Sulfinol D Evaluation.

ECCN EAR 99

PDVSA Cardon Refinery Sulfinol Evaluation Confidential Technical Note

PDVSA Cardon Refinery Sulfinol Evaluation Confidential Technical Note

by C.J. Taylor

ECCN EAR 99 This document is made available subject to the condition that the recipient will neither use nor disclose the contents except as agreed in writing with the copyright owner. Copyright is vested in Shell Global Solutions (US) Inc. © Shell Global Solutions (US) Inc., 20082009. All rights reserved. Neither the whole nor any part of this document may be reproduced or distributed in any form or by any means (including but not limited to electronic, mechanical, reprographic or recording) without the prior written consent of the copyright owner. Shell Global Solutions is a trading style used by a network of technology companies of the Shell Group.

Shell Global Solutions

3

CONFIDENTIAL - ECCN EAR 99

Table of Contents Summary 1. Introduction 2. Design Basis

4 5 6

2.1 2.2 2.3 2.4 2.5

Sour Gas Lean Solvent Composition Treated Gas Specifications Other Design Criteria Future Case Conditions

6 6 7 7 8

3. 3.1 3.2

Process Description

9

The Sulfinol Process General Process Description

9 9

4.

Evaluation

10

4.1 4.2 4.2.1 4.2.2 4.2.3 4.2.4

Design Case Conditions Test Run Conditions Feed Gas CO2 Composition Feed Gas Temperature Lean Solvent Temperature Lean Solvent Composition

4.2.4.1

DIPA-oxazolidone Formation

4.2.5 4.2.6 4.3 4.3.1 4.3.2 4.3.3 4.3.4 4.3.5

CO2 Lean Solvent Loading Test Run Case Summary Future Case Conditions CO2 Lean Loading Circulation Rate Reboiler Duty Solutions for Improving Regeneration of Solvent Absorber Column Tray by Tray Data

10 10 11 11 11 12 13 13 14 15 15 15 15 16 16

5. 6.

Process Conditions and Heat Exchanger Information Sensitivity Analysis

18 19

6.1 6.2

Gas Inlet Temperature Lean Solvent Inlet Temperature

19 20

7. Conclusion 8. Appendix A – Process Flow Diagram (PFD) Bibliographic Information

21 22 24


4


Summary Shell Global Solutions (US) Inc. is pleased to provide the technical information on the Sulfinol process. Information including a key process information, heat exchanger duty estimates, tray by tray data, and two sensitivity analysis is provided for PDVSA’s Cardon Refinery Study. The CO2 removal section of HMU at the PDVSA Cardon Refinery was identified as a bottleneck on PDVSA’s last maximum capacity test run. Operationally, the Sulfinol unit was not able to maintain the treated gas in specification of 0.05 mol % CO2. The lean Sulfinol flowrate was increased from 7,400 ton/day to 9,600 ton/day by putting the spare circulation pump (PT-2202) in service. However, the treated gas measured concentration of CO2 was 0.432 mol %. The following three cases were evaluated for this study:

1. Design Case 2. Test Run Case 3. Future Case The purpose of this study is to identify reasons as to why the Sulfinol unit during the test run wasn’t meeting the treated gas specification and to determine the required circulation rate to achieve the treated gas specification when the Sulfinol unit is operated at the original design conditions with new feed gas conditions. The evaluation of the design case validated the model’s accuracy to match the actual operating data for treated gas CO2 concentration. The evaluation of the test run case determined that the additional CO2 concentration in the feed gas was the major contributor to the increased CO2 concentration in the treated gas. The increased solvent circulation rate of 9,600 ton/day should have been adequate to remove the additional CO2 from the sour gas. However, it was determined that the low water content in the lean solvent and the insufficient reboiler duty were the main causes as to why 9,600 ton/day of solvent was not able to treated the sour gas to the desired treated gas requirement of 0.05 mol % CO2. The reboiler duty was inadequate to regenerate the solvent to the required CO2 lean loading to achieve the desired CO2 specification in the treated gas. The lean loading for the test run was estimated to be 3,600 ppmw based on the reboiler duty (steam rate) to regenerate the solvent. Shell’s recommended maximum CO2 lean loading is 2000 ppmw to avoid corrosion in the reboiler and lean solvent piping. The evaluation of the future case demonstrated that the required lean solvent circulation is 9,000 ton/day. This higher circulation resulted in a higher reboiler duty (14.2 E6 kcal/hr) than the existing reboiler design duty (11.7 E6 kcal/hr), and was therefore deemed inadequate. The sensitivity analysis for the feed gas temperature showed no sensitivity on the required circulation rate. The sensitivity analysis for the lean solvent temperature demonstrated 50 °C is the most optimum lean solvent temperature, which meets the CO2 specification in the treated gas without the column temperature exceeding Shell’s maximum temperature constraint in the absorber. When the lean solvent temperature is increased above 50 °C, the CO2 specification can be met with lower circulation rate, however the temperatures inside the column exceed the maximum column temperature of 80 °C which can result in corrosion of carbon steel material.


1.

5


Introduction

The CO2 removal section of HMU at the PDVSA Cardon Refinery was identified as a bottleneck on PDVSA’s last maximum capacity test run. The conditions of the feed to the absorber C-2202 during this test are shown on Table 2-1 and Table 2-2. Operationally, the absorber was not able to maintain the treated gas in specification of 0.05 mol % CO2. The lean Sulfinol flowrate was increased from 7,400 ton/day to 9,600 ton/day by putting a spare circulation pump (PT-2202) in service. However, the treated gas measured concentration of CO2 was 0.432 mol %. The following three cases were evaluated for this study:

1. Design Case 2. Test Run Case 3. Future Case The purpose of this study is to identify reasons as to why the Sulfinol unit during the test run wasn’t meeting the treated gas specification and to determine the required circulation rate to achieve the treated gas specification when the Sulfinol unit is operated at the original design conditions with new feed gas conditions (Future Case). The future case with new feed gas conditions are shown in Table 2-5. Tray by tray data was tabulated for the new feed gas conditions case to enable PDVSA to rate the existing column to determine the feasibility of the existing amine contactor for the new design conditions. Process conditions and heat exchanger information was provided for the 2 cases evaluated for this study. A sensitivity study of the effect of gas inlet temperature and lean solvent inlet temperature were evaluated in order to meet the CO2 design specifications.

6


2.


Design Basis

The sour gas properties, treated gas specifications, and lean solvent data were received on Monday, September 27th from José Ramírez of PDVSA.

2.1

Sour Gas

The process data of the sour gas to the absorber C-2202 for the test run and design conditions are provided in Table 2-1. The lean solvent flowrate and inlet solvent temperature for the test run and design conditions are also provided in Table 2-1. Table 2-1: Sour Gas Feed Properties Test run Conditions Absorber C-2202 Gas inlet Dry Gas Flowrate (t/d) 460 H2O steam (t/d) 12.4 Pressure (kgf/cm2 gauge) 15.3 Temperature (°C) 67.5 Composition (mol %, dry basis) CO2 22.66 H2 75.15 N2 0.158 C1 1.987 CO 0.04 Sulfinol section Lean sulfinol flowrate (t/d) 9600 Inlet temp. of sulfinol (°C) 52

2.2

Design Contions Absorber C-2202 Gas inlet Flowrate (t/d) 460 H2O steam (t/d) 4.2 Pressure (kgf/cm2) 16.6 Temperature (°C) 45 Composition (mol %, dry basis) CO2 19.81 H2 76.41 N2 0.18 C1 2.4 CO 1.2 Sulfinol Section Lean sulfinol flowrate (t/d) 7400 Inlet temp. of sulfinol (°C) 45

Lean Solvent Composition

The lean solvent composition for the test run and design conditions are provided in Table 2-2. Table 2-2: Lean Solvent Composition

Water (wt %) Dipa (wt %) Sulfolane (wt %) Oxaxolidone (wt %) BL (wt %) BT (wt %)

Test run 11 43.07 41.29 10.43 37.9 37.9

Design 15 45 40 40-45 43-48

Note 1: The test run solvent composition was reported to be 105.79 %wt. Email correspondence with José Ramírez of PDVSA confirmed his confidence in the DIPA, Sulfolane and Oxazolidone values. The resulting water content on a 100 % basis would result in a water concentration of 5.21 % wt. This low of water concentration is far below the recommended minimum water concentration of 15 wt %.

7


2.3


Treated Gas Specifications

The following treating gas requirements for the C-2202 column are reported in Table 2-3. Table 2-3: Treated Gas Specifications Parameter CO2

2.4

All Cases 0.05

Units mol%

Other Design Criteria

The following is a list of additional design data used for developing this report.

Table 2-4: Additional Design Parameters

Parameter Utilities Design air temperature Reboiler heat duty (Note 1) Lean solvent Lean Solvent Loading (Note 2) Lean Solvent Loading (Note 2,3) Absorber Column Maximum temperature of solvent (Note 4)

Test Run Conditions

Design Conditions

Units

30 10.4 E+6

30 11.2 E+6

°C kcal/hr

0.025

0.003

mol/mol

3600

450

ppmw

80

80

°C

Notes:

1. The design reboiler duty as specified on the datasheet was 11.7 E+6 kcal/hr. 2. The lean loading is not measured at the Cardon Refinery, therefore, for this study the lean loadings were estimated based on the reboiler duties for the test run and design conditions. 3. Shell’s recommended maximum CO2 lean loading is 2000 ppmw to avoid corrosion in the reboiler and lean solvent piping. 4. Sulfinol Solvent temperatures inside the column greater than 80 °C can result in corrosion of carbon steel material.

8


2.5


Future Case Conditions

Table 2-5 provides the flow rate, temperature, pressure, and composition of the sour feed gas and the lean Sulfinol temperature for the future case. The solvent composition for the future Sour Gas case will be the design conditions specified in Table 2-2. Table 2-5: Future Case: Sour Gas Feed Properties and Lean Solvent Conditions Study Conditions Absorber C-2202 Gas inlet Dry Gas Flowrate (t/d) 460 H2O steam (t/d) 5.4 Pressure (kgf/cm2 gauge) 15.3 Temperature (°C) 45 Composition (mol %, dry basis) CO2 22.66 H2 75.15 N2 0.158 C1 1.987 CO 0.04 Sulfinol section Lean sulfinol flowrate (t/d) Resulting Inlet temp. of sulfinol (°C) 45


3.

Process Description

3.1

The Sulfinol Process

9


The Shell Sulfinol process is a regenerative amine based process for the removal of hydrogen sulphide, carbon dioxide, carbonyl sulphide, mercaptans and organic sulphides/disulphides from gas streams. The process was specifically developed for the treatment of gas streams at elevated pressures. Sulfinol solvent is a mixture of water, amine (DIPA or MDEA) and Sulfolane. A formulation with DIPA had been selected for this application. The addition of Sulfolane increases the physical solubility of the acid gas contaminants (H2S and CO2) in the solvent and improves the efficiency of the absorption process. The physical solubility of the mercaptans and the organic sulphides/disulphide is also increased to a level whereby these contaminants can be removed to low levels.

3.2

General Process Description

The process flow diagram defining the operation of the Sulfinol unit is shown in Appendix A. Feed to the main absorber should pass through a feed gas conditioning system. This system should exclude pipe scale, liquid hydrocarbons, corrosion inhibitors, and catalyst fines as these will accumulate in the closed loop system and can lead to operating problems, like foaming. Care should also be taken to exclude oxygen, such as from vapour recovery units, as it leads to enhanced degradation. The removal of the acidic components (CO2, H2S, COS, and mercaptans) from the gas phase takes place in an absorber column, filled with trays or packing, where the gas stream is contacted with the Sulfinol solvent counter-currently. The lean solvent is supplied to the absorber under flow and temperature control. The temperature of the lean solvent is kept sufficiently high to avoid condensation of hydrocarbons in the column. If hydrocarbons are allowed to condense in the absorber, severe foaming of the solvent can occur. Rich solvent from the absorber flows to a Lean-Rich heat exchanger where it is heated by hot lean solvent coming from the regenerator bottom. The heated rich solvent is introduced to the top of the stripping section of a regenerator, filled with trays or packing, where the acid gases are stripped from the solvent by contacting the solvent counter currently with stripping steam. The stripping steam is generated at the bottom of the regenerator in the reboiler. Acid gas leaving the stripping section of the regenerator is washed in the water wash section of the regenerator and is then routed to the regenerator overhead condenser. The cooled acid gas along with condensed water flows to the reflux accumulator, where the acid gas and water are separated. The condensed water is mixed with the make-up water and returned under flow control to the regenerator as reflux via the reflux pump. The acid gas product from the reflux vessel is routed to a downstream processing unit (e.g., acid gas injection). Lean Sulfinol solvent from the bottom of the regenerator is pumped back to the absorber via lean-rich exchanger, solvent cooler. A slipstream of the lean Sulfinol solvent after lean-rich exchanger is routed to the series of filters (mechanical filter, activated carbon filter followed by after carbon filter). Suspended solids are considered to be a major cause of foaming in absorbers and regenerators. This mechanical filtration can be supplemented by filtration through an active carbon bed to remove surface-active contaminants.

10


4.

Evaluation

4.1

Design Case Conditions


The design case was modeled to confirm the plant would meet the treated gas specification of 0.05 mol % CO2 under the design conditions. Without knowing the exact CO2 lean loading of the plant, the treated gas CO2 concentration was determined for various CO2 lean loadings to show the sensitivity on the lean loading of the CO2 removal. Figure 4-1 shows the lean loading required to meet the treated gas specification is ~ 750 ppmw for the design circulation of 7,600 ton/day. CO2 in Treated Gas vs Estimated CO2 Lean Loading 0.35 Design

CO2 in treated Gas (mol %)

0.30

Measured

0.25 0.20 0.15 0.10 0.05 0.00 ‐

1,000

2,000

3,000

4,000

5,000

Estimated CO2 Lean Loading (ppmw)

Figure 4-1: Effect of Lean Loading The reboiler duty for the design case was measured to be 11.2 E 6 kcal/hr (Table 2-4). The estimated lean loading for this reboiler duty at the design conditions is 450 ppmw. The estimated lean loading is less than the required lean loading (750 ppmw) which explains why the CO2 in the treated gas was below the 0.05 mol % CO2. Our model predicted a 0.047 mol % CO2 concentration in the treated gas with the loan loading of 450 ppmw, which validates that the model accurately predicts the CO2 concentration in the treated gas for the design conditions.

4.2

Test Run Conditions

The CO2 removal section of HMU at the PDVSA Cardon Refinery was identified as a bottleneck on PDVSA’s last maximum capacity test run. Operationally, the absorber was not able to maintain the treated gas specification of 0.05 mol % CO2. The lean Sulfinol flowrate was increased from 7,400 ton/day to 9,600 ton/day by putting the spare circulation pump (PT-2202) in service in attempt to lower the treated gas CO2 concentration. However, the treated gas CO2 concentration was measured to be 0.432 mol %.

11



The major differences between the test run conditions and the design conditions were the feed gas CO2 composition, feed gas temperature, lean solvent flow, lean solvent temperature, lean solvent composition, and the CO2 lean solvent loadings. These changes were investigated to determine the major causes of the increased CO2 concentration.

4.2.1

Feed Gas CO2 Composition

The feed gas CO2 composition increased from 19.81 mol % to 22.66 mol % between the design case and the test case. The test case CO2 concentration increased by ~ 15 %, which results in approximately 15 % additional moles of CO2 which needed to be absorbed by the solvent. The 30 % increased in lean Sulfinol circulation using the spare circulation pump should have been enough solvent to handle the additional CO2 load on the solvent. It was determined that the additional CO2 concentration was a major contributor to the increased CO2 concentration in the treated gas, but the solvent circulation rate of 9,600 ton/day should have been adequate. Therefore, the reason as to why the solvent circulation rate of 9,600 ton/day yielded the higher CO2 concentration in the treated gas was investigated.

4.2.2

Feed Gas Temperature

The feed gas temperature was increased from 45 °C to 67.5 °C between the design case and the test case. While, the feed gas temperature was increased by 22.5 °C, the impact to the treated gas CO2 concentration is negligible. This is a result of the treated gas temperature entering the column very quickly coming to thermal equilibrium with the rich solvent temperature leaving the column. The temperature profile of the bottom ten trays of the column for the test run conditions was predicted by our model and reported in Table 4-1. As shown in Table 4-1, the rich solvent temperature leaving the column is ~ 80 °C and in the first two trays the temperature of the gas increases to ~ 80 °C. Above tray two, the gas temperature closely matches the solvent temperature throughout the column. Therefore, the increased feed gas temperature of the test case was determined not to be a major reason why the solvent circulation rate of 9,600 ton/day yielded the higher CO2 concentration in the treated gas. Table 4-1: Temperature Profile in Column (Bottom 10 Trays) Trays 1 2 3 4 5

Solvent Temperature Gas Temperature Deg C Deg C 78.5 67.5 79.5 79.5 76.8 76.8 73.3 73.3 69.7 69.7

6 7 8 9 10

4.2.3

66.3 63.2 60.5 58.3 56.5

66.3 63.2 60.5 58.3 56.5

Lean Solvent Temperature

The lean solvent temperature increased from 45 °C to 52 °C between the design case and the test case. While the lean solvent temperature was increased by 7 °C, the impact on treated gas CO2 concentration is minimal. The optimum lean solvent temperature for CO2 removal is

12



between 45 °C and 50 °C. However, due to the exothermic reactions associated CO2 absorption, it is important to keep the temperature of the solvent in the absorber below 80 °C to avoid corrosion associated with high temperature in absorber columns made of carbon steel material. The higher lean solvent temperature results in higher solvent temperatures throughout the column, which could result in increased corrosion rates. The lean solvent temperature sensitivity reported in Section 6.2 demonstrates the circulation rate to meet the treated gas specification is optimal at 50 °C. Therefore, it was determined that the test run conditions lean solvent temperature of 52 °C was not a major reason why the solvent circulation rate of 9,600 ton/day yielded the higher CO2 concentration in the treated gas.

4.2.4

Lean Solvent Composition

The lean solvent composition changed severely from the design conditions during the test run. While, the DIPA and Sulfolane concentration remained fairly constant, the water concentration was significantly decreased and there was a substantial formation of DIPA-oxazolidone. The water concentration in Sulfinol solvent is critical for CO2 removal. Figure 4-2 shows the CO2 concentration in the treated gas increases substantially as the water concentration is decreased below 10 wt %. Therefore, the lower water content of the solvent during the test run can explain the high CO2 concentration (0.432 mol %) measured during the test run. The decreased water concentration in the test case was determined to be a major reason why the solvent circulation rate of 9,600 ton/day yielded the higher CO2 concentration in the treated gas. The recommended minimum for water concentration is 15 wt %, as the absorption of CO2 becomes significantly worse below 15 %. It should be noted that the water concentration below 15 %wt is outside the scope of the operating data which our Sulfinol model is based upon; therefore the results are less conclusive than the data inside the operating data window.

CO2 in Treated Gas vs Water Concentration 0.70 3600 ppmw CO2 9,600 T/D Circulation Measured


0.60 0.50 0.40 0.30 0.20 0.10 0.00 5

7

9

11

13

Water Concentration (wt %)

Figure 4-2: Effect of Water Concentration

15

17


4.2.4.1

13


DIPA-oxazolidone Formation

DIPA-oxazolidone is the principle degradation products in systems with CO2 and DIPA it is formed from a reaction with carbamate and CO2, carbamate is the primary product formed in the reaction between DIPA and CO2: CO2 + 2R2NH = R2NCOO- + R2NH2+ = DIPA-oxazolidone + R2NH + H2O Where R2NH is DIPA, R2NCOO- is carbamate DIPA-oxazolidone can be tolerated up to around 10% wt of the total solvent inventory. Concentrations greater than 10% wt are not recommended due to the following reasons:

• •

DIPA‐oxazolidone is effectively a waste product that decreases the concentration of DIPA available for acid component removal DIPA‐oxazolidone increases the viscosity of the solvent thereby decreasing heat transfer and pumping efficiency

The rate of DIPA-oxazolidone formation is enhanced by high CO2 partial pressures above the solvent, high temperatures and large residence times. The DIPA-oxazolidone essentially ties up the good amine (DIPA) and doesn’t allow for CO2 removal. The DIPA-oxazolidone does have some physical solvent nature and acts similar to sulfolane. For modeling purposes, the DIPA-oxazolidone is considered to be sulfolane. Reclamation of the Sulfinol should be utilized when the concentration of DIPA-oxazolidone exceeds 10 wt %. For DIPA-oxazolidone concentration less than 10 %, the water and DIPA concentration shall be maintained, while allowing the Sulfolane concentration to deviate.

4.2.5

CO2 Lean Solvent Loading

The lean loading is not measured at the Cardon Refinery; therefore the CO2 lean loadings were estimated based on the reboiler duties for the test run conditions. Figure 4-3 shows the effect of lean loading on the estimated CO2 concentration in the treated gas for the test-run conditions. This figure clearly shows that as the CO2 lean loading increases, the CO2 in the treated gas increases considerably. Therefore, it was concluded that lean loading is a major reason for the increased CO2 concentration in the treated gas. The reboiler duty for the plant during the test run conditions was measured to be 10.4 E6 kcal/hr (Table 2-4). The lean loading for the test run was estimated to be 3,600 ppmw based on the reboiler duty (steam rate) to regenerate the solvent. It should be noted that Shell’s recommended maximum CO2 lean loading is 2000 ppmw to avoid corrosion in the reboiler and lean solvent piping. The reboiler duty (steam rate) for the test run case was significantly lower than Shell’s recommended reboiler duty for this higher circulation rate. A general rule of thumb for Sulfinol-D solvent is to use between 70 – 80 kg steam/ ton of solvent. Therefore, the desired reboiler duty for 9,600 ton/day of solvent would be 14 – 16 E+6 kcal/hr.

14



CO2 in Treated Gas vs Estimated CO2 Lean Loading 0.200 0.180

9,600 T/D Circulation Rate


0.160 0.140 0.120 0.100 0.080 0.060 0.040 0.020 0.000 ‐

2,000

4,000

6,000

8,000

10,000

12,000

Estimated CO2 Lean Loading (ppmw)

Figure 4-3: Effect of Lean Loading

Using the estimated lean loading of 3,600 ppmw, the CO2 in the treated gas was estimated to be 0.06 mol % (Figure 4-3). It should be noted that Figure 4-3, assumed a water concentration in the solvent of 11 wt % as per the test-run conditions design basis as originally reported. However, if the concentration of water in the solvent was lower than reported (See Note 1 of Table 2-2), the curve in Figure 4-3 would be shifted upwards, as a result of the effect of water concentration as shown in Figure 4-2.

4.2.6

Test Run Case Summary

It was determined that the additional CO2 concentration in the feed gas was the major contributor to the increased CO2 concentration in the treated gas. The increased solvent circulation rate of 9,600 ton/day should have been adequate to remove the additional CO2 from the sour gas. However, it was determined that the low water content in the lean solvent and the insufficient reboiler duty were the main reasons as to why 9,600 ton/day of solvent was not able to treated the sour gas to the desired treated gas requirement of 0.05 mol % CO2. The low water content of the solvent was not suitable for the solvent to absorb the CO2 from the sour gas. The reboiler duty was inadequate to regenerate the solvent to the required CO2 lean loading to achieve the desired CO2 specification in the treated gas. If the reboiler duty was increased to 14 - 16 E6 kcal/hr and the solvent composition was maintained at the design conditions, the treated gas concentration should be below the 0.05 mol % CO2 specification.


4.3

15


Future Case Conditions

The future case was modeled to determine the circulation required to meet the treated gas composition of CO2 to be less than 0.05 mol %.

4.3.1

CO2 Lean Loading

In order to predict the circulation required to meet the treated gas specification, an assumption of the CO2 lean loading has to be made. Shell’s assumption of the CO2 lean loading for the future case is 450 ppmw. This assumption was established based on the lean solvent loading estimated by our model for the design case conditions and reboiler estimate. This assumption could be validated by PDVSA if a lean loading measurement was taken.

4.3.2

Circulation Rate

Using a CO2 lean loading of 450 ppmw, the required lean solvent circulation rate was estimated to 9,000 T/D to meet the treated gas CO2 specification. If the CO2 lean loading is determined to be higher than the assumed lean loading of 450 ppmw, Table 4-2 provides the solvent circulation rate required to achieve the 0.05 mol % CO2 concentration in the treated gas.

4.3.3

Reboiler Duty

Using a circulation rate of 9,000 ton/day, the required reboiler duty to achieve the assumed CO2 lean loading of 450 ppmw is 14.2 E+6 kcal/hr. The maximum duty available was established by the design reboiler duty as specified on the datasheet of 11.7 E+6 kcal/hr. As this required reboiler duty is more than the maximum duty of the reboiler, the reboiler was assumed to be inadequate. If the CO2 lean loading is determined to be higher than the assumed lean loading of 450 ppmw, Table 4-2 provides the required reboiler duty to achieve the respective lean loadings for the given circulation rates in order to meet the 0.05 mol % CO2 concentration in the treated gas.

Table 4-2: Circulation Rate Required and Reboiler Duties for Various CO2 Lean Loadings Lean Solvent Loading ppmw CO2 450 1000 1500 2000

Solvent Circulation Rate Ton/Day 9,000 9,200 9,600 10,000

Reboiler Duty E+6 kcal/hr 14.2 14.5 15.1 15.7

16


4.3.4


Solutions for Improving Regeneration of Solvent

There are a few suggestions for improving the regeneration of the solvent.

1. Investigate options to increase reboiler duty 2. Inject LP steam into the bottom of the column to improve regeneration of the solvent and decrease the CO2 lean loading. These suggestions can be evaluated by Shell Global Solutions (US) in the future if desired. If you have any questions regarding any of these solutions, we would be glad to discuss further. 4.3.5

Absorber Column Tray by Tray Data

Tray by tray data was tabulated for the new feed gas conditions case to enable PDVSA to rate the existing column to determine the feasibility of the existing amine contactor for the future design conditions. Table 4-3: Tray by Tray Data for Sulfinol Absorber TRAY Bottom 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 Top

TL C 73.6 72.0 68.5 64.8 61.3 58.1 55.3 53.0 51.3 50.0 49.1 48.4 48.0 47.8 47.6 47.5 47.4 47.3 47.3 47.3 47.3 47.3 47.3 47.3 47.3 47.3 47.3 47.3 47.3 47.3 47.3 47.3 47.3 47.3 47.3 47.3 45.0

TG C 45 72.4 72.0 68.6 65.0 61.5 58.3 55.5 53.2 51.4 50.1 49.1 48.5 48.1 47.8 47.6 47.5 47.4 47.3 47.3 47.3 47.3 47.3 47.3 47.3 47.3 47.3 47.3 47.3 47.3 47.3 47.3 47.3 47.3 47.3 47.3 47.3

PRESS. BARA

SOLVENT KG/H

GAS KG/H

15.98 15.96 15.94 15.92 15.90 15.87 15.85 15.83 15.81 15.79 15.77 15.75 15.72 15.70 15.68 15.66 15.64 15.62 15.60 15.57 15.55 15.53 15.51 15.49 15.47 15.45 15.42 15.40 15.38 15.36 15.34 15.32 15.30 15.27 15.25 15.23

391200 389400 387300 385300 383300 381500 380000 378600 377600 376800 376300 375900 375600 375400 375300 375200 375200 375100 375100 375100 375100 375100 375100 375100 375100 375100 375100 375100 375100 375100 375100 375100 375100 375100 375100 375100

17450 15390 13350 11390 9594 8014 6697 5657 4875 4311 3919 3652 3473 3355 3278 3228 3195 3174 3160 3151 3146 3142 3139 3138 3137 3136 3136 3135 3135 3134 3133 3132 3131 3130 3128 3125

GAS VISC CP 0.0162

TRAY

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 0.0067

GAS DENSITY KG/M3 7.191 6.108 5.55 5.007 4.449 3.892 3.365 2.896 2.505 2.197 1.968 1.804 1.69 1.613 1.561 1.526 1.502 1.486 1.475 1.467 1.461 1.457 1.453 1.45 1.448 1.445 1.443 1.441 1.439 1.436 1.434 1.432 1.43 1.427 1.425 1.423 1.42

LIQUID DENSITY KG/M3

LIQUID VISC CP

LIQUID COND. W/M/K

LIQUID SURFT mN/M

LIQUID HEAT CAP. KJ/KG/K

1105.7 1103.1 1102.1 1101.1 1099.9 1098.7 1097.5 1096.4 1095.4 1094.6 1093.9 1093.5 1093.2 1093.0 1092.8 1092.7 1092.7 1092.6 1092.6 1092.6 1092.6 1092.5 1092.5 1092.5 1092.5 1092.5 1092.5 1092.5 1092.5 1092.5 1092.5 1092.5 1092.5 1092.5 1092.5 1092.5 1094.4

6.38 6.30 6.65 7.13 7.66 8.23 8.79 9.30 9.74 10.09 10.33 10.51 10.64 10.71 10.77 10.80 10.82 10.83 10.84 10.85 10.85 10.85 10.85 10.85 10.85 10.85 10.85 10.85 10.85 10.85 10.85 10.85 10.85 10.85 10.85 10.85 12.07

0.207 0.207 0.207 0.207 0.206 0.206 0.206 0.206 0.206 0.206 0.206 0.205 0.205 0.205 0.205 0.205 0.205 0.205 0.205 0.205 0.205 0.205 0.205 0.205 0.205 0.205 0.205 0.205 0.205 0.205 0.205 0.205 0.205 0.205 0.205 0.205 0.205

37.95 38.10 38.41 38.72 39.03 39.31 39.55 39.74 39.90 40.01 40.09 40.14 40.18 40.20 40.22 40.23 40.24 40.24 40.24 40.24 40.25 40.25 40.25 40.25 40.25 40.25 40.25 40.25 40.25 40.25 40.25 40.25 40.25 40.25 40.25 40.25 40.44

2.72 2.70 2.68 2.67 2.66 2.65 2.65 2.65 2.65 2.64 2.64 2.64 2.64 2.64 2.64 2.64 2.64 2.64 2.64 2.64 2.64 2.64 2.64 2.64 2.64 2.64 2.64 2.64 2.64 2.64 2.64 2.64 2.64 2.64 2.64 2.64 2.63

17



Table 4-4: Tray by Tray Data for Sulfinol Regenerator TRAY

TL C

Bottom 1 2 3 4 5 6 7 8 9 10 11 12 Top

TG C

125 124.6 124.3 123.9 123.3 122.3 120.8 118.5 115.0 110.4 98.2 45.4 45.0

PRESSURE BARA 135.4 125.2 124.6 124.3 123.9 123.3 122.4 120.9 118.5 115.0 110.4 111.3 98.2

FAT SOLVENT KG/HR

GAS TOTAL KG/HR

GAS VISC CP 0.010

1.75 1.73 1.72 1.70 1.68 1.67 1.65 1.64 1.62 1.61 1.61 1.60

400100 400100 400000 399800 399600 399200 398800 398000 396800 395100 8697 7962

25310 25160 24990 24750 24410 23920 23180 21980 20310 18880 25068 24333

GAS LIQUID LIQUID DENSITY DENSITY VISC KG/M3 KG/M3 CP 0.94 0.96 0.95 0.95 0.94 0.95 0.96 1.00 1.06 1.18 1.35 1.47 1.57

1017.6 1018.1 1018.6 1019.2 1020.3 1022.3 1025.8 1031.7 1040.4 1051.7 961.1 990.0

LIQUID COND. W/M/K

LIQUID SURFT mN/M

0.23 0.23 0.23 0.23 0.23 0.23 0.23 0.22 0.22 0.22 0.68 0.64

34.70 34.74 34.76 34.79 34.82 34.86 34.92 35.02 35.16 35.36 60.00 68.78

0.75 0.76 0.77 0.78 0.80 0.83 0.88 0.99 1.18 1.49 0.29 0.59

0.015

Notes:

1. The regenerator was modelled at 10 stripping trays and 2 reflux trays.

LIQUID HEAT CAP. KJ/KG/K

3.05 3.04 3.04 3.04 3.04 3.03 3.03 3.02 3.00 2.98 4.21 4.18

18


5.


Process Conditions and Heat Exchanger Information Table 5-1: Process Conditions and Heat Exchanger Information Process Conditions Treated Gas CO2 Circulation DIPA concentration Sulfolance concentration Water concentration CO2 Lean Amine Loading

Units mol % T/D wt % wt % wt % mol/mol

Test Run 0.42 9,600 43 46 11 0.025

Design 0.05 7,400 45 40 15 0.003

Future 0.05 9,000 45 40 15 0.003

CO2 Lean Amine Loading CO2 Rich Amine Loading CO2 Rich Amine Loading Reflux rate

ppmw mol/mol ppmw T/D

3562 0.31 11100 41

447 0.33 16523 46

447 0.29 14472 100

Heat Exchangers Condenser Reboiler L/R Exchanger Amine Cooler (air)

E6 E6 E6 E6

1.1 10.4 9.0 9.2

1.2 11.2 9.7 9.9

2.6 14.2 12.1 11.7

kcal/hr kcal/hr kcal/hr kcal/hr

19


6.


Sensitivity Analysis

A sensitivity study was performed to evaluate the effect of gas inlet temperature and lean solvent inlet temperature on the circulation rate required to meet the CO2 design specifications for the future case.

6.1

Gas Inlet Temperature

The sensitivity analysis performed on the gas inlet temperature demonstrated that the circulation rate to achieve the 0.05 mol % CO2 specification in the treated gas was insensitive to the feed gas temperature. This is because the treated gas temperature entering the column very quickly comes to thermal equilibrium with the rich solvent temperature leaving the column. Table 6-1 shows that for both the inlet gas temperatures (65 °C, 35 °C), the gas leaving the Tray 1 is ~ 72 °C, which matches the rich solvent temperature for Tray 1 and the remainder of the column. Therefore, the increased feed gas temperature is not a sensitive parameter for determining the required circulation rate to meet the specification of 0.05 mol % CO2 concentration in the treated gas. Table 6-1: Temperature Profiles in Column (Bottom 10 Trays)

Trays

Solvent Temperature Deg C

1 2 3

72.8 71.4 69.2

Gas Temperature Deg C 65.0 72.8 71.4 69.2

4 5 6 7 8 9 10

66.9 64.7 62.5 60.3 58.3 56.4 54.7

66.9 64.7 62.5 60.3 58.3 56.4 54.7

Trays

Solvent Temperature Deg C

1 2 3 4 5 6

71.3 71.3 69.2 67.0 64.7 62.5

Gas Temperature Deg C 35.0 71.3 71.3 69.2 67.0 64.7 62.5

7 8 9 10

60.4 58.4 56.5 54.7

60.4 58.4 56.5 54.7

20


6.2


Lean Solvent Inlet Temperature

The sensitivity analysis performed on the lean solvent inlet temperature demonstrated that the circulation rate to achieve the 0.05 mol % CO2 specification in the treated gas was sensitive to the feed gas temperature as shown in Table 6-2. As the temperature of the lean solvent is increased, the kinetics of the reaction for CO2 absorption increase, and therefore the CO2 removal is improved and the required circulation rate is decreased. However, at higher lean solvent temperatures, the temperature of the solvent in the column begin to exceed the maximum acceptable temperature ( 80 °C ) for Sulfinol solvent to avoid corrosion of the carbon steel in the column. If the absorber is stainless steel or clad with stainless steel then the maximum temperature conditions can be relaxed. If it is desired to operate the column at higher temperatures, it is recommended to change the absorber metallurgy to stainless steel of clad with stainless steel to avoid corrosion. Table 6-2 illustrates that 50 °C is the most optimum lean solvent temperature, which meets both the CO2 specification and the maximum temperature constraint. When the lean solvent temperature is increased to 55 °C, the CO2 specification can be met with 7,300 ton/day solvent, however the maximum column temperature is 88 °C. Therefore, the circulation rate needed to be increased to 9,600 ton/day in order to lower the column temperature below. Similarly, at 60 °C lean solvent temperature, the circulation rate was increased to meet the maximum temperature constraint. Table 6-2: Sensitivity of Lean Solvent Temperature Lean Solvent Temperature C 35 40 45 50 55 55 60 60

Circulation Max Temperature Rate in Column T/D C 13,000 54 10,700 63 72 9,000 8,200 80 7,300 88 9,600 80 7,200 94 11,500 80

CO2 in Treated Gas (Actual) mol % 0.05 0.05 0.05 0.05 0.05 < 0.05 0.05 < 0.05


7.

21


Conclusion

The evaluation of the design case validated the model’s accuracy to match the actual operating data for treated gas CO2 concentration. The evaluation of the test run case determined that the additional CO2 concentration in the feed gas was the major contributor to the increased CO2 concentration in the treated gas. The increased solvent circulation rate of 9,600 ton/day should have been adequate to remove the additional CO2 from the sour gas. However, it was determined that the low water content in the lean solvent and the insufficient reboiler duty were the main causes as to why 9,600 ton/day of solvent was not able to treated the sour gas to the desired treated gas requirement of 0.05 mol % CO2. The reboiler duty was inadequate to regenerate the solvent to the required CO2 lean loading to achieve the desired CO2 specification in the treated gas. The lean loading for the test run was estimated to be 3,600 ppmw based on the reboiler duty (steam rate) to regenerate the solvent. Shell’s recommended maximum CO2 lean loading is 2000 ppmw to avoid corrosion in the reboiler and lean solvent piping. The evaluation of the future case demonstrated that the required lean solvent circulation is 9,000 ton/day. This higher circulation resulted in a higher reboiler duty (14.2 E6 kcal/hr) than the existing reboiler design duty (11.7 E6 kcal/hr), and was therefore deemed inadequate. The sensitivity analysis for the feed gas temperature showed no sensitivity on the required circulation rate. The sensitivity analysis for the lean solvent temperature demonstrated 50 °C is the most optimum lean solvent temperature, which meets the CO2 specification in the treated gas without the column temperature exceeding Shell’s maximum temperature constraint in the absorber. When the lean solvent temperature is increased above 50 °C, the CO2 specification can be met with lower circulation rate, however the temperatures inside the column exceed the maximum column temperature of 80 °C which can result in corrosion of carbon steel material.


8.

22

Appendix A – Process Flow Diagram (PFD)


23



5

V-1002 E-1003

FC 2 6

V-1004 LC

P-1001

13

E-1001 C-1002

C-1001

P-1003

S-1001/3

1

LC

11

Feed Gas

V-1001 12 10 7

E-1004

E-1002

P-1002

CASE Temperature Pressure Flow MolWt H2S CO2

Test Run (low water) Stream <1> degC 67.5 bara 16.0 kg/s 5.5 12.0 mol% 0.0000 mol% 22.2661

#N/A <2> 52 15.473 0.9 2.6 0 0.2576

<5> 45 1.64 4.6 41.6 0.0000 91.6836

Water MU

<13> 45 1.64 0.0 18.0

Process Flow Diagram / H&MB ACID GAS REMOVAL PDVSA Cardon ReF PDVSA Cardon ReF Rev File

1 Date

Oct/2010 by

C:\Users\craig.j.taylor\Desktop\[AMEST.xlsm]PFD 5

Figure A-1: Sulfinol Process Flow Diagram

SGSI BV

24



Bibliographic Information This report has been classified as Restricted and is subject to US Export Control regulations and has been classified as ECCN EAR 99.

Report Number

:

NA

Title

:

PDVSA Cardon Refinery Sulfinol Evaluation

Subtitle

:

Confidential Technical Note

Author(s)

:

C. Taylor

PTU/TDUA

Reviewed by

:

A. Joura

PTU/TDUA

Approved by

:

J. Critchfield

PTU/TDUA

Content Owner

:

C. Taylor

PTU/TDUA

Issue Date

:

2010-22-10

Activity Code

:

00000000

Project Number

:

00000000

Sponsor

:

Keywords

:

Electronic file

:

Issuing Company

:

PDVSA Cardon Refinery, Sulfinol, Shell Global Solutions (US) Inc. Westhollow Technology Center, P.O. Box 4327, Houston, TX 77210, USA. Tel. +1 281 544 8844

Sulfinol D Evaluation.

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