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SWEETENING TECHNOLOGIES – A LOOK AT THE WHOLE PICTURE

Marco Bergel 1, Ignacio Tierno

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1. TECNA Estudios y Proyectos de Ingeniería S.A.

Keywords: 1. Sweetening; 2. Carbon dioxide; 3. Acid gas; 4. Amines; 5. Membranes. 1 Background

Nowadays, a wide variety of gas sweetening technologies is commercially available: different

chemical and physical solvents, membranes, regenerable adsorbents, among others . Many have their own niche, but there are still cases where different technologies compete for a same application. Combining processes can even produce better results.

To answer the question: “which method fits the project requirements best?”, one should also

consider the whole gas processing scheme and site conditions, and not only the sweetening technology itself.

The present paper analyses sweetening technologies available to treat natural gas with a high

carbon dioxide (CO2) content, considering the integration of sweetening facilities with different gas processing schemes and under different site conditions:

- downstream processing of sweet gas: cryogenic processes, NGL recovery, power generation or injection into pipeline

- acid gas disposal method: venting or reinjection - energy costs - inlet gas pressure and CO2 content - CO2 specification - power availability, remoteness of location Most selection guidelines focus on the sweetening process and consider it as an isolated facility.

However, this paper shows the best choice should arise from a thorough analysis of the complete gas processing scheme. Throughout the following pages the factors that influence sweetening technology selection will be addressed.

2 Introduction

Design of an efficient and competitive processing scheme is a crucial stage in the development of

gas fields. In that context, the sweetening unit plays a leading role due to the wide variety of technologies for CO2 removal currently available. Amongst them, chemical and physical solvents, membranes and regenerable adsorbents stand out. The process engineer faces then the challenge of selecting the technology that best fits the project needs.

This work proposes a critical analysis of the traditional selection tools for removal of acid gases,

suggesting an alternative approach that contemplates the project as a whole together with external factors, besides the characteristics of the gas to be treated. Additionally, the flexibility of the main technologies to deal with gradual changes in CO2 content specifications is analyzed.

3 Sweetening technologies

There are several technologies commercially available to treat acid gases. Some of them are based

upon the absorption of CO2 by means of a chemical or physical solvent and its subsequent desorption, others use the difference in permeability through a material of natural gas components. These differences in the removal mechanism determine the main advantages and disadvantages thereof.

For the purpose of briefly describing each of them, sweetening technologies can be classified

according to the following table:

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Table 1 – Classification of sweetening technologies

CO2 removal

mechanismProcess type Technology Commercial name

AminesMEA, DEA, MDEA, DIPA,

DGA, formulated solvents

Potassium carbonateBenfield, Catacarb,

Giammarco-Vetrocoke, etc.

Non regenerative, continuos

(usual arrangement: lead/lag)Sodium hydroxide -

Physical absorption Regenerative, continuous Physical solventsSelexol, Rectisol, Purisol,

Fluor Solvent, IFPexol, etc.

Physical-chemical

absorptionRegenerative, continuous Physical-chemical solvents

Sulfinol, Ucarsol LE 701,

702 & 703, Flexsorb PS, etc.

Physical adsorption

Regenerative, continuous

(adsorption/desorption

sequence)

Molecular sievesZ5A (Zeochem), LNG-3

(UOP), etc.

Permeation Continuous MembranesSeparex, Cynara, Z-top,

Medal, etc.

Regenerative, continuous

Chemical absorption

Note: distillation processes (typical of enhanced oil recovery projects, w ere CO2 is recovered from the gas to re-inject it) are not

included in this list; their range of application is beyond the typical cases of natural gas processing.

a. Particular characteristics A detailed description of each technology can be found in References 1 to 3. It will become useful to

remember some particular characteristics: - Absorption with amines is one of the most widespread processes in the industry. Even though

there are several amines, for the treatment of natural gas mostly MDEA or formulated solvents based on MDEA are employed.

- CO2 absorption with potassium carbonate takes place at high temperatures. The process shows similarities with that of amines in that it consists of absorption and reaction in the contactor column.

- Physical solvents can be regenerated by means of successive depressurizations, without heat input. However, there is a wide variety of process schemes, and thermal regeneration or stripping may be required. Physical solvents absorb heavy hydrocarbons and water, and in certain cases they allow to reach all gas specifications in one same unit.

- Absorption with mixed solvents keeps many similarities with absorption with amines, and has some of the advantages associated to physical solvents (lower heat requirements for regeneration).

- Adsorption becomes efficient for CO2 contents below 2% and makes it possible to achieve very low specifications (< 50 ppm). In addition, water, H2S, mercaptans, and other sulfur compounds are removed, thus its use is usual in gas liquefaction trains (for LNG production).

- Gas pretreatment is very important to ensure membranes lifespan, and it can be classified as follows: o Gas heating. o Heavy hydrocarbons separation by cooling (by mechanical refrigeration or Joule-Thomson

effect). o Heavy hydrocarbons and water adsorption by means of a regenerable adsorbents system.

Additionally, all of them include filtering. The pretreatment choice depends on CO2 removal ratio, the heavy hydrocarbons content and on the uncertainty associated to gas composition. In membranes methane is lost, thus “enriching” the residual gas in heavy hydrocarbons.

- Removal of small amounts of acid gases is usually carried out with non-regenerative chemical scavengers. A possible arrangement consists in making the gas flow through a vessel containing the scavenger.

b. Summary table

Table 2 summarizes the main characteristics of the above mentioned sweetening technologies.It

may become useful for a first pre-selection, to discard technologies with application ranges that do not fit the project requirements.

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Table 2 – Main characteristics of sweetening technologies

AMINES MEMBRANES HOT POTASSIUM CARBONATE PHYSICAL SOLVENTS MIXED SOLVENTS PHYSICAL ADSORPTION NON REGENERATIVE SOLVENTS

Up to 70% V Up to 90% V 5% V to 50% V PCO2 > 3.5 bara PCO2 > 7.6 bara 0.1% V to 2% V < 0.1% V

From 2% V down to deep removal 1% V≥ 1.5% V (single stage scheme)

≥ 0.1% V (two stage scheme)1% V < 0.5 % V 50 ppmV 5 to 300 ppmV

From low to more than 10 From very low to more than 10 From low to 7 From 3 to 11 From low to more than 10 From low to 3 Low

PressureAbsorber: 5 to 120 bara

Regenerator: 1.5 bara27 bara to 100 bara

Absorber: 69 bara

Regenerator: 1.5 baraAbsorber: 69 bara

Absorber: 69 bara

Regenerator: 3 bara or lowerAdsorption: 14 to 69 bara As required

Temperature 30 to 60ºC (absorption) < 60ºC 110 to 120ºC -18ºC to Ambient Ambient to 60ºC (absorption)Adsorption: 30 to 60ºC

Regeneration: 350ºCAmbient

Less than 1%1 stage: 8 - 15%

2 stages: 2%Very low

Absorbs heavy hydrocarbons &

aromatics

Absorbs heavy hydrocarbons &

aromaticsNone None

Process Turndown Gas Flow Rate 30% 20% 30% Approximately 30% Approximately 30% Low (Note 4) No limitation

_Contactor

_Regeneration System (Note 1)

_Flash Drum

_Lean/Rich Amine Heat Exchanger

_Lean Amine Cooler

_Circulation Pumps

_Inlet Pre-Treatment (Note 2)

_Membrane Skid

_Recycle Compressor and Coolers

(for 2 stages systems)

_Contactor

_Regeneration System (Note 1)

_Gas/Gas Heat Exchanger

_Circulation Pumps

_Lean Solution Cooler (for 2 stage

process scheme)

_Contactor

_CO2 Recycle Flash Drum

_Flash Drums at different pressures

_Lean Solvent Pumps

_Rich Solvent Pumps

_Vacuum Pump

_Recycle Compressor (Optional)

_Chiller (Optional)

_Contactor

_Regeneration System (Note 1)

_Flash Drum

_Lean/Rich Solvent Heat Exchanger

_Lean Solvent Cooler

_Circulation Pumps

_Reclaimer (Optional)

_Molecular Sieve Vessels

_Regeneration Gas Heater

_Liquid Scavenger Towers

SS for certain parts (Lean/Rich Heat

Exchanger, Reboiler tubes, Regeneration

System overhead)

Pre-treatment: CS or SS (high acid

gas content)

Membrane Skid: CS

Stainless Steel for certain parts Carbon SteelSS for certain parts (Lean/Rich Heat

Exchanger)Carbon Steel Carbon Steel

High Low High High High Medium Low

_Heating Medium

_Power

_Chemicals (e.g. antifoam)

_Pre-treatment requirements (e.g.

Power, Refrigeration)

_For 2 stages: Power (for

Compression)

_Heating Medium

_Power

_Chemicals (e.g. antifoam)

_Power

_Chemicals (e.g. antifoam)

_Refrigeration (Optional)

_Heating Medium or Stripping Gas

(Optional)

_Heating Medium

_Power

_Chemicals (e.g. antifoam)

_Heating Medium

High complexity Low complexity (Note 6) Very High complexity High complexity High complexity Medium complexity Low complexity

Oxygen, Heavy HC (liquid state), Solid

particles, Organic acids

Heavy HC, BTEX, Glycols, Amines,

Liquid waterSolid particles, Heavy HC (liquid state) Solid particles, Heavy HC (liquid state)

Solid particles, Heavy HC (liquid state),

Oxygen

Heavy HC (liquid state), Glycols,

Amines, Liquid waterHeavy HC (liquid state)

Investment High Medium High Medium High Medium Low

Operation Medium1 stage: Low

2 stages: MediumLow Low Medium Low High

Outlet gas saturated with water. Gas is dehydrated.Outlet gas saturated with water.

Solution can precipitate.Gas is dehydrated.

Sulfinol solvent is relatively expensive.

Outlet gas almost saturated with water. Gas is dehydrated.

Outlet gas saturated with water. The

spent caustic is a hazardous waste.

Notes:1.- Regeneration System includes: Regeneration Column (Still), Condenser, Accumulator, Reflux Pumps and Reboiler.

2.- Inlet pre-treatment depends on gas composition. Simple pre-treatment includes: coalescing filter, non-regenerable adsorbent (activated carbon) guard bed, dust filter and heater.

Enhanced pre-treatment could include a LTS Unit (mechanical refrigeration), a Joule-Thompson Expansion Unit or a Regenerable Adsorption System.

3.- Inlet and Outlet Scrubbers, Filters not indicated.

4.- Adsorption/cooling cycles must be lengthened.

5.- CS: Carbon Steel. SS: Stainless Steel.

6.- Membrane unit only. Complexity increases with recycle compression (two stage membrane process) and enhanced pre-treatment schemes.

PROCESS

ITEM

Notes

Typical Operating

Conditions

Main Equipment (Note 3)

Lay Out Requirements

Cost Composition

Materials Requirements

Services Requirements

Ease of operation

Contaminants

Typical Hydrocarbon Losses

Acid Gas Content at Inlet

Typical Acid Gas Content at Outlet

Typical Gas Flow Rate (MMSCMD)

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4 The traditional approach Facing the vast range of applicable technologies, the process designer’s challenge lies in selecting

the optimal technology for the project at issue. A first approach to the problem consists in referring to the “traditional” selection guidelines.

As starting point, the content of acid gases in the gas to be treated could be an adequate parameter

to find guidance in the selection. As it is observed in Figure 1, some technologies can be easily discarded. However, most of them present a quite broad application range. In addition, this criterion seems to be insufficient since it fails to contemplate the treated gas specification that must be reached.

Figure 1 – Example of gas sweetening technologies selection chart [Ref. 1]

0

10

20

30

40

50

60

70

80

90

100

SOLID BED AND

SCAVENGER

PRIM ARY AND

SECONDARY

AM INES

TERTIARY AM INES HOT POTASSIUM

CARBONATE

PHYSICAL

SOLVENTS

M EM BRANES

Acid

Gas C

on

ten

t, C

O2+H

2S

Vo

l%

Incorporating this second parameter in the selection chart, we obtain Figure 2. This allows us to

restrict even more the possible alternatives. But again, it turns out to be incomplete since it fails to contemplate a crucial parameter as the pressure of the gas to be treated, and consequently, the partial pressure of the CO2 to be removed.

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Figure 2 – Example of gas sweetening technologies selection chart [Ref. 3]

100% 100%

10% 10%

1% 1%

1000 ppm 1000 ppm

100 ppm 100 ppm

1 ppm 10 ppm 100 ppm 1000 ppm 1% 10%

Acid Gas Concentration in Outlet Gas

Ac

id G

as

Co

nc

en

tra

tio

n in

Fe

ed

Guide to selection of gas sweetening processes

Batch Processes, Mol Sieves

Amines,

Mol Sieves,

Batch Processes

Membranes

Physical Solvents, Mixed Solvents, Amines

Membranes followed by Amines

Membranes,

Physical Solvents

Physical Solvents,

Potassium Carbonate

Physical Solvents,

Mixed Solvents,

Amines Amines, Mixed Solvents, Physical

Solvents, Potassium Carbonate

Amines, Mixed Solvents

Figure 3 is a selection chart that incorporates this consideration.

Figure 3 – Example of gas sweetening technologies selection chart [Ref. 2]

1

10

100

1000

0,1 1 10 100

Partial Pressure of acid gas in Product (psi)

Part

ial P

ressure

of acid

gas in

Feed (

psi)

Physical solvents

Amines (high

loading) or

Physical solvents

Physical solvents or Amines

Amines or Mixed solvents

Potassium carbonate,

Mixed solvents or

Amines

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After a quick visual inspection of the 3 figures, some “rules of thumb” become almost evident, allowing us to discard some of the processes:

- For low quantities of CO2 to be removed, non-regenerative processes become the recommended alternative due to the low installation cost of this technology, while for large quantities, the operating cost of the solvent that cannot be regenerated makes its application prohibitive.

- Physical adsorption becomes economically convenient for low concentrations of inlet CO2, and it is generally applied for gas “polishing”, when H2S and mercaptans or other sulfur compounds must also be removed. Its use to remove exclusively CO2 is not usual.

- Physical solvents present a certain disadvantage for low partial pressures of CO2 in the inlet gas. For partial pressures above 50 to 150 psi, this technology can become attractive over chemical solvents.

- Processes based upon amines make it possible to achieve ‘restrictive’ specifications of acid gas (for example, lower than 2%), and they present a broad application range.

- Membranes do not seem to be adequate to reach restrictive CO2 specifications (for example, lower than 2%). This assertion extracted from the figures analysis is not completely valid. Membranes lose competitiveness for high removal ratios of carbon dioxide (for example, an 85% removal: from 14% to 2% CO2), that are generally associated to reaching restrictive specifications. But they become more competitive for low removal ratios of carbon dioxide, even when they are associated to restrictive specifications (for example, a 9% removal: from 1.1% to 1% CO2).

- Some process combinations become attractive, e.g.: membranes followed by amines, also called “hybrid systems”. The preferential use of these systems seems to be high CO2 partial pressures in the feed gas and low CO2 contents in the treated gas.

To this point, we have discarded a certain amount of technologies after sketching a quick selection of

the applicable ones. However, this traditional approach has shown to be insufficient for a final selection. It is important to incorporate additional criteria that take into account the project restrictions and the conditions of the environment, in addition to the characteristics of the gas to be treated and of course, to carry out an economic analysis of the pre-selected alternatives. The optimum selection may be even different to that arising from using the above mentioned charts.

5 The proposed approach

So far, the technologies have been analyzed isolated from the remaining processing units, even

though it is usual to find a strong interaction among them. The proposed approach consists in not losing sight of the impact of the sweetening unit in the remaining facilities, also considering the external factors in the evaluation.

a. Project restrictions

Units located upstream of the sweetening unit

Compression:

Due to the corrosive nature of acid gases, sweetening generally constitutes the first stage of gas

processing, afterwards followed by dehydration and hydrocarbon dew point conditioning. But depending on the pressure at which the gas is available and the delivery pressure, it may be necessary to compress it, in such case compressors may be placed upstream of the sweetening unit.

In general, all technologies profit from a higher inlet gas pressure, due to the increase in CO2 partial

pressure (greater driving force). The saving in the cost of the sweetening unit must be compared to the cost increment in compression (since a larger gas flow rate is being compressed) plus the cost increase due to the metallurgy of the compression unit, if any, due to acid gas handling (scrubbers and air-coolers may require stainless steel instead of carbon steel if liquid water is present with high partial pressures of CO2).

Amine units constitute an exception to the aforesaid, since gas treatment pressure does not have a

striking impact on plant cost if it is above some 40 bar, and the content of CO2 is higher than 10%, approximately. Moreover, the plant may become marginally more expensive when increasing the treatment pressure. Generally, the amine load is limited in order to avoid corrosion and solution degradation problems (to approximately 0.45 mol CO2/mol amine), therefore a higher treatment pressure does not influence the amine circulation rate and the regeneration section size (regeneration column, reboiler, lean amine cooler, etc.). However, it does impact on the shell thickness required for the absorption column, and in many cases the increase in thickness compensates or exceeds the reduction in column diameter due to treating smaller gas actual flow rates.

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Other processes:

Even though acid gas removal is usually the first stage of gas processing, in some cases it may be

advantageous to sweeten the gas downstream of liquid recovery units. For example: - For low removal ratios of CO2, for example from 2.2% to 2%, installing a membrane unit

downstream of a dew point conditioning unit may turn out to be convenient. The dew point unit removes the water and heavy hydrocarbons from the gas, and only a minimum pretreatment (filtering) is required to protect the membranes. Sweetening, in addition, will not moisten the gas again.

- In turboexpansion plants for ethane recovery (C2), an important percentage of the inlet CO2 will liquefy and it will be recovered together with the C2 (for example, 50% of CO2 for a C2 recovery of 90%, strongly depending on the gas pressure and the process employed). In these cases the residue gas specification can be met, and the liquids be treated to remove the CO2 –a much smaller volume, at low pressure– as long as the carbon dioxide does not freeze in the turboexpansion process.

Units located downstream of the sweetening unit

Injection to pipelines:

If the heavy hydrocarbon content (C5+) of the gas to be treated is low and no dew point conditioning

is required, the sweetened gas may be delivered to the gas transmission pipeline system (after dehydration, if necessary). In this case, the CO2 and water content allowed by the country’s legislation or the transportation company’s specifications must be reached. Table 3 shows some specifications typical of South America, while Table 4 shows the water content of the sweet gas for different processes.

Table 3 – Gas specifications typical of South America

Contaminant Units Argentina (1) Bolivia (2) Venezuela (3)

Present: 8.5

2009: 6.5

2011: 4

2013: 2

Present: 17.3 (12.0)

2009: 13.3 (9.2)

2011: 9.8 (6.8)

2013: 6 (4.2)

Present: 112 (7.0)

2009: 105 (6.6)

2011: 97 (6.1)

2013: 90 (5.6)

Source:

(1) ENARGAS Resolution No. 622/1998, Basic specifications (non-relaxed).

(2) Transredes – SSDH Administrative Resolution No. 0670/2001 – SSDH No. 0190/2002.

(3) COVENIN 3568:2-2000; Resolution No. 162 issued by the Ministry of People's Power for Energy and Petroleum

[Ministerio del Poder Popular para la Energía y Petróleo], 17/09/2007.

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Total inerts % mol 4 3.5 -

N2 % mol 2 2

H2S mg/Sm3 (ppmv) 3 (2.1) 5 (3.5)

mg/Sm3 (lb/MMSCF)Water 65 (4.1) 95 (5.9)

2 2CO2 % mol

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Table 4 – Water content in gas according to sweetening process

Treated gas Residual acid gas

Amines Saturated with water Saturated with water

Potassium carbonate Saturated with water Saturated with water

Physical solvents Dehydrated (1) (varies according to regeneration method)

Mixed solvents Close to saturation (2) Saturated with water

Heating Dehydrated (1) Sub-saturated (3)

Refrigeration (mechanical, JT) Dehydrated (1) Sub-saturated (3)

Adsorption (TSA) Dehydrated (4) Dehydrated (4)

Physical adsorption Dehydrated (4) (varies throughout regeneration cycle)

Non-regenerable (batch) Saturated with water (in aqueous solution)

Notes:

(1) In general, water contents lower than 110 mg/Sm3 (7 lb/MMSCF) are reached.

It must be analyzed on a case-by-case basis whether it is sufficient to comply with transport specifications.

(2) Treated gas is approximately 3 to 5ºC above its water dew point.

(3) Residual acid gas is approximately 20 to 40ºC above its water dew point.

(4) Dehydrated down to ppm levels (e.g.: <50 ppm of water).

Process

Membranes; pre-treatment:

As may be observed, amine treatment requires dehydration of sweetened gas. On the other hand,

membranes will usually remove enough water together with CO2 to comply with the specification (it must be verified in each particular case). In an economic comparison of processes, costs must include a dehydration unit (generally with TEG) in cases that require it. As an approximate value, adding a TEG unit may increase the investments required by 10% to 15% above the cost of an amine unit.

It is worth pointing out that, in the cases of Bolivia or Argentina, where the total inert content is

limited, if the nitrogen content of the gas is high, CO2 removal may be required even up to lower levels than its maximum admissible content, in order to comply with the inerts specification.

Dew point conditioning:

If the heavy hydrocarbon content of the gas to be treated is relatively high, in addition to sweetening,

its hydrocarbon dew point conditioning will be required in many cases, to comply with sales specifications and/or to obtain higher incomes for the production of gasoline.

Dew point conditioning processes resort to the generation of low temperatures to condense heavy

hydrocarbons. Even though this seems detrimental to sweetening processes that heat the gas (e.g.: potassium carbonate), in a global comparison this difference between processes is not a determining factor. For instance, in the case of membranes, gas is typically heated approximately 10 ºC above residue gas dew point; in an amine process, gas temperature increase ranges from 5 to 15 ºC, and can reach up to 30 ºC. This difference is compensated by installing an air cooler between the sweetening unit and the dew point conditioning unit: the total cost increase is not significant, specially in cases of high inlet gas temperature.

In accordance with Table 4, sweetening processes affect the water content of the gas being treated.

Hydrocarbon dew point conditioning processes imply dehydration, and the amount of water to be removed will exert a slight impact on the cost of the dew point conditioning unit. In many cases, the water content of the gas after membrane sweetening is not enough to meet the dehydration requirements of a dew point conditioning process, and the continuous injection of a hydrate inhibitor (such as mono-ethylene-glycol) will be required to prevent the formation of hydrates in the cold separator.

In the case of membrane units with pretreatment based on adsorption with regenerable sieves, the

removal of heavy hydrocarbons during pretreatment may be sufficient to comply with the hydrocarbon dew point specification, specially in the case of gases having heavy hydrocarbons (up to C20 or more) but a low C4+ content. In these cases, it is worth to consider integrating sweetening and dew point conditioning in the same unit, to keep facilities complexity level low (it may be necessary to add mechanical refrigeration in order to cool the inlet gas and perform adsorption at lower temperatures). In some cases, physical solvent absorption allows such integration among sweetening, dehydration and dew point conditioning.

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Recovery of natural gas liquids (NGL): To recover higher percentages of NGL (butane, propane and, depending on the case, ethane), it is

also usual to resort to the generation of low temperatures. The technology most frequently applied is turboexpansion.

In these cases, the required CO2 removal may be higher than that set forth by gas transportation

specifications and will be prescribed by the process conditions in order to prevent the formation of solid CO2, mainly in those cases in which ethane is recovered (due to the very low temperatures involved).

Membrane sweetening and a pretreatment based on adsorption located upstream of a

turboexpansion unit can result in an interesting integration. In this way, the dedicated molecular sieves located at the entry to the turboexpansion unit for dehydration may be reduced in size, or even eliminated if the expansion ratio is not very high.

Electric power generation:

If the treated gas is used for electric power generation, the allowable CO2 content is higher than that

required by typical transportation specifications. In many cases sweetening is not even necessary, or a minor conditioning is enough. With adaptations to combustion systems, fuel gases with heating values as low as 300 BTU/SCF can be used for turbo-generators (up to 65% CO2). The lowest limit must be analyzed together with turbine vendors. In these cases, membranes benefit from the low removal ratios required.

Disposal of acid gas

A very important aspect to be considered is the destination of the acid gas separated. The following

table summarizes possible destinations:

Table 5 – Acid gas disposal options

Gas Engines Gas Turbines Fired heaters Flaring Venting Injection

> 600 > 66% Ok Ok Ok OkNot

recommended

Ok (higher

injection costs)

600 to 300 66% to 33% Ok Ok Ok OkNot

recommendedOk

300 to 200 33% to 22% (lower limit) (lower limit) (lower limit) OkNot

recommendedOk

200 to 150 22% to 16% Not feasible Not feasible Not feasible (lower limit)Not

recommendedOk

< 150 < 16% Not feasible Not feasible Not feasible Not feasible OkOk (lower

injection costs)

LHV

(BTU/SCF)

Methane

content

(remainder:

CO2)

Possible destinations according to gas lower heating value

Venting:

For chemical solvents, the CO2 released contains very low hydrocarbon levels (generally lower than

0.2%), and, pursuant to the legislation in force in many countries of South America, it may be vented to the atmosphere, provided it does not contain significant H2S levels. For acid gas containing H2S, calculations of hydrogen sulfide dispersion in the atmosphere must be developed to ensure that there is a suitable safety margin between toxicity limits and the concentration thereof in any area accessible to operators (for example, the closest platform to the acid gas stack). Were this is not possible, alternatives to venting must be contemplated. In the case of mixed and physical solvents, the hydrocarbon content of acid gas is higher, ranging approximately from 1 to 5%, and venting is usually not possible.

Flaring:

In the case of CO2 with higher hydrocarbon contents (for example, membranes permeate gas) or in

such other cases in which venting is not an option (for example, amine regeneration gas because of its H2S content), acid gas may be flared.

Depending on the heating value of the gas, the addition of fuel gas for flaring may be necessary.

According to API STD 537 and flare manufacturers’ recommendations, below 300 BTU/SCF a higher number of pilots, or more intense heat release pilots in comparison to standard flares, are required. The minimum

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lower heating value (LHV) for flaring is 150 BTU/SCF. In most cases, membranes permeate gas has a LHV above 150 BTU/SCF.

Use in fuel gas system:

Due to its high methane content, membranes permeate gas may be used as low heating value fuel

gas. This greatly benefits this alternative, as will be shown in the following sections. In some instances, burners or combustion systems specially adapted to handle this gas will be required. In order to reach the supply pressure of some fuel gas systems, the permeate pressure must be increased (reducing the efficiency of the membranes), although compressing permeate gas may be more convenient, specially for its use in turbines.

Injection:

Even though many countries of South America have no legislation prohibiting venting CO2 to the

atmosphere, more and more projects are considering acid gas injection (AGI) to reduce greenhouse effect gas emissions, in accordance with the clean development mechanism laid down in the Kyoto Protocol. The cost of CO2 injection units represents a considerable percentage of the total gas treatment cost, and may increase the required investments by up to 50% above the sweetening unit cost.

Almost all the technologies analyzed generate a CO2 effluent containing water and different amounts

of hydrocarbons. The corrosion of carbon steels by CO2 results from the formation of carbonic acid when CO2 dissolves in liquid water. In order to prevent it, water must be eliminated, its condensation must be avoided, or stainless steels must be used instead of carbon steels. If reinjecting the carbon dioxide is required, its corrosiveness at high pressures demands the use of stainless steel in great part of the injection system, and dehydrating the CO2 to be injected is sometimes essential (typically with a TEG unit).

Membrane pretreatment based on adsorption is the only technology that generates a dry acid gas

stream (Table 4). If CO2 injection is required, this has the advantage of avoiding the need for corrosion resistant alloys or acid gas dehydration for acid gas injection, which may lead to cost-reductions of up to 20% in the AGI unit.

Light hydrocarbons content in the acid gas also has a considerable impact on acid gas injection

costs. Light hydrocarbons reduce the density of a CO2 stream, and, therefore, imply higher pressures in the discharge of injection compressors, and, eventually, more compression stages. Moreover, for the same carbon dioxide removal, the injection flow rate resulting from a membrane unit will be higher than that from an amine unit, due to the permeation of hydrocarbons (HC) together with CO2. The following table shows a comparison derived from a recent study. Note the two-fold increase in power for case 3 in comparison to case 1.

Table 6 – Impact of sweetening on acid gas injection unit

CO2 HC

1) Amines 99,7 0,3 1,00 1,00 130 5 1,00

2)2 stage

membranes80 20 0,87 1,25 145 5 1,33

3)1 stage

membranes55 45 0,72 1,82 165 6 1,94

Case

Acid gas composition (% mol) Injection

pressure

(bar)

Injection power

relative to case 1

Flow rate relative

to case 1

Density relative

to case 1

Number of

compression

stages required

In the case of amine units, acid gas is obtained at a pressure slightly above atmospheric (10 psig).

The limit is determined by the maximum temperature at the bottom of the regeneration column, in order to prevent amine decomposition. In the context of projects providing for acid gas injection, it is beneficial to regenerate the amine at the highest possible pressure.

An advantage of membrane units is that permeate gas may be provided at a higher pressure (at the

expense of a somewhat larger area) and the number of acid gas compression stages may be reduced. But this does not usually compensate for the increase in flow rate and compression discharge pressure if compared to amines. The requirement of reinjecting acid gas is detrimental to the membranes in comparison to other treatment alternatives.

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Location of facilities and supervision requirements The simplicity of the treatment with non-regenerative scavengers (for very low CO2 removals) and

membranes (for higher CO2 removals) makes these processes very attractive for remote facilities which require a minimum level of supervision. This is specially true in the case of one-stage membrane units with simple pretreatment (heating), where no recycle compression is required.

Economies of scale

The “size” of the facility may tip the balance of the decision in favor of certain technologies. For

example, in the case of very low quantities of inlet CO2 or low flow rates of gas to be treated, non-regenerative processes present clear advantages due to their low investment cost. Nevertheless, this technology abruptly loses appeal with the increase of the flow rate to be treated or the CO2 content of the inlet gas owing to the high operating cost, that is to say, the cost of the scavenger used. The NPV (net present value) of this alternative is practically proportional to the treated flow rate. Because of their modular nature, membranes have a similar cost characteristic in relation to the flow rate, but, in this case, proportionality results from a linear increase in investment cost in relation to the flow rate. On the other hand, several technologies show an exponential relationship between cost and flow rate, typically “Capex = A x (Flow Rate)^B”, where B≈0.6-0.7 for the process industry. These technologies surpass the foregoing for high flow rates, as, in the event of a flow rate increase of 100%, their cost will increase only by 60% whereas membranes will record a cost increase of 100%. Accordingly, in the case of low flow rates, membranes benefit from the same behavior. This effect of economies of scale explains, in part, the reason why certain technologies are more appealing for low flow rates. For example, the following figure shows this effect for a particular case study, in which high CO2 content gas had to be sweetened.

Figure 4 – Economies of scale

FLOWRATE SENSITIVITIES

0

10

20

30

40

50

60

0.25 0.75 1.25 1.75 2.25

FLOWRATE [MMSCMD]

CA

PE

X [

MM

US

D]

Amines Membranes

Contaminants in inlet gas Some processes are highly sensitive to the composition of inlet gas. In the case of membranes,

heavy hydrocarbons may irreversibly damage them and must be removed during pretreatment. A proper pretreatment design is of key importance in order to handle variations in the content of heavy hydrocarbons. In the case of pretreatment based on physical adsorption, in the event of an increase in the heavy hydrocarbon content of the inlet gas, the system may be adjusted by reducing the time of the adsorption – regeneration cycles.

The presence of H2S is an important point to consider, as the content thereof in sales gas is one of

the most difficult specifications to comply with. While amine units easily remove large amounts of H2S, meeting very low specifications, membrane processes limitedly remove hydrogen sulfide, as its permeation capacity is similar to that of CO2. Therefore, both gases will permeate with similar ratios through membranes,

12

obtaining concentration removal ratios of the same magnitude. In this way, a membrane system designed to reduce CO2 content by 50% will remove approximately 50% of the inlet H2S, regardless of its concentration.

b. Environmental conditions

Energy cost

The energy cost is an extremely relevant parameter in the decision-making process. In particular, the

Latin American context is completely heterogeneous with regard to the price of gas agreed upon in the different regions of the continent. Broadly speaking, the heterogeneity is so that the price of gas ranges from 1 to 5 USD/MMBTU. Consequently, it is worth analyzing the impact of energy cost on the selection of the sweetening process.

The answer calls for a previous analysis, since not only must the energy consumption of the

sweetening unit be analyzed, but also the hydrocarbon losses in the CO2 rich stream to be disposed of, as both factors bring about a reduction in the flow rate of sales gas. Nonetheless, where the heating value of the CO2 rich stream is above a minimum, it may be used as fuel gas. In this case, hydrocarbon losses do not entail "losses" in sales gas themselves, as the use of that low-heating-value gas reduces the consumption of fuel gas derived from sales gas. Therefore, we will not record the heat content of "reusable" residual streams as cost, but we will record that of "non-reusable" residual streams.

The following figure shows the results obtained in a recent case study developed by Tecna for a 5

MMSMCD plant treating high pressure inlet gas with 15% CO2. In accordance with different gas price scenarios, the figure provides a graphic representation of the net present value (NPV) for different alternatives, composed of three terms:

1. CAPEX: cost of equipment multiplied by an installation factor. 2. OPEX: operating costs, such as energy consumption, labor and other supplies throughout 15

years of production. 3. Losses: non-reusable hydrocarbons, such as fuel gas, disposed of together with the CO2 removed

during the period of 15 years.

Figure 5 – Impact of energy cost

ENERGY PRICE vs TOTAL COST - SENSITIVITY

0

20

40

60

80

100

120

140

160

0.5 1.5 2.5 3.5GAS PRICE [ U$D / MMBTU ]

TO

TA

L C

OS

T N

PV

[ M

M U

$D

]

NPV AMINE UNIT NPV MEMBRANE UNIT NPV MEMBRANE UNIT - PERMEATE REUSE

NPV 2ST MEMBRANE UNIT NPV HYBRID UNIT - PERMEATE REUSE NPV HYBRID UNIT

On the basis of the figure, it may be observed that, within the framework of the study, the

membranes turned out to be attractive for gas prices lower than 1 USD/MMBTU, but this technology ceased to be competitive for higher energy costs, due to the incidence of high hydrocarbon losses (in the order of 15% of the heat content of inlet gas) on the NPV. However, in the event of reuse of the permeate as fuel gas, membranes presented significant advantages over its competitors. Nevertheless, it is worth highlighting that this case contemplates a complete reuse of the permeate stream, and that, in many cases, specially where the gas flow rate to be treated is considerable, the heat content of the permeate may exceed fuel gas

13

requirements, as a consequence of which such excess must be disposed of and recorded as a hydrocarbon loss. Moreover, fuel gas facilities must be prepared to handle low-heating-value permeate. This alternative may not be aligned with the company’s environmental policy if it is a standard practice to reinject CO2, as, in fact, the CO2 removed will be vented to the atmosphere together with combustion exhaust gases.

A similar analysis may be applied to the hybrid case, composed of a membrane unit placed

upstream of an amine unit. The membranes carry out the “bulk" removal of carbon dioxide, while the amine unit "polishes" the gas, meeting the outlet specification. The rationale of this scheme is to exploit the advantages inherent in each process; membranes are not economically suitable for the purpose of obtaining low CO2 outlet content with high inlet concentrations, as the CO2 removal ratio and the hydrocarbon losses are high in this case, whereas the chemical nature of the absorption of CO2 in amines makes it less dependent on partial pressure, allowing deep removals. In the case under analysis, the hybrid system was competitive only considering the reuse of membrane permeate as fuel gas, in order to meet the energy requirements of amine regeneration. The full exploitation of the symbiosis between both technologies occurs by fixing the outlet specification for the membrane unit so that the heat content of the permeate is lower than or similar to the one required for amine regeneration; in this way, no hydrocarbon losses per se were generated. Again, this alternative results in the venting of the CO2 removed in the membrane unit.

In those cases in which the company's environmental policy requires the reinjection of CO2 or there

is no destination for all the permeate stream to be used as fuel gas, the amine alternative turned out to be the most convenient for the usual gas prices in our continent, followed by the 2-stage membrane process. The latter was prejudiced by its higher hydrocarbon losses (3% of the heating value of inlet gas), although the difference with the amine alternative is in the range of uncertainty of the estimate.

Preferences of the company

Another essential parameter is the previous experience of the company and its preferences

regarding sweetening technology. There is certain inertia to change within each company; therefore, the technology having most successful experience has more possibilities than new technologies.

6 Flexibility over specification changes

Let us analyze the case of specification changes along plant operation lifecycle. For example,

Venezuelan law provides for a gradual reduction in the specification of CO2 in sales gas, as shown in Table 3, requiring the future expansion of the CO2 removal capacity. In another hand, a similar challenge is faced when considering future increases in the inlet CO2 content. In this context, let us analyze the flexibility of the alternatives to achieve these objectives in the most efficient manner. The analysis will focus on the study of solvent and, specially, amine processes, and membranes, together with a combination of both.

The size of an amine unit depends directly on the absolute amount of CO2 removed (in kg/h). This

means that, for an inlet CO2 content of 6%, the removal of CO2 to reach an outlet of 2% approximately doubles the removal necessary to reach 4%. Consequently, the amine circulation rate and the size of the regeneration section will increase in the same proportion (100%, possibly requiring the addition of a regeneration train identical to the original in parallel). If we analyze the same case, but for an inlet content of 10%, the specification change mentioned hereinabove requires a circulation rate increase of only 30%, which could be absorbed by a suitable overdesign of the unit, without having to add parallel trains.

Therefore, even though the technology is attractive from the viewpoint of operational reliability, it is

also true that it has little flexibility for the purpose of expanding the CO2 removal capacity, specially, for “low” inlet concentrations (< 8% approximately). The design of these units should consider extra capacity to face the greater removals required by future and more restrictive specifications.

On the other hand, the size of a membrane unit depends directly on the CO2 removal ratio. Due to

the modular nature of this technology, it is relatively easy to install additional membrane area to reduce the outlet CO2 content, as a result of which the process has a good flexibility for expansions, in spite of presenting some economic disadvantages with respect to its competitors: it should be borne in mind that hydrocarbon losses also increase with the additional membrane area.

What is then the best proposal for specification changes? Undoubtedly, the answer will arise from a

case-by-case analysis. Nevertheless, there is a process which presents remarkable advantages for the purpose of the changes in the CO2 specification. It is the hybrid system of membranes and amines, which allow the exploitation of the specific advantages of each of these processes, specially in those cases in which it is possible to reuse the membrane permeate as fuel gas for the amine unit. The alternative may

14

consist, for instance, in installing an amine unit at a first stage, and installing the membrane unit at a second stage, when the change of specification is required. The most important decision variable is the outlet CO2 content of the membrane unit, and, therefore, the relative size of both units. In this case, it is recommended that the amine unit be sized according to the most demanding of the following cases:

- Optimum concentration of CO2 at membrane unit outlet: for the purpose of the analysis, the “final situation”, that is to say, the removal of CO2 required in 2013, must be considered. The optimum concentration is that in which permeate gas from the membrane unit is completely used as fuel gas.

- Size required by the amine unit in order to meet the specifications prior to the installation of the membrane unit.

This sizing criterion is based on the fact that, as has been previously explained, the hybrid system

loses competitiveness where the permeate exceeds the fuel gas requirements, and it is necessary to burn or dispose of the hydrocarbons of the permeate. Due to the easy installation of membranes, the expansion of the carbon dioxide removal capacity is relatively easily developed, both for lower outlet CO2 specifications required and for increases in the inlet gas CO2 concentration. This scheme allows phasing investments in two stages, instead of installing the entire capacity from the outset.

Another viable alternative could consider the installation of membranes, at a first stage, and the later

installation of an amine unit, where so required. In this case, the lowest CAPEX during the first stage may exceed the hydrocarbon losses derived from the operation of the membrane unit.

7 Case study

There follows a case study of selection of sweetening technologies for a significant flow rate (>3

MMSCMD) of lean gas with 15% CO2, which must be treated to meet a CO2 specification of 2%. Given the flow rate of gas to be treated and the amount of CO2 to be removed, the use of non-

regenerative scavengers or physical adsorption was discarded from the outset. Moreover, based on the experience of the operating company and the general experience in the region, among the solvent absorption processes, the amine process was selected. The alternatives studied are the following:

- Removal with amines (Amines) - Removal with 1 stage membranes (Membranes 1 st.) - Removal with 2 stage membranes (Membranes 2 st.) - Hybrid system: Removal with 1 stage membranes, and, then, with amines (Hybrid) Gas is available at approximately 40 barg and the delivery pressure required is higher (80 barg),

therefore, we analyzed the location of each of the treatment alternatives mentioned: upstream and downstream of the compression unit. In whole, 8 cases were defined:

Table 7 – Analyzed alternatives

Amines Amines HP Amines LP

Membranes 1 stage Membranes 1 st. HP Membranes 1 st. LP

Membranes 2 stages Membranes 2 st. HP Membranes 2 st. LP

Hybrid (membr. 1 st. + amines) Hybrid HP Hybrid LP

High pressure Low pressure Conditions

Process

Other conditions for the purpose of the study: - The study included the comparison of capital expenditures (CAPEX, +/- 30% estimate) and

operational expenditures (OPEX) during a period of 15 years, updated to their present value. - In the case of operational expenditures, the replacement of membrane elements and solvent

(amine) make up were taken into account. - In all cases, the study considered a constant flow rate of gas to be treated, and penalized the

reduction in flow rate of sales gas with the value of hydrocarbon losses (HC Losses) in such cases as may be applicable.

- A sales value for natural gas of 2 USD/MMBTU was adopted. - Acid gas needed to be reinjected in all cases, due to the environmental policy of the operating

company.

15

- For the alternatives of amine treatment and hybrid system, the additional cost of a gas dehydration unit with TEG was considered, in order to meet the sales gas specification.

- The reduction in flow rate to be compressed was taken into account in those cases where the sweetening unit was located upstream of the compression unit

The following figure shows the net present value (NPV) of the alternatives considered. The case of

amine treatment at high pressure is taken as the basis (100% net present value) for the comparison.

Figure 6 – Net present value of cases analyzed

Net Present Value - Processing Alternatives

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

110%

120%

130%

140%

150%

160%

170%

180%

190%

Amines

HP

M embranes 1 st.

HP

M embranes 2 st.

HP

Hybrid

HP

Amines

LP

M embranes 1 st.

LP

M embranes 2 st.

LP

Hybrid

LP

CAPEX OPEX HC Losses

Some conclusions derived from the foregoing figure: - In all cases of membrane treatment, it is beneficial to locate the compression upstream of the

sweetening unit. - In this particular case, amine treatment before compression is more convenient than after

compression. - Under the conditions of this study, two-stage membrane processes have a present value

comparable to amine sweetening processes, and are later followed by the hybrid scheme and the one-stage membrane treatment (prejudiced by the high CO2 removal ratio and the high flow rates processed).

The following figures show hydrocarbon losses and utility consumptions for the cases under

analysis:

16

Figure 7 – Hydrocarbon losses

Hydrocarbon Losses

0

5

10

15

20

25

Amines

HP

M embranes 1 st.

HP

M embranes 2 st.

HP

Hybrid

HP

Amines

LP

M embranes 1 st.

LP

M embranes 2 st.

LP

Hybrid

LP

% i

nle

t g

as h

eati

ng

valu

e

Figure 8 – Fuel gas consumption

Fuel gas consumption

0%

1%

2%

3%

4%

5%

6%

7%

8%

9%

10%

Amines

HP

M embranes 1 st.

HP

M embranes 2 st.

HP

Hybrid

HP

Amines

LP

M embranes 1 st.

LP

M embranes 2 st.

LP

Hybrid

LP

% t

reate

d g

as

Membranes pre-treatment Amines regeneration LP to HP compression

Acid gas compression Membrane recycle compression Electric power generation

It is worth highlighting that the possibility of using permeate gas as fuel for one-stage membranes

was discarded, as it implies a remarkable increase in CO2 emissions, and there was no demand for fuel gas which allowed the total use thereof. Even considering the reduction in flow rate of sales gas, these alternatives were very convenient from an economic viewpoint. The following figure shows a net present value comparison of amine treatment over one-stage membranes considering the total reuse of the permeate as fuel gas. The amine treatment does not comprise the reinjection of acid gas, but considers its venting to the atmosphere, in order to compare the alternatives under identical circumstances.

17

Figure 9 – Reuse of permeate as fuel gas vs. Amines LP

Net Present Value - Processing Alternatives

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

110%

120%

M embranes 1 st.

HP

Permeate as FG

Amines

LP

M embranes 1 st.

LP

Permeate as FG

CAPEX OPEX

It can be observed how the application of different constraints for the disposal of acid gas reverts the

results of the analysis, turning membranes into a more convenient alternative. The permeate available from these one-stage membranes alternatives is 15 to 20% of the heating value of the inlet gas. For high feed gas flow rates, the excess of low BTU fuel gas is significant and its application is attractive, for example, for electric power generation (which may not be an option in remote locations).

8 Conclusions and lessons learned

The selection of sweetening technologies is a complex process which calls for the analysis of the

interaction of several agents, such as factors pertaining to the external environment, the internal environment and other gas processing units. Some of the conclusions reached are the following:

• Preselect potential alternatives – several technologies are economically unviable for certain conditions.

• Consider the integration with the rest of the processing facilities – a broad view of the project is required, which contemplates processing units located upstream and downstream of the sweetening unit.

• First, choose the technology, and, then, optimize it – for those technologies which allow alternative processing schemes, it is recommended to analyze only the basic scheme during the selection process.

• Speed up and facilitate the selection process - a consultant having proven experience in CO2 removal technologies may speed up the process and facilitate arriving at an optimum solution. The consulting company may contribute a holistic approach, analyzing the project as a whole.

9 References

[1] Gas Conditioning and Processing Volume 4, Maddox & Morgan, 4th edition.

[2] Engineering Data Book, Gas Processors Suppliers Association, 12th edition.

[3] Oilfield Processing of Petroleum, Volume 1: Natural Gas, Thomas & Manning. [4] “Recent Developments in CO2 Removal Membrane Technology”, David Dortmundt, Kishore Doshi, UOP

webpage. [5] “Hybrid Systems: Combining Technologies Leads to More Efficient Gas Conditioning”, William Echt,

Laurence Reid Gas Conditioning Conference, 2002.