Gas Natural

______________________________ 1 Research and Development Engineer - Dow Brasil S/A

2 Scientist – Dow Brasil S/A

IBP 2778_10

HIGH EFFICIENCY ON CO2 REMOVAL IN NATURAL GAS

WITH UCARSOL™ SOLVENTS

Thiago V. Alonso1

Copyright 2010, Brazilian Petroleum, Gas and Biofuels Institute - IBP This Technical Paper was prepared for presentation at the Rio Oil & Gas Expo and Conference 2010, held between September, 13-

16, 2010, in Rio de Janeiro. This Technical Paper was selected for presentation by the Technical Committee of the event according to

the information contained in the abstract submitted by the author(s). The contents of the Technical Paper, as presented, were not

reviewed by IBP. The organizers are not supposed to translate or correct the submitted papers. The material as it is presented does

not necessarily represent Brazilian Petroleum, Gas and Biofuels Institute’ opinion, nor that of its Members or Representatives.

Authors consent to the publication of this Technical Paper in the Rio Oil & Gas Expo and Conference 2010 Proceedings.

Abstract

The present work evaluated a gas sweetening plant using amine solvents to remove CO2 in natural gas in order to get a

sweet gas in ppm levels. The work was conducted using Dow Chemical’s proprietary simulator PROCOMP™. At this

specific case study CO2 concentration is around 13% and the maximum specification limit is 100ppm. This very rigorous

CO2 specification in treated gas is often required for liquefaction process, where gas must have all impurities removed

prior to cooling. More specifically, carbon dioxide and water must be extracted upstream of liquefaction or they would

cause damage to liquefaction facilities by freezing. The cooling of natural gas to -160º C allows it to be transported

economically by reducing the volume by 600:1. The conversion of natural gas to its liquefied form allows for the

transport of greater quantities.

The simulation is conducted with a commodity solvent, Methyl diethanolamine and also with a formulated solvent

UCARSOL™ AP-814 in order to check the performance in terms of CO2 removal, rich and lean loadings in the amine

stream, and considering the same operational conditions like recirculation rate and heat duty in regeneration.

Based on the results got for same conditions applied in both solvents, UCARSOL™ AP 814 removed most of the CO2,

letting the sweet gas with 2.67 ppm of CO2 (molar fraction). Results obtained for MDEA generated a sweet gas with

2.8% of CO2. The removal of CO2 using UCARSOL™ AP 814 was 10,000 higher comparing to regular MDEA and

proves the high selectivity for CO2 removal.

1. Introduction

Natural gas, as it is used by consumers, is much different from the natural gas that is brought from underground

reservoir. The processing of natural gas is very important in order to get an efficient calorific capacity, better

transportation conditions and also avoid corrosion problems. Although the processing of natural gas is in many aspects

less complicated than the processing and refining of crude oil, it is equally as necessary before its use by end users. [1]

The final natural gas used as fuel in the industry or vehicles is composed almost entirely of methane. However,

natural gas found in the reservoir has a lot of other compounds beyond of methane and other hydrocarbons. Raw natural

gas comes from three types of wells: oil wells, gas wells, and condensate wells. Natural gas that comes from oil wells is

typically called associated gas. This gas can exist separate from oil in the formation (free gas), or dissolved in the crude

oil (dissolved gas). Natural gas from gas wells typically produces raw natural gas and sometimes with a semi-liquid

hydrocarbon condensate. The commonly chemical composition of the gas is basically mixtures with other hydrocarbons;

principally ethane, propane, butane, and pentanes. In addition, raw natural gas contains water, hydrogen sulfide (H2S),

carbon dioxide, helium, nitrogen, and other compounds. [1] [2]

Rio Oil & Gas Expo and Conference 2010

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These contaminants found in raw natural gas can generate several problems. CO2 when combined with water

creates carbonic acid which is corrosive. CO2 also reduces the BTU value (heat capacity) of gas and in concentrations of

more than 2% or 3 % and makes it not economic viable. H2S is an extremely toxic gas that is also tremendously corrosive

to equipments. Water can be found also together gas and usually in a saturation condition. Water can generate problems

regarding hydrates formation in pipe lines and can increase corrosion rate. Amine sweetening processes remove these

acid contaminants making the gas marketable and suitable for transportation. Glycols dehydration systems can remove

water from gas stream. [2]

One particular application where natural gas must have its composition free of CO2 and water is for liquefaction

processes. More specifically, carbon dioxide and water must be extracted upstream of liquefaction or they would cause

damage to liquefaction facilities by freezing. Hydrocarbons heavier than methane are sometimes also separated and sold

as raw materials to the petrochemical industry or as fuel. The CO2 specification for the liquefaction process would be

around 50 to 100 ppm. [3] [4]

After the removal of most contaminants and heavy hydrocarbons from the feed gas, the natural gas advances

within to the liquefaction process. To obtain maximum volume reduction, the gas has to be liquefied through the

application of refrigeration technology which makes it possible to cool the gas down to approximately -162°C when it

becomes a liquid. Without contaminants, LNG is a non-corrosive liquid that is clear and colorless. The volume of LNG

equals approximately 600 volumes of natural gas at standard temperature and it makes an efficient technology for

exporting the natural gas produced in off-shore platforms. [4] [5]

Amine gas sweetening is a proven technology that removes H2S and CO2 from natural gas and liquid

hydrocarbon streams through absorption and chemical reaction. Each of the amines offers distinct advantages to specific

treating problems.

MEA (Monoethanolamine)

This is a primary amine, with just one organic substituent bound to nitrogen. There is not so much selectivity

with this amine. It removes H2S and CO2 very aggressively. However it is very corrosive in concentrations above 18%

weight/weight decomposes in the presence of CO2 to form carbamates increasing corrosion problems and also usually

need reclamation units.

DEA (Diethanolamine)

This is a secondary amine, with just two organic substituent bound to nitrogen. This amine removes H2S and

CO2 and also COS. Typically used in concentrations of 30% wt or less and also can decompose in the presence of CO2 to

form carbamates increasing corrosion problems.

MDEA (Methyldiethanolamine)

This is a tertiary amine, with three organic substituent bound to nitrogen. Has a higher affinity for H2S than CO2

which allows some CO2 slip. Has a low heat of reaction comparing to primary and secondary amines, which represents

lower energetic costs for regeneration. Carbamates are not formed and concentration up to 45% wt. can be used. [6]

UCARSOL™ - FORMULATED SOLVENTS

UCARSOL™ solvents are formulated products that can work for specific customer’s desired application in a

very efficient way. These products allow low required regeneration energy comparing to conventional amines and

corrosion problems are much reduced. These tailored solvents were developed for bulk CO2 removal, H2S removal with

CO2 slip and many other applications for natural gas and refineries gas sweetening plants. [7]

At this work, it is shown a gas treating system working with UCARSOL™ AP 814, a formulated amine

designed to remove high levels of CO2, where sweet gas has a specification of 100 ppm maximum of CO2.


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2. Materials and Methods

Results were obtained using DOW’s proprietary simulation software PROCOMP™. The simulator solves the

material balances, heat balances, mass transfer relations and equilibrium relations necessary to perform rigorous rate

based calculations on absorbers and strippers. Other equipment such as heat exchangers, pumps and flash tanks, can also

be simulated.

All vapor liquid equilibrium values are screened and fitted when necessary to ensure that simulator matches

experimental data.

3. Results and Discussion

In this situation the sweet gas must achieve 100 ppm maximum of CO2. Usually CO2 specification for

transmission pipelines is 2 – 3 % maximum. However if a process like LNG is considered, the total amount of CO2 in

natural gas must be around 50 – 100 ppm.

The sour gas composition in molar percentage and its characteristics are below:

CO2: 13.85

CH4: 83.00

Ethane: 2.22

Propane: 0.63

Others: 0.16

Temperature: 12.7 °C

Pressure: 68 bar (a)

Flow rate: 50 MMSCFD

The gas treating plant simulated in this case has the following basic conditions for the absorber and stripper.

Absorber Column:

- Diameter: 1.98 m

- Active tray Area: 1.7 m2

- Number of Trays: 24

- Tray Spacing: 2 ft

- Weir height: 4 in

- Internals: Koch FLEXITRAYS

Regenerator Column:

- Diameter: 2.28 m

- Active tray Area: 3.1 m2

- Number of Trays: 20

- Tray Spacing: 2 ft

- Weir height: 3 in

- Internals: Koch FLEXITRAYS


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The flowchart of the process is described in figure 1 below.

Figure 1. Flowchart of the simulated plant

In this case, the gas comes saturated in equilibrium condition with water. The inlet temperature is 12°C, which

is considered low for the entrance in the absorber column. One heat exchanger was added to the top of absorber column

in order to capture the heat of the hot sweet gas for the cold sour gas. The temperature of sour gas is raised to 27°C. The

inlet gas enters the bottom section of the amine contactor. The rich amine will enter the amine regeneration system

feeding into the amine flash tank. The amine flash tank is designed to provide 10 minutes of residence time.

The liquid amine from the amine flash tank flows trough a lean/rich exchanger where rich amine is pre-heated

before moves into the stripper and lean amine is cooled before it goes to cooler. The rich amine is fed at the top stage of

the regenerator column. A water cooled heat exchanger is provided for the reflux condenser and a horizontal vessel

serves as the reflux accumulator. The acid gas vapors of the reflux accumulator moves for its final disposal. At the

bottom of the amine regenerator, heat duty is provided in the reboiler with saturated steam or hot oil. Lean amine leaves

the stripper is, pre-cooled in Rich/Lean amine heat exchanger and it is cooled in air cooler. The lean amine is pumped

into the absorber column where it reacts with acid gases.

For an efficient gas treating system, a key factor of success is to have controlled the degradation levels of amine,

keep under control the corrosion rate of pipelines, to manage the amount of energy spent mainly for the regeneration

process and for cooling, heating operations, and pumping activities and most importantly, leaving the sweet gas under

desired specification limits.

The simulation was conducted in this case with a regular commodity amine MDEA (Methyl Diethanolamine)

and also with formulated solvent UCARSOL™ AP 814. The solvents were running with a solution 50% of amine 50%

water by weight.


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Some operational characteristics of the simulated gas sweetening plant are described in table 1. The simulation

was conducted for both solvents using these fixed properties. The circulation rate is one of the most important factors to

be considered as the circulation rate is increased for any given column, the CO2 pickup will increase due to higher

amount of amine moles to be reacted to acid gases in a certain time.

Table 1 – Process conditions for simulation

Absorber Pressure bar (a) 65

Flash tank residence time (min) 10

Regeneration Pressure bar (a) 1.8

Amine concentration in water (% wt) 50

Reboiler Heat Duty (MMBTU/h) 40

Amine circulation rate (m3/h) 160

Regenerator condenser temperature (ºC) 45

At table 2 below, it is shown the treated gas condition for both solvents at the stream above the absorber column.

Table 2 – Sweet gas characteristics

MDEA UCARSOL™ AP-814

Temperature (ºC) 25 23

Pressure (bar a) 65 65

Molar Flow (kmol/hr) 2218 2155

Water (mol fraction) 2.00 . 10-3 2.00 . 10-3

CO2 (mol fraction) 2.80 . 10-2 2.67 . 10-6

Methane (mol fraction) 9.35 . 10-1 9.63 . 10-1

Ethane (mol fraction) 2.50 . 10-2 2.50 . 10-2

Propane (mol fraction) 7.00 . 10-3 7.00 . 10-3

n-Butane (mol fraction) 3.00 . 10-3 3.00 . 10-3

By the results obtained, it can be seen that UCARSOL™ AP-814 let the sweet gas with 2.67 ppm of CO2 in its

composition, covering the required specification. The results conducted with regular MDEA generated a CO2

concentration in sweet gas around 2.8%, almost 104 times higher comparing to the formulated solvent, considering the

exactly same operational conditions. Not considerable changes in terms of hydrocarbons composition is seen for both

cases.

In table 3, the results for simulation are described for the acid gas stream.

Table 3 – Acid gas characteristics

MDEA UCARSOL™ AP-814

Temperature (ºC) 45 45

Pressure (bar a) 1.6 1.6

Molar Flow (kmol/hr) 302 364

Water (mol fraction) 0.06 0.06

CO2 (mol fraction) 0.93 0.94

Residual Hydrocarbons (mol fraction) 0.01 ---


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The acid gas produced by this system has basically the same molar composition for both solvents analyzed.

However, the total molar flow obtained for UCARSOL™ AP 814 case is 20% higher comparing to MDEA, showing

that this solvent better removed the CO2.

The analysis of rich and lean amine loadings were conducted also. The molar concentration of CO2 per moles of

amine is described to be the loadings. The rich amine has a high concentration of CO2 and it is found at the stream that

flows out the absorber column. The lean amine has a low concentration of CO2 and it is found at the stream that flows

out the regenerator column. To avoid corrosion problems, these loadings must be under certain specified values. Also,

the maximum temperature of lean amine must be below 130°C to avoid solvent degradation and corrosion issues. The

conditions for rich/lean amine are found in table 4 and table 5.

Table 4 – Lean/Rich amine streams for MDEA

Lean loading mol CO2/mol MDEA 0.002

Hot Lean amine temperature (ºC) 125

Cold Lean amine temperature (ºC) 42

Rich loading mol CO2/mol MDEA 0.41

Hot Rich amine temperature (ºC) 100

Cold Rich amine temperature (ºC) 62

Table 5 – Lean/Rich amine streams for UCARSOL™ AP 814

Lean loading mol CO2/mol UCARSOL™ AP 814 0.015

Hot Lean amine temperature (ºC) 125

Cold Lean amine temperature (ºC) 41

Rich loading mol CO2/mol UCARSOL™ AP 814 0.495

Hot Rich amine temperature (ºC) 100

Cold Rich amine temperature (ºC) 79

The rich loading for UCARSOL™ system was around 0.49 moles CO2/mole of amine and for regular MDEA

0.41 moles CO2/mole of amine representing a better removal of CO2 from the sour gas in the absorber columns. It is

important to keep lean loading below 0.02 moles CO2/mole of amine. High lean loadings and solution degradation

products can lead to corrosion and reboiler fouling problems. At the same way, it is important to keep the rich loadings

around 0.4 to 0.5 moles CO2/mole of amine in order to reduce further corrosion and degradation problems. [8]

The lean loading for MDEA case is considerably low, as it indicates that over regeneration in stripper happened.

As the steam-stripping rate is increased, a leaner amine will be produced which can result in a greater distance to

equilibrium and more CO2 can be removed from the sour gas. However it is very important to consider that over

regeneration can generate corrosion problems too.

Temperature evaluation trough the section of the columns was also assessed for both cases studied. The charts

for temperature change by the segment in the columns for absorber and regenerator are described in figure 2 and figure 3.


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Figure 2. Absorber and regenerator temperature profile for UCARSOL™ AP 814

Figure 3. Absorber and regenerator temperature profile for MDEA

Usually the only parameter available for control of the column temperature is the lean amine temperature. Since

the CO2 reaction with MDEA is kinetically controlled, a hotter column increases the reaction rate. However, once the

lean amine temperature reaches about 135 to 140 °F, the decrease in solubility of the CO2 in the amine solution will

usually become the overriding factor and the net CO2 pickup will begin to decrease. [9]


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A comparison of the temperature profiles in the absorber shown in Fig. 2 and Fig 3. shows that the

UCARSOL™ AP-814 promoted the reaction with the CO2 more strongly in the lower portion of the column where

temperature increased considerably. This behavior is not seen for MDEA as temperatures in upper region of the column

are higher. This is important as the exothermal reaction is concentrated in the bottom of the column showing that CO2

reacts immediately with amine when they are in contact. The flat temperature behavior shows that for MDEA the

reaction occurs trough all the column and reaction is much slower comparing to UCARSOL™ AP-814.

4. Conclusions

By the results observed, UCARSOL™ AP 814 showed a very efficient performance to remove CO2 in a high

concentration of a natural gas stream until ppm levels, where it is required for liquefaction process. The amount of CO2

in sweet gas generated was around 2.67 ppm while regular MDEA removed CO2 in the same conditions till 2.8%.

The acid gas composition did not show much difference for both solvents; however the molar flow of acid gas

produced by UCARSOL™ AP 814 was 20% greater comparing to MDEA. The rich amine loadings were under desired

control values, and lean loadings for UCARSOL™ AP 814 were in good levels. The lean loading for MDEA was

considerable low indicating that over-regeneration is happening. In this case, it is recommended to reduce heat duty in

reboiler stripper to avoid corrosion problems in the pipelines and equipments.

Temperature profiles showed that UCARSOL™ AP 814 reacts much faster with CO2 comparing to MDEA.

The high temperature at the bottom of the column show where most of the absorption of CO2 is occurring as this is an

exothermal reaction. MDEA temperature profile is more flat in comparison with the pother solvent, showing reaction

occurs along entire absorber column and reaction is therefore slower. This is the main reason that MDEA did not

accomplish the desired CO2 removal in this system.

5. References

[1] Natural Gas, Secondary Energy Infobook PAGE 31

[2] LEAL, O et al, Carbon Dioxide Removal from Natural Gas using Amine Surface bonded adsorbents

[3] EBENEZER, S et al, Removal of carbon dioxide from natural gas for LNG production - Institute of Petroleum

Technology Norwegian University of Science

[4] The LNG Process Chain, Information Paper No. 2 — LNG Process Chain

[5] BARCLAY et al, Selecting offshore LNG processes, LNG journal October 2005 page 36

[6] SAAR, R et al, An Operational Comparison of DEA Versus Formulated High Performance Selective Amine

Technology, CGPA/CGPSA Third Quarterly Meeting

[7] UCARSOL™ AP-814 for CO2 removal – Product information

[8] Oil&Gas journal, edition from June 9, 2003.

[9] ALIBADI et al, Using Mixed Amine Solution for Gas Sweetening, World Academy of Science, Engineering

and Technology 58 2009

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