SOUR GAS TREATMENT PLANT DESIGN CBE 160 PROJECT REPORT

Transcription

1 SOUR GAS TREATMENT PLANT DESIGN CBE 160 PROJECT REPORT Project Instructor: Dr. Mello Date: 07/16/2015 Team Number: 4 Team Members: Sheng Han Han Ee Ong William Agung Prabowo

2 Executive Summary In this report, a conventional design of sour gas treatment plant employing packed absorber and stripper columns is presented psig, 50 MMSCFD sour gas that consists of 10 mole percent CO2 is processed in the design to reduce the CO2 content down to 2 mole percent (pipeline specification). The design is simulated with Aspen HYSYS V8.6 acid gas package and is able to achieve the desired specification. Further, the absorber in the design is compared with the one in novel Rotating Packed Bed (RPB/Higee) design to assess the benefits of the RPB. We found that RPB is able to give a significant volume reduction factor at the expense of higher pressure drop compared to the conventional packed column, indicating RPB can be a viable option for future design. Introduction In natural gas treatment process, some of the most basic principles are the understanding of sour and sweet gas. Sour gas is defined as natural gas with over 2 mol.% of carbon dioxide (CO2) while sweet gas is defined as natural gas with less than 2 mol.% CO2 (pipeline quality). Sour gas can still be used as fuel but there are two main concerns associated with it. First, corrosion issue: As most natural gas has to be transported over long distances in pipes before it is consumed, having sour gas in the pipeline means having CO2, which as an acid gas can react with water, resulting in a carbonated water that is corrosive to pipes. This can eventually lead to pipe leaks and failure. Second, environmental concern: It has become an environmental responsibility to convert sour gas to sweet gas and properly dispose of the CO2 in the process. Second, environment concerns: With the rise of global warming threat, it has become Sour Gas Treatment Plant Design Page 1

3 unacceptable to employ sour gas as a fuel source. Therefore, the aims of this project are: (1) To design a conventional sour gas treatment plant that converts 1000 psig sour gas at a feed rate of 50 MMSCFD with 10 mol.% CO2 to sweet gas with only 2 mol.% CO2 and (2) to compare absorbers in the conventional plant design with the one in the Rotating Packed Bed (RPB/Higee) design. To remove CO2 from natural gas, absorption solvent is used in an absorptionstripping process. This paper focuses on using methyl-diethanolamine (MDEA) as the compound that undergoes chemisorption with CO2 in an acid-base reaction to form a salt compound. By contacting sour gas with MDEA solution in an absorption column, CO2 can be removed from the gas. The rich amine solution (high CO2 content) can then be regenerated into lean amine (low CO2 content) and recycled back for absorption in the stripping column. The entire process can be very efficient since MDEA is continuously recycled while CO2 is washed out of the natural gas stream. In addition, MDEA does not show significant decomposition under operating conditions 3. Alternatives and Options Considered Two methods of CO2 removal from natural gas will be discussed in this paper: Conventional design with packed column and novel design with RPB. In a conventional design, the absorption and stripping processes are carried out with packed columns that usually have a major vertical footprint in the plant. On the other hand, the novel RPB design promises significant packing volume reduction and increased mass transfer rate due to the high-gravity environment created within it. On the aspect of absorption solvent, there are alkanolamines other than MDEA such as methylethanolamine (MEA), diglycolamine (DGA), and diethanolamine (DEA) Sour Gas Treatment Plant Design Page 2

4 that also react selectively with CO2. The solvent selection is primarily based on the solvent CO2 loading, defined as the mole of CO2 that can be absorbed per mole of amine. Higher maximum loading is desired for absorption since less solvent can be used to purify the sour gas. Subsequently, lower minimum loading is desired for stripping since the lean solvent can have maximum capacity for absorption again. The loading of those alkanoamines are presented below in Table 1: Table 1: Properties of alkanolamines as absorption solvent. 1 Parameter MEA DGA DEA MDEA Amine wt.% in solution Rich amine acid gas loading (mole acid gas/mole amine) Lean amine acid gas loading (mole acid gas/mole amine) Acid gas pick-up (mole acid gas/mole amine) From the table, it is evident that MDEA and DEA have the highest acid gas pick-up values. However, MDEA is selected as our solvent of choice due to its tertiary amine nature that binds more weakly with CO2 compared to DEA, a secondary amine. MDEA can therefore be regenerated in the stripping column more readily. The lower kinetic rate observed in MDEA is then compensated by adding piperazine (PZ), a secondary amine, that acts as an activator for the MDEA. Overall rate constant of solution is ~5 s -1. Design All the major and minor units are simulated using Aspen HYSYS V8.6 with acid gas fluid package. Column performances are calculated from HYSYS through robust rate-based methodology (i.e. efficiency calculation type). Two major components of our design are the absorber and stripper columns. Due to significant difference between the absorber and stripper operating pressures, a flash drum is also incorporated to facilitate this pressure change so that any CO2 gas Sour Gas Treatment Plant Design Page 3

5 that evolves from the pressure reduction can be vented and immediately removed from rich solvent stream. The process flowsheet is displayed on the next page in Figure 1. Figure 1: Process flow diagram of natural gas purification process implemented in Aspen HYSYS V8.6. Sour Gas Treatment Plant Design Page 4

6 Absorber The crux of the CO2 removal from sour gas occurs here. An 8-stage packed bed absorber is used. Countercurrent flow is obtained by pumping in lean amine from the top of the column and flowing in sour gas from the bottom of the column. Pressure at the column is controlled at stream pressure of 1000 psig. Lean solvent at 26 C is fed from the top of the column while natural gas at 21 C is fed from the bottom of the column. Temperature in the column is allowed to vary since the chemisorption reaction is exothermic and therefore the streams will naturally heat up in the column. In an ideal situation, mass balance indicates that minimum amine flow rate needed for absorption is approximately 2300 kmol/h. However, due to non-ideality of column condition, (i.e. equilibrium not reached due to insufficient residence time) 2600 kmol/h of amine flow rate is needed to ensure that the sweet gas stream meets the desired specification. Flash The flash drum provides the pressure transition between the absorber and stripper columns. It operates at 5.6 psig, and a valve is installed before the flash column so that flow into flash drum can be controlled. The significant pressure reduction in the flash vaporizes some CO2 from the liquid amine, and the gas evolved is allowed to be vented out, effectively decreasing the rich amine loading and easing the duty of stripper in regenerating the lean amine. Stripper To reduce operating cost and waste, amine used in the absorption process is regenerated as lean amine in the stripper column. The stripper column is a 6-stage packed column with rich amine stream fed to the highest tray in the column so that the Sour Gas Treatment Plant Design Page 5

7 gas in the distillate will be richest in CO2 and when the liquid trickles down the column it shall be a lean solvent. Temperature of the stripper is higher than temperature at the absorber since higher temperature pushes the exothermic chemical reaction equilibrium to the left and encourages CO2 to leave liquid amine. Average temperature of the column is 108 C and detailed temperature profile is given in the appendix. Pressure of the stripper is low at 5 psig which again encourages CO2 desorption from amine. At that pressure, the boiling point of water in the solvent is 111 C and therefore the reboiler operates at 111 C to generate steam which acts as the stripper gas for the distillation process. Output stream of hot lean amine is cooled in a heat exchanger with rich amine stream from the flash column in a countercurrent heat exchanger. The rich amine is heated up to approximately stripper column temperature prior to entering the stripper thus reducing the reboiler heat duty. On the other hand, the lean amine is further cooled down using a cooler and pumped back into the absorption column. A surge tank is placed prior to the pump so that fluctuations in lean amine flow rate and composition will have minimal impact on the absorption column performance. Results and Discussion From HYSYS simulation, with sour gas flow rate of 50 MMSCFD (2490 kmol/h) and lean solvent flow rate of 2600 kmol/h, the desired specification of sweet gas is achieved in the absorption column. The total height of the column is 4.8 meters. The dimensions of the absorption tower are given below: Table 2: Absorption column dimensions. Column Diameter Stage Height Packing Type Packing Size 1.5 m 0.61 m Intalox saddle 2 inches The composition and flow rates of the streams entering and exiting the absorber is shown in Table 3 on the following page: Sour Gas Treatment Plant Design Page 6

8 Table 3: Data for streams entering and exiting absorption column. Parameter Unit Feed Gas Sweet Gas Rich Amine Lean Amine Temperature C Molar Flow kmol/h Mole fraction CO ppm Methane trace Ethane ppm trace Propane ppm trace MDEA ppm Piperazine ppb H2O With the absorption column, the sour gas at 10 mol% CO2 is purified to sweet gas at 2 mol% CO2, which meets our streams requirement. The lean amine has a CO2 loading of while the rich amine has a CO2 loading of 0.57, which is lower than the CO2 corrosion limit loading of The lower loading achieved by the rich amine is attributed to insufficient residence time and possible contact area for CO2 to be chemisorbed by amine. No energy input is required for the absorber since no heating nor cooling are required. To achieve the same degree of CO2 removal from sour gas, the RPB design, a more novel approach, can also be used. Due to high gravity environment in the RPB, greater packing can be used. This creates thin liquid film that promotes high mass transfer rate. Therefore, the RPB can be designed to be more compact than the conventional absorption column. For the same feed and product gas specifications as well as the same flow rates as conventional column, the RPB design specification is given in the Table 4 on the following page based on formulas derived in Agarwal et. al. 2 Sour Gas Treatment Plant Design Page 7

9 Table 4: RPB design calculations Specification Parameter Value Dimensions r i m r o m h m V RPB m 3 Pressure drop P C kpa P f 20.4 Pa P m Pa P RPB kpa Liquid distributor Surface area 1.96 m 2 Packing volume 3.39 m 3 p Pa p kpa Maldistribution 1.08% From Table 2 and 4, it is evident that RPB absorber is more compact compared to the conventional design. Diameter of RPB unit is only 1.2 m, whereas diameter of conventional column is 1.5 m. In addition, conventional column runs up to 4.8 m packing height, but RPB unit only requires 3.4 m packing height. However, the tradeoff of having smaller dimensions in RPB is larger pressure drop of 14.5 psig, which is much greater than 0.5 psig for a typical packed bed column. In the flash unit, 33 kmol/h of CO2 is expelled as gas which represents 16 mol.% of CO2 originally present in the rich amine stream. CO2 loading was therefore reduced to Mole fraction of MDEA and PZ combined in gas stream is below 7.6 ppm. Therefore, the flash unit achieved its purpose of removing gaseous CO2 from the rich stream while keeping MDEA and PZ circulating in the process. The 6-stage stripper column is an energy intensive unit due to the need for steam to be generated at the reboiler. Rich amine enters the stripper at a flow rate of 2761 kmol/h. The column is 3.7 m high. The column dimensions and specifications are given on the following page: Sour Gas Treatment Plant Design Page 8

10 Table 5: Dimensions and specifications of stripper column. Column Diameter Stage Height Packing Type Packing Size 1.5 m 0.61 m Intalox saddle 2 inches Streams flowrate and composition is given below in Table 6: Table 6: Data from streams entering and exiting stripper column. Parameter Unit Rich Amine Flue Gas Lean Amine Temperature C Molar Flow kmol/h Mole fraction CO ppm Methane 3.3 ppm 52 ppm trace Ethane 0.5 ppm 7 ppm trace Propane 0.5 ppm 7 ppm trace MDEA 0.11 trace 0.12 Piperazine 0.02 trace 0.02 H2O From Table 6, it is evident that the loading of CO2 decreased from 0.48 in the rich amine stream to in the lean amine stream. CO2 gas of 170 kmol/hr is expelled from the top of the column and the combined MDEA and PZ loss through this process in the distillate stream is less than 1 ppb. For practical purposes, there is zero loss in amine. Therefore, the process is efficient in achieving the goal of converting rich amine to lean amine through removing CO2 without losing any amine. A countercurrent heat exchanger is installed for exchange of heat between the cold rich amine stream entering the stripper and the hot lean amine stream exiting from the stripper. The heat exchanger brings the temperature of the rich stream from 65 C to 85 C and the temperature of the lean amine stream from 110 C to 64 C. The higher pressure rich amine stream flows in the tube while the lower pressure lean amine stream flows in the shell. To make up for the loss of water and trace amount of MDEA/PZ, kmol/h of water, 1.25 mol/h of MDEA, and mol/h of PZ is fed to the surge tank. MDEA and Sour Gas Treatment Plant Design Page 9

11 PZ are the more expensive solvents and thus operating cost is kept low through the low make up flow rates of these solvents. Conclusion and Recommendations Our conventional design employed three major units for the natural gas sweetening process: Absorber column, flash tank and stripper column. The design simulated in HYSYS achieved the desired sweet gas specifications while ensuring minimal loss of expensive the amines. The conventional absorption column can theoretically be replaced by a RPB unit that promises 2.5 times packing volume reduction as well as lower vertical footprint. However, the pressure drop observed in RPB is significantly higher than the conventional column (although it is only a 1% drop from the feed pressure). If spatial concern is overwhelming, such as building an absorption unit on an offshore oilrig, the RPB can be a viable option to substitute the space intensive packed column. However, rigorous analysis on the economic and safety issues along with numerous field implementations should still be done on both conventional and RPB design to ensure the most suitable design is selected for robustness and ease of operation in the industry. Sour Gas Treatment Plant Design Page 10

12 References 1. Engineering Data Book, Section 21: Hydrocarbon treating. Gas Processors Suppliers Association. Tulsa, OK Process Intensification in HiGee Absorption and Distillation: Design Procedure and Applications. Lava Agarwal, V. Pavani, D. P. Rao, and N. Kaistha. Industrial & Engineering Chemistry Research (20), DOI: /ie101195k 3. Ayyaz. M., Mohamed I., Abdul M., Thanabalan M., Amir S. Thermophysical Properties of Aqueous Piperazine and Aqueous (N-Methyldiethanolamine + Piperazine) Solutions at Temperatures ( to ) K. Journal of Chemical Engineering, (2009) 4. Hanna Kierzkowska-Pawlak., Marta S., Andrzej C. Reaction Kinetics of CO2 in Aqueous Methyldiethanolamine Solutions using the Stop-Flow Technique. Chemical and Process Engineering, 33 (1), 7-18 (2011) 5. T. E. Rufford, et. Al. The removal of CO2 and N2 from natural gas: A review of conventional and emerging process technologies. Journal of Petroleum Science and Engineering (2012) 6. Arunkumar S., Bandyopadhyay S. S. Absorption of Carbon Dioxide into Piperazine Activated Aqueous N-Methyldiethanolamine. Separation Science Laboratory Cryogenic Engineering Centre, IIT (2010) Sour Gas Treatment Plant Design Page 11

13 Appendices Appendix 1: HYSYS Stream Results Sour Gas Treatment Plant Design Page 12

14 stages stages Appendix 2: Absorber Profiles Composition profile in absorber Temperature profile in absorber Vapor Liquid Mole fraction Temperature degree C Figure 2.1 Composition of CO2 in mole fraction in vapor and liquid phase versus stages in Figure 2.2 Temperature profile versus stages in absorber. absorber. By running Aspen, we get the above Absorber profiles. For left graph, we have CO2 composition profile in both liquid and gas phase in absorber. Since the lean Amine go into column from first stage and NG from bottom, Amine absorbs CO2 from NG when it flow from top to bottom. As a result, the composition CO2 in Liquid increase from stage 1 to stage 8. And CO2 in Gas decrease from bottom to up. For right graph, since absorption is exothermal reaction so as the cool lean Amine going to column from top, temperature increase as heat accumulated. But there is a peak where at stage 6 and temperature goes down. It is because the cold NG enter from bottom to cool the system temperature. Sour Gas Treatment Plant Design Page 13

15 stages stages Appendix 3: Stripper Profiles Composition profile in stripper Temperature profile in stripper Vapor 4 5 Liquid Mole fraction Temperature degree C Figure 3.1 Composition of CO2 in mole fraction in vapor and liquid phase versus Figure 3.2 Temperature profile versus stages in stripper. stages in stripper. Similar to the absorber, we generate stripper profiles. However, stage 1 and stage 8 are condenser and reboiler respectively. The rich Amine liquid goes into stripper at stage 2 and the concentration of CO2 decreases as the steam generate by the reboiler strips off the CO2 from the liquid. The CO2 in gas phase increase from stage 8 up to 2 slightly. But the composition of CO2 in gas phase increases dramatically at condenser due to large temperature drop. Gas phase contains most of water and CO2, decreasing of temperature condenses most of water and 99.7 % CO2 is removed from rich Amine. Sour Gas Treatment Plant Design Page 1

16 Appendix 4: Amines Reaction Mechanisms CO 2 + R R R N + H 2 O R R R NH + + HCO 3 (1) CO 2 + PZ + H 2 O PZCOO + H 3 O + (2) CO 2 + R R R N + PZ PZCOO + R R R NH + (3) CO 2 + PZCOO + H 2 O PZ(COO ) 2 + H 3 O + (4) CO 2 + R R R N + PZCOO PZ(COO ) 2 + R R R NH + (5) Appendix 5: Caculation of HiGee CO 2 + OH HCO 3 (6) HCO 3 + H 2 O CO H 3 O + (7) PZ + H 3 O + PZH + + H 2 O (8) PZCOO + H 3 O + PZH + COO + H 2 O (9) R R R N + H 3 O + R R R NH + + H 2 O (10) 2H 2 O H 3 O + + OH (11) The design of the HiGee Absorber refers to the paper by Agarwal. The paper shows all steps to do calculation for the design. RPB Inner Radius RPB Width G r i = ( πv jet (1 f d ) ) 1 2 ρ G p ( ) ρ L C G λc L 0.5 = βn g a a P b μ c 1 4 βn a g a b P μ c (ρ L ρ G ) 0.25 U G = {ρ 0.5 [ G + λ ( L 0.5 αg ) ρ 0.5 L } ] 2 RPB Outer Radius N g = ω2 r i g h = G 2πr i U G Sour Gas Treatment Plant Design Page 1

17 Gdy = K OG a e (y y)2πrhdr r 2 o r 2 G i = K OG a e πh [ y o y i (y y ] ) LM (y y ) LM = (y o y o ) (y i y i ) ln [(y o y o )/(y i y i )] V RBP = πr o 2 h Liquid distributor Surface area S = 2πr i h Packing volume V = πh(r o 2 r i 2 ) Frictional pressure drop P f = 1 fρ 2d G ( G 2 h 2πhε ) ( 1 1 ) r i r o Momentum pressure drop P m = 1 2 ρ G ( G 2 2πhε ) ( 1 2 r 1 i r2 ) o Centrifugal pressure drop P C = 1 2 ρ GAω 2 (r o 2 r i 2 ) P RPB = P f + P m + P C Pressure recovery p = ( 4fh 2K) ρ 2 Lv i 3D pipe 2 Hole pressure drop p 0 = 1 C ρ L v jet 2 Percent Mal-distribution Sour Gas Treatment Plant Design Page 2

18 percent moldistribution = 100 (1 p 0 p p 0 ) Table 5.1: Dimensions and specifications of stripper column. Symbol Value Unit Description G m 3 /s volumetric gas flow rate L m 3 /s volumetric liquid flow rate v jet 4 m/s liquid distributor velocity f d 0.33 fraction of cross-sectional area of RPB ρ G kg/m 3 density of gas ρ L 1042 kg/m 3 density of liquid p 4 ratio of liquid jet to exit gas kinetic energy α 0.9 α is (between 0.7 and 0.9); β 130 PRB flooding correlation fitting parameters λ 1.51 a 0.43 PRB flooding correlation fitting parameters b c N g ratio of centrifugal to gravitational acceleration a p 2500 m 2 /m 3 specific surface area of packing μ 1.25E-05 kg/(m s) fluid viscosity (gas) K OG a e 0.1 s 1 Overall gas volumetric mass transfer coefficient y i 0.1 Component mole fraction in gas bulk phase y o 0.02 at inner radius and outer radius y i Component gas-phase mole fraction in y o 1.43E-05 equilibrium with bulk liquid phase f 1 Fraction factor ε 0.9 Porosity of packing A Centrifugal pressure drop proportionality constant Re Reynolds Number d p m Effective diameter of packing, 6(1 ε)/ a p d hole m C o 0.2 Discharge coefficient K 8.5 Velocity head loss constant Sour Gas Treatment Plant Design Page 3