorptive separation. The textural properties (surface area, 2

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Table 1 Textural properties of Sorbead WS. Typical properties Chemical composition Surface area (BET) Pore volume Packed bulk density

Value SiO2 Al2O3

97 wt.% 3 wt.% 650 m2/g 0.45 cm3/g 0.7 kg/L

pore volume and composition) of the Sorbead WS from BASF along with bulk properties were provided by the vendor in Table 1. 2.2. Adsorption isotherms Isotherms data of CO2 and CH4 on Sorbead WS at 303 K, 313 K, 333 K were measured on two instruments: a static volumetric analyser ASAP 2050 (Micrometrics, USA), and a gravimetric analyser magnetic suspension balance Rubotherm (Rubotherm, Germany). The gas pressure range of ASAP 2050 is 0–10 bar while that of the Rubotherm balance is 0–200 bar. Prior to isotherm measurements, adsorbents were degassed at 350 O C for 12 h at a pressure less than 2 Pa following a pre-evacuation period of 2 h at 100 OC. The purpose of the degassing is to remove impurities, especially moisture, from the pores of the adsorbents. The heating ramp was set to 2 OC/min to prevent the microporous structures of adsorbent from collapsing because of steaming. The single component adsorption isotherms of both CO2 and CH4 obtained from each instrument were then fitted to a Dual-Site Langmuir (DSL) Model as shown in the equations below (Eqs. (1),(2)).

m1 B1 P m2 B2 P n* = + 1 + B1 P 1 + B2 P

(1)

Q Bi = b0, i exp (− i ) RT

(2)

Fig. 2. Demonstration of Working Capacity (WC) calculation.

A 10-step cycle including adsorption, pressure equalization with the buffer tank, pressure equalization between two beds and desorption is shown in the scheduling Table 3.

• Step 1 – Feed mixture gas enters bed 1 co-currently. CO • • • • •

where P is the equilibrium pressure, T is the gas temperature, R is universal gas constant, mi , b0, i and Qi are Langmuir isotherm parameters, where i is 1 or 2.

2 is selectively adsorbed to the adsorbent and rich CH4 gas is collected from the top port of bed 1. Bed 2 is under counter-current desorption. Rich CO2 product exits from the bottom of bed 2. Step 2 – Connect the bed 1 to the buffer tank for a co-current pressure equalization, while bed 2 continues for the desorption process. Step 3 – Connect bed 1 and bed 2 for an inter-column pressure equalization. Step 4 – Bed 1 begins desorption and collect rich CO2 gas stream. Bed 2 is pressurised by the buffer tank. Step 5 – continue for desorption at bed 1. Bed 2 is pressurised by the feed gas mixture. Step 6–10 – Repeat of step 1–5 with the beds switched.

2.3. Working capacity and selectivity

2.5. Process simulation

The theoretical working capacity (WC ) can be calculated directly when adsorption isotherms are available (Eq. (3)):

To have a better understanding of the dynamic behaviour of the process as well as the mass and heat profile in the beds, parallel simulations were also conducted in comparison with the experimental data. All simulations were carried out in our in-house numerical simulator MINSA (Monash Integrator for Numerical Simulation of Adsorption), which was initially designed by Webley et al. (Todd et al., 2001). MINSA applies the Fast Finite-Volume Method to simulate PSA/ VSA cycles. It has been employed extensively and verified by experimental data over the past two decades for various adsorption processes studies including H2 purification, CO2 capture from flue gas and natural gas processing(Ling et al., 2015; Jiang et al., 2018; Zhang and Webley, 2008; Xu et al., 2012; Xiao et al., 2009, 2008). Several assumptions are applied for MINSA simulation:

WC = n * (P1) − n * (P2)

(3)

where nads (P1) and nads (P2) is the gas adsorbed amount at partial pressure P1 (normally in adsorption step) and P2 (normally in desorption step) respectively. For the less adsorbed component, methane in this case, the partial pressure at the end of the desorption step is assumed to be 0 as shown in Fig. 2, although this may not be the case in practical use, especially if the desorption pressure is relatively high. The selectivity (S ) of CO2 over CH4 is calculated by Eq. (4).

S=

WCCO2 WCCH4

(4)

(i) Ideal gas law was applied as the equation of to calculate the P-V-T relationship. (ii) Gas flow in the axial direction is assumed to be plug flow model without dispersion, while radial concentration, velocity and temperature gradients are negligible. (iii) Local thermal equilibrium between the homogeneous bulk phase and the adsorbent particles occurs instantaneously. (iv) Cross-sectional area and voidage along the column is identical.

2.4. Adsorption plant details The adsorption plant is a part of the CO2CRC capture skid, along with a membrane testing facility. A schematic of the plant is shown in Fig. 3. The process is an improved version of the Skarstrom adsorption process with a buffer tank for an additional step of pressure equalization. The details of the fixed-bed and the buffer tank, together with the general operating conditions for the adsorption plant on the capture skid are listed in Table 2.

The governing model equations for adsorption, consisting of a set of 3

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Fig. 3. Photo and Schematic of Adsorption Plant.

ρ RT ∂ni ∂ (Pyi ) Py ∂T ε T ∂ ⎛ υPyi ⎞ − i =− b − b ∂t T ∂t εt ∂z ⎝ T ⎠ εt ∂t

Table 2 Details of the column and buffer tank of the adsorption plant. Properties

Values

Column radius Column length Column wall Bulk density of adsorbent Porosity of adsorbent Volume of the buffer tank Feed gas pressure Feed gas molar compositions

60 mm 800 mm 4.5 mm 700 kg/m3 0.37 15 L 30 bar 30% CO2 + 70% CH4 50% CO2 + 50% CH4 40 OC 500 s 5 - 7 bar 2000 s

Feeding temperature Adsorption time Desorption pressure Desorption time

where yi is the component mole fraction, εb and εt are the voidage of the bed and total voidage (including beads voidage), υ is the bulk gas superficial velocity in m / s , ρb is the bulk density in kg / m3 , P and T are absolute pressure and temperature respectively. Rate of mass transfer is described by the linear driving force model. (Ruthven et al., 1994)

∂ni = ki (ni* − ni ) ∂t

ni* =

Bed 2

DE↓

2 PE BT↑

3 PE↑

4 DE↓

5

6

7

8 PE↓

PE↓

PE BT↓

RP↑

AD↑

PE BT↑

PE↑

9 PE BT↓ DE↓

m1, i B1, i Pi m2, i B2, i Pi + n n 1 + ∑ j = 1 B1, j Pj 1 + ∑ j = 1 B2, j Pj

(7)

Momentum balance. Pressure drop through the bed is estimated by the popular Ergun equation, which is valid for both laminar and turbulent flow regimes.

Steps 1 AD*↑

(6)

where ni* is equilibrium adsorbent loading of component i in mol/ kg and ki is mass transfer coefficient of component i in s−1. The multi-component adsorption equilibrium was calculated by the extended Dual-site Langmuir equation.

Table 3 Cyclic configuration of the PSA cycle.

Bed 1

(5)

10 RP↑

1.75(1 − εi ) ρb 2 150μ (1 − εi )2 ∂P =− υ0 − υ0 ∂z εb3 dP2 εb3 dP

(8)

where μ is the viscosity of the bulk phase, and dp is the characteristic dimension of the adsorbents. Energy balance: The beds were considered non-isothermal (due to the appreciable swing in bed temperature observed in the experiments). An overall energy balance for systems can be described the equation follows:

*AD – Adsorption, PE BT – Pressure equalization with buffer tank, PE – Pressure equalization with the other bed, DE – Desorption, RP – Re-pressurization. The arrow direction refers to the gas stream flowing direction.

partial differential equations describing the mass, momentum and energy transport between the gas and solid phases, as well as various equilibrium isotherm models are in-built in the software. Some specifications/assumptions were made in modelling the process to match the current experimental system. Mass balance. The general unsteady-state mass balance is:

ρS

∂ (ρb Ug ) ∂ (υρb Hg ) ∂US 4h w l 0 + εt = −εt − (T − Tw ) ∂t ∂t ∂z Dυ

(9)

where ρS is the adsorbents bulk density, US and Ug are internal energies of adsorbents and gas calculated separately in Eqs. (10) and (11), Hg is 4

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Fig. 4. Adsorption isotherms of CO2 and CH4 at 303 K, 313 K and 333 K on Sorbead WS. Symbols – experimental data; Lines – Dual-Site Langmuir model fitting results.

enthalpy of gas phase, h w is the heat transfer coefficient between bulk gas phase and the column wall, D is column radius and l 0 is dimensionless length of the column. Other variables follow the same definition as previous equations.

P Ug = Hg − ρg ⎛ US = ⎜CS + ⎝

i=m

∑ Cpi ni ⎞⎟ (T − T0) − ⎡⎢ ∑ ∫0 ⎣ i=1

⎠

ni

⎤ ΔHi (s, T ) ds⎥ ⎦

(11)

Where CS is the specific heat capacity of the adsorbents, Cpi is the specific heat capacity of the component i in the gas phase, ΔHi (s, T ) is isosteric heat of adsorption for component i in gas phase, and T0 is a reference temperature. 3. Results 3.1. Adsorbent isotherms, working capacity and selectivity

Feed CO2 composition (%)

CO2 working capacity (mmol/ g)

CO2 to CH4 working selectivity

1 2 3 4 5 6 1 2 3 4 5 6

30

2.04 1.61 1.27 1.00 0.76 0.55 2.92 2.49 2.15 1.88 1.64 1.43

1.81 1.43 1.13 0.89 0.68 0.49 3.30 2.81 2.43 2.12 1.85 1.61

3.2. PSA results Separation experiments were carried out on the adsorption rig for 2 months from 5th May 2017 to 4th July 2017 under various operational conditions. Each of the conditions are listed in Table 6. Because the capture of CO2 from high CO2 content natural gas is the main target of our project, the feed CO2 concentration for the experiments was maintained from 30% to 50% CO2. In order to avoid CH4 gas emission to the atmosphere, the exiting gas with enriched CH4 in the top stream and the desorbed gas with enriched CO2 in the downstream line were combined and passed to a thermal oxidizer. Due to the limitation of the initial design of the pipeline, the small pipe size negatively affected the desorption process due to excessive pressure drop. The desorption pressure was unable to reach 1 atmospheric pressure in the given

Table 4 Dual-Site Langmuir model parameters of the isotherms for CO2 and CH4 on Sorbead WS. Terms

CO2

CH4

m1 (mmol/ g ) b0,1 (1/ bar )

1.89 2.56E-05

1.89 5.14E-04

Q1 (kJ / mol) m2 (mmol/ g ) b0,2 (1/ bar )

23.97 15.96 2.37E-06

10.46 2.76 1.50E-06

20.87

50

be determined by the desorption pressure and the inlet CO2 concentration. In the calculation, CO2 concentration in the downstream gas was assumed to be 100%. As expected, the working capacity of CO2 declines when the composition of CO2 in the feed stream decreases. The same trend can be observed as well when the desorption pressure increases. It is noted that the theoretical selectivity of CO2 to CH4 at certain conditions could even drop to below 1, which means the adsorbent becomes CH4 selective rather than CO2 selective. This is attributed to the linearity of the adsorption isotherms of CH4, especially at a low CO2 partial pressure range where the total adsorbed amount of CO2 would be lower than that of CH4 at high partial pressure. This also highlights just how challenging it is to develop an effective PSA process for high pressure natural gas streams.

Fig. 4 shows the adsorption isotherms of single component CO2 and CH4 on Sorbead WS at 303 K, 313 K and 333 K between 0–45 bar (CO2) and 0–80 bar (CH4). Note that the data points of each isotherm (shown as open square) were a combination of ASAP 2050 results at the low pressure range of 0–10 bar and Rubotherm results at the high pressures from 10 bar to the highest end, because in the range of 0–10 bar ASAP 2050 has a better precision than Rubotherm. The isotherms data points were fitted to Dual-Site Langmuir Model as described in Eq. (1) and plotted as the solid lines in the graph. The fitted DSL model parameters are provided in Table 4. The working capacity of CO2 and selectivity of CO2 over CH4 at the experimental operational conditions were then calculated according to the fitted model parameters (Table 5). The feed pressure was fixed at 30 bar in the site experiment. The working capacity and selectivity can

Q2 (kJ / mol)

Desorption P (bara)

(10)

i=m i=1

Table 5 Working capacity and selectivity of CO2 over CH4 at various desorption pressures with the feed pressure of 30 bara.

21.31

5

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cyclic curve). In this case, the pressure of both beds after inter-column pressure equalization reached 14 bar, lower than that if the buffer tank was absent. Fig. 7 shows the profiles of the feed gas flowrates and exiting gas flowrate of the CH4 product stream. When combining Figs. 6 and 7, it can be found that majority of the gas entered the system at beginning of the re-pressurization phase once the solenoid valve was opened at the bottom of the bed, since the pressure in feed gas was 30 bar while the pressure inside the column was around 19 bar; then the feed flowrate trended to very low or zero once the pressure in the bed was close to that of the feed gas. The same case occurred for the beginning of the adsorption step since the pressure at a feed stream pipeline was higher than that set for the back pressure regulator. For the exiting stream, high flowrate only occurred at the adsorption step for each cycle when the solenoid valve at the top of the bed was open; and then the flowrate decreased gradually once the pressure after backpressure regulator was built up. The outlet flowrate of the pipeline was limited to 3–4 s L/min to protect the thermal oxidizer. From Fig. 7, it can be observed that the flowrate peaks in exiting stream and feed stream for the adsorption step were in good synchronization. The flowrate values of the exiting streams fluctuated as partial gas was taken in the flowrate of 1–2 s L/ min by analyzer. However, the high pressure gas from the top stream always had a priority to pass the pipeline in comparison with the downstream gas so that the changeable flowrate did not affect the separation performance at the same desorption pressure. The entire system was covered with heating tape and isolation materials, so that the temperatures at the top and bottom of the bed were maintained at an average of 40 and 55 °C, respectively, in Fig. 8. The temperature swing in the bed was clearly shown with the two temperature lines, that is, temperature rose at adsorption and dropped during desorption. Meanwhile, the feed gas was heated to 40 °C but it slightly changed with the ambient temperature. Because the desorption pressure was not deep (only 5 bar), the CO2 concentration in the downstream gas was only 60% and CH4 purity in the top stream was only 80%. The separation efficiency can be significantly improved by lowing the desorption pressure, which will be discussed next.

Table 6 Running conditions in the initial experiment. CO2 feed composition (%)

Adsorption step time (s)

Desorption step time (s)

Feed flowrate (sL/min)

Desorption pressure (barg)

30 28 45 45 50

1500 500 500 600 600

3000 4000 4000 4100 5600

7.3 9 5 4.5 4.5

3.5 5 7 7 6

desorption time. As shown in Table 5, a lower separating “driving force” is one consequence of the high desorption pressure and contributes to a poor CO2 working capacity and selectivity, consequently, an unsatisfactory separation performance. Even though the desorption pressure was up to 5 or 7 barg as shown in Table 6, the actual results (Table 7, also demonstrated in Fig. 5) collected on site still display a positive separation performance. When the inlet CO2 concentration was 28%, the bottom product stream was enriched to 41% CO2 concentration while the top stream contains only 12% CO2 (24th May 17 data point). When the inlet CO2 was increased to 45% from 13th June 2017, the CO2 concentration of the bottom product rose to 55% and the top product contained 19% CO2. The results also reveal that it is essential to further reduce the desorption pressures to release more CO2, hence optimization of the cycle time is needed. 3.3. Detailed operation results with the adsorption rig The detailed experimental data including the bed profile information collected in one day of running (24th June 2017) were retrieved to show the operating status of the adsorption rig. Fig. 6 clearly shows the pressure swing cycles during the PSA process on the rig. The adsorption step was conducted at a constant high pressure of 29 bar, and the lowest pressure at the end of the desorption step averaged around 5 bar between the two beds, which was probably related to non-uniform bed packing. The buffer tank provided a reservoir for holding the gas from one bed, reducing the pressure of this bed after the adsorption step from 29 bar to an intermediate pressure level of 22 bar, meanwhile refilling the other bed to 19 bar (shown as two shoulder plateaus in the pressure Table 7 Representative experimental results from 5th May 2017 to 4th July 2017. Date

Feed Gas (mol%)

Top Stream (mol%)

Blowdown Stream (mol%)

Avg. Flowrate

CO2 CH4 CO2 CH4 CO2 CH4 (sL/min) 30% CO2 in feed gas stream from 10-May-2017 (52 OC – bottom and 40 OC - top) 10-5-17 29 71 18 82 48 52 7.39 11-5-17 30 70 17 83 52 48 7.39 23-5-17 28 72 12 88 41 59 6.5 24-5-17 28 72 12 88 41 59 6.9 Reduce adsorption time to 1000s from 24-May-2017 (55 OC – bottom and 35 OC - top) 28-5-17 32 68 17 83 45 55 7.8 29-5-17 32 68 17 83 45 55 7.8 Reduce adsorption time to 500 s from 29-May-2017 (54 OC – bottom and 37 OC - top) 4-6-17 26 74 12 88 39 61 9.0 5-6-17 27 73 12 88 36 64 8.9 6-6-17 28 72 11 89 39 61 8.35 7-6-17 29 71 12 88 38 62 8.3 45% CO2 in feed gas stream from 7-Jun-2017 (61 OC – bottom and 46 OC - top) 13-6-17 42 58 19 81 52 48 4.75 14-6-17 45 55 19 81 55 45 4.95 O O Increase adsorption time to 600 s from 15-Jun-2017 (53 C – bottom and 38 C - top) 19-6-17 45 55 24 76 58 42 4.15 20-6-17 45 55 21 79 56 44 4.49 Increase desorption time to 5600 s after 21/6/2017 (56 OC – bottom and 40 OC - top) 23-6-17 49 51 21 79 61 39 4.51 24-6-17 49 51 20 80 60 40 4.51 25-6-17 54 46 22 78 64 36 4.63

6

Total Gas Inlet

Desorption Pressure

Adsorption Time

Desorption Time

(mol/cycle)

(barg)

(sec)

(sec)

19.9 19.9 18.29 18.33

3.3-3.6 3.3-3.6 3.1-3.4 2.6-2.9

1500 1500 1500 1500

3000 3000 3000 3000

16.15 16

3.4-3.6 3.6-3.7

1000 1000

4500 4500

10.88 10.69 10.23 10.1

4-4.7 4.5-4.8 4.8-5 4.6-5

– 500 500 500

– 4000 4000 4000

7.25 7.7

6-6.8 6.5-7

500 500

4000 4000

8.11 8.14

6.6-7.7 6.7-8

600 600

4100 4100

8.43 8.53 8.57

5.5-6.5 5.5-6.5 5.7-6.7

600 600 600

5600 5600 5600

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Fig. 5. Separation performance of CO2 and CH4 from 5th May 2017 to 4th July 2017.

Fig. 8. Profile of temperatures in bed. Fig. 6. Profile for pressures (gauge) for the two adsorption beds; blue – bed 1 and red – bed 2.

conditions were assumed for simulation, while the experimental condition was actually changed with weather and non-uniform heating temperatures. CO2 concentrations of 64% in the blowdown stream and CH4 of 73% in the top stream was obtained in the simulation, which is slightly different from the real experimental data (CO2 product of 60% and CH4 of 80%). There was 10% C2+ hydrocarbons in the real experiment gas which we model as CH4. The adsorption capacity of C2+ hydrocarbon on Sorbeads WS is between CO2 and CH4 so that such components diluted both products in the process and could explain the discrepancy. 4. Discussion 4.1. Selection of sorbead as a bench mark adsorbent in this study Currently the most common adsorbents reported in the open literature for natural gas separation by PSA are zeolite 13X or kinetic carbon molecular sieves (CMS) (Santos et al., 2011; Grande et al., 2017; Cavenati et al., 2005; Jayaraman et al., 2002; Rocha et al., 2017; Ribeiro et al., 2010; Cavenati et al., 2004; Gholipour and Mofarahi, 2016; Cavenati et al., 2006). However, the working capacity and selectivity on zeolite 13X for CO2 removal in PSA operation pressure range is quite low so that vacuum desorption may be required to remove adsorbed CO2 from the adsorbent; kinetic carbon molecule sieve would lead to a large volume PSA rig, complex cycle design and poor separation efficiency. Inspired by the mesoporous silicate material, MCM-41, we found a high silicate content adsorbent, Sorbeads WS, has a large CO2 adsorption capacity and promising selectivity of CO2 over CH4 in the high pressure range. Thus, we chose Sorbeads as a bench mark adsorbent to deal with high pressure natural gas.

Fig. 7. Profiles of feed gas flowrate and exiting gas flowrate in the top stream.

3.4. Simulation verification Fig. 9 illustrates the comparison of the experimental and simulation results. As with the experiment on 24th June, the feed gas contains 49% CO2 balanced with CH4. The simulation pressure curve in Fig. 9(a) shows excellent agreement with the experimental data, whereas the flowrate in both Fig. 9(c) and (d) of either top stream or feed stream almost agreed with the simulation results. The simulation temperature curve in Fig. 9(b) had a large deviation from the actual curve, but this is reasonable since constant environment temperature and heating loss 7

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Fig. 9. Comparison of simulation results and experimental results for 1 cycle: (a) bed pressure, (b) temperature at top part of bed, (c) top stream flowrate and (d) feed stream flowrate.

4.2. Performance improved by increasing feed composition

As illustrated in the graph of adsorption isotherms (Fig. 4), nearly linear isotherms were obtained for both pure CO2 and CH4 on adsorbents at all 3 temperature points. The trend of CO2 isotherms were not like those on the other commonly used commercial adsorbents, such as zeolite 13X, which are quickly saturated at a very low pressure (< 0.5 bar) (Cavenati et al., 2004). The rapidly saturating isotherms of CO2 corresponds to strong interaction between the gas molecule and the adsorptive sites on the surface of the adsorbent due to the large quadrupole moment of CO2. In contrast, a linear adsorption isotherm generally indicates a weaker interaction, for instance the isotherms of CH4 are quite linear on most of the adsorbents, because CH4 molecule has no dipole and quadrupole moment to interact with polar site on the adsorbent. As to Sorbead WS, the high silica content (Si/Al ˜ 25) in its composition, therefore, corresponds to weaker interaction between CO2 and the adsorbent, which facilitates CO2 desorption from these adsorbents at atmospheric pressure level. It is also seen that CH4 adsorption capacity on such adsorbents is quite low over the entire pressures range, which will be beneficial for the adsorbent to be used in PSA processes to remove CO2 from a high pressure natural gas. Thus, for any high pressure PSA process, taking natural gas sweetening process as a base example, adsorbents with relative linear adsorptive isotherms should be preferred materials. Sorbead WS was initially used in the first campaign of the Otway capture project where the feed gas includes high content CO2 at high pressure. Future campaigns of our capture project will introduce other adsorbents, using Sorbead WS as a benchmark material, to continue investigating the effect of linear adsorption isotherms on the separation performance.

It is important to note that the feed composition will strongly influence the separation performance. As shown in Fig. 5, the concentration of CO2 in the bottom product stream increased as the feed concentration was adjusted from 30% CO2 to 50%, while the concentration of the top product stream remained at around 80% of CH4. It indicated the overall separation performance was improved by increasing the feed composition, which agreed with the selectivity data calculated in Table 5. This is a potential advantage when comparing the adsorption process with the traditional solvent based absorption process in natural gas treatment. When dealing with high CO2 content natural gas, solvent based absorption process would inevitably require more solvent to capture the CO2, and thus more energy for regeneration and a larger footprint. Adsorption processes are inherently more suitable for treating high CO2 content gas streams. In addition, as the selectivity increases with the feed composition, the adsorption plant will reduce in size as the CO2 feed level increases. 4.3. Impact of desorption pressure As described in the previous section, the separation performance with the demonstration rig was hindered by a high desorption pressure issue. To assess the impact of blowdown pressure on the separation performance, process simulations were conducted for the feed gas with CO2 concentration of 45% balanced with CH4 at flowrate of 4.5 s L/min, temperature of 40 OC, feed pressure of 30 bar. The simulation result of CO2 and CH4 with different desorption pressures are shown, respectively in Fig. 10. Both CO2 and CH4 concentration are positively 8

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Fig. 10. Impact of desorption pressures on separation performance (a) CH4 and (b) CO2.

affected by deepening the desorption pressure. If the desorption pressure decreased from 7 bar to 1 bar, the CO2 concentration in the bottom stream (CO2 rich product) would increase from 58 to 79% and in the top stream (CH4 rich product) decrease from 37 to 2%; CH4 in the top stream similarly changed from 63 to 98% and from 42% to 21% in the bottom stream. Hence, in this case, the specification of the methane product stream could be achieved via such a PSA process. It demonstrates that reducing desorption pressure is essential for achieving required separation performance.

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5. Conclusion The CO2CRC has designed and operated an adsorption rig in Otway Australia to capture CO2 from high CO2 content natural gas. Two months of experimental data (from May 2017 to June 2017) were collected showing that CO2 was successfully separated from the feed mixture gas using a commercial adsorbent. With a feed gas of 30% CO2/ 70% CH4, the CO2 concentration in the CO2 rich product stream reached 50%, and 12% of CO2 concentration in the CH4 rich product. The results of 60% CO2 and 80% CH4 products could also be observed from the experiment with a 50% CO2/50% CH4 feed gas. However, due to the limitation of design, ideal separation performance was not obtained on the rig due to the high desorption pressure. This problem is now being rectified. Simulation results with an in-house simulation tool MINSA were in good agreement with the experimental data. Meanwhile, simulation predictions revealed that if the desorption pressure could decrease to 2 bar instead of the 5 to 7 bar in the actual process, the CO2 capture performance could be significantly improved. Acknowledgement All funds were supported by CO2CRC Limited, the leading Australian CCS R&D organisation. The authors also acknowledge the Australian Government funding associated with CO2CRC. References Allzadch-Khlavi S, Sawada AJ, Gibbs CA, Alvaji J. Rapid cycle syngas pressure swing adsorption system, 2007. doi:https://doi.org/10.1016/j.(73). Belmabkhout, Y., Sayari, A., 2009. Adsorption of CO2 from dry gases on MCM-41 silica at ambient temperature and high pressure. 2 : adsorption of CO2/N2, CO2/CH4 and CO2/H2 binary mixtures. Chem. Eng. Sci. 64, 3729–3735. https://doi.org/10.1016/j. ces.2009.05.039. Belmabkhout, Y., Serna-Guerrero, R., Sayari, A., 2009. Adsorption of CO2from dry gases on MCM-41 silica at ambient temperature and high pressure. 1: pure CO2 adsorption. Chem. Eng. Sci. 64, 3721–3728. Burgers, W.F.J., Northrop, P.S., Kheshgi, H.S., Valencia, J.A., 2011. Worldwide development potential for sour gas. Energy Procedia 4, 2178–2184. https://doi.org/10. 1016/j.egypro.2011.02.104. Butwell FK, Dolan BW, Kuznickl MS. Selective removal of nitrogen from natural gas by pressure swing adsorption. US6197092, 2001. doi:https://doi.org/10.1145/634067.

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method for PSA/VSA cycle simulation - experimental validation. Ind. Eng. Chem. Res. 40, 3217–3224. https://doi.org/10.1021/ie0008070. Xiao, P., Zhang, J., Webley, P., Li, G., Singh, R., Todd, R., 2008. Capture of CO2 from flue gas streams with zeolite 13X by vacuum-pressure swing adsorption. Adsorption 14, 575–582. https://doi.org/10.1007/s10450-008-9128-7. Xiao, P., Wilson, S., Xiao, G., Singh, R., Webley, P., 2009. Novel adsorption processes for carbon dioxide capture within a IGCC process. Energy Procedia 1, 631–638. https:// doi.org/10.1016/j.egypro.2009.01.083. Xu, D., Xiao, P., Li, G., Zhang, J., Webley, P., Zhai, Y., 2012. CO2 capture by vacuum

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