21 25 H2S Removal From CO2 Vent Stream Amine - · PDF file... is a technology well known on...

XIX International Gas Convention AVPG 2010, May 24th - 26th Caracas, Venezuela

H2S REMOVAL FROM CO2 VENT STREAM OF AMINE PLANTS

Federico Patti and Francisco Sanchez Carelli – FLARGENT

ABSTRACT

In amines plants, venting CO2 into the atmosphere is a problem which demands

hard work during the design stage by making calculations so as to avoid

contamination of CO2 at floor level. But when the gas that is treated in the plant

contains significant amounts of H2S, it is vented to the atmosphere with the CO2.

In this case, it is difficult to avoid presence of H2S at floor level even raising the

height of the vent. Depending on the H2S ppm concentration on the vent, the

effect can be smell or as a simple odor of rotten eggs or as a serious threat to the

health of operators.

On the other hand, Sulfatreat, a non-hazardous, non regenerative, granular

product, is a technology well known on the removal of H2S from natural Gas flows

at low and medium pressure, prior injecting the gas into pipeline.

The purpose of this paper is to present the results of a technology analysis that

ended in the selection of Sulfatreat as the optimum process for the removal of H2S

from CO2 vent stream of amine plants. Since the process is already in operation,

this work not only examines the theoretical aspects that led to that conclusion, but

also is complemented by field measurements taken after the Star-Up.


CASE STUDY

The Natural Gas Industry has in carbon dioxide (CO2) one of the main obstacles,

since it causes serious problems in all treatment processes stages, transportation

and sales.

Thinking on Natural Gas as a fuel, high level of CO2 increases the inert content

reducing the gas heating value, which results on a lower sells price. Upstream end

users, in transport gas pipelines CO2 can also cause problems, since in

combination with water generates carbonic acid (H2CO3) which at high pressure,

as in any gas pipeline transportation, it is highly corrosive and can reduce the life

of carbon steel pipes. Because of this, it is common for Natural Gas market

regulators to limit the CO2 maximum allowable content so as to be sold in houses

and in industries. For example, in Argentina, the CO2 content in natural gas for

consumption and/or transportation is limited in 2%.

That is why there are different processes for removal of CO2 from Natural Gas in

order to achieve the allowable values by the regulations and laws. One of the most

common processes is the technology of amines, whose optimal range of use is

when the inlet flow contains up to 10% CO2 and is required 2% at output. Amines

are organic chemical compounds obtained from replacing from ammonia by alkyl

radicals one or more hydrogen atoms. In contact with hydrocarbon gas streams

that contain CO2, the amine has the ability to absorb the CO2 removing it away

from the gas. This contact between the gas with CO2 and the amine is produced

on mass transfer equipment, usually known as contactor column.

The amine rich in CO2 must then be regenerated, since the process is a closed

cycle. This means that the CO2 must be removed from the amine so this one can

be re-used. This is accomplished in other mass transfer equipment usually known


as regeneration column; the CO2 is desorbed from the amine at high temperatures

by means of heating.

The CO2 separated from the amine is usually vented to the atmosphere, for which

during the design of this type of facility is common to take precautions when

defining the vent height above ground level mainly it shall be avoided a high

content of CO2 in the air that plant operators breathe because it reduces the

partial pressure of oxygen in air. Dispersion analyses are reliable tools commonly

used in this stage.

In the graph below (taken from the GPSA manual) shows a diagram of a typical

amine plant process. The CO2 vent flow is referenced as "Acid Gas" at the top

right.

When the gas to be treated contains high levels of H2S (sulfide hydrogen), in

addition to CO2 it is normal that the H2S & the CO2 go together in the


atmospheric vent stream. The reaction of the amine with the H2S is similar to the

reaction with the CO2, so that in contact with the gas it will remove both

components equally. And in the regeneration will separate both (CO2 & H2S) from

the amine.

When the sulfur content in the inlet gas is low, the presence of H2S in the vent

stream can be smell just like a harmless odor of rotten eggs. But when the sulfur

input reaches higher levels, the level of H2S in the vent reaches values that would

seriously threaten plant operators’ health. Even at low concentrations, H2S acts as

an irritant to the eyes and respiratory tract. Moderate concentrations cause

headaches, dizziness, nausea and vomiting in that order. The greatest danger,

however, is from its acute effects. Massive dosage that is contact with high

concentrations (1000 ppm or more) can cause immediate loss of consciousness

(in 1-2 seconds) which is rapidly followed by respiratory failure and death (2-3

minutes). In Argentina, there is a legal framework take into consideration this and

set a maximum of 7.5 ppmv gaseous emissions from a vent at 30 meters height.

To depend not only on dispersion calculations in protecting human health, since

some time companies are discussing possible technologies to remove efficiently

and simply the H2S from CO2 vents in amines plant.

Although there are many technologies used for H2S removal from gas streams,

the basic conditions to be satisfied for the implementation in the application

described are restrictive, limiting the possible options. These conditions are as

follows:


a) Remove H2S converting it into a non-toxic waste

b) Be compatible with the venting gas composition (approximately 100% CO2

saturated with water)

c) Be applicable to very low pressure streams

d) Efficiently absorb variations and picks in the operation conditions.

The analysis of technology study made in at least two amine plants in Argentina

concluded that Sulfatreat, a non-hazardous, non regenerative, solid granular iron

oxide (FexOy) product is the alternative that meets the requirements described

above with the lowest economic impact.

The process of Sulfatreat consists in the chemical reaction between H2S from the

gas stream with the iron oxide; products obtained are iron sulfide (FeS2) (also

known as pyrite) and water vapor. The reaction is as follows:

The iron sulfide (Fe2S) which is the reaction product is neither toxic nor corrosive

or flammable. It is a non-reversible reaction and the product is a stable compound

which does not decompose, so that H2S is removed from the gas stream in an

irreversible way. As a consequence of this the product is not regenerative and

must be replaced when spent, usually between one and three years, disposing it

of as a solid spend waste. The spent product is non-hazardous, which can be

disposed of in landfills or on roads.

The model of flow within the Sulfatreat bed is "Plug-Flow". The following graph

illustrates a typical scheme of Sulfatreats reactors. The gas enters through the top

of the vessel, creating a reaction zone that is moving toward the bottom as the

Fex Oy + SH2 Fe2 S + H2O


product is being spent, and

leaves the reactor at the bottom

with a concentration of H2S which

is close to 0 ppmV during most of

the life of the product. This

feature gives the system the

ability to absorb instantaneous

concentration and/or flow

variations without special field

work or extraordinary investment

in the operating cost in terms of cost per kilogram of H2S removed.

The system can be composed of one

or more reactors (vessels) parallel or

lead-lag configurations, with simple

pipes and instrument installation as

illustrated in the graph on the left. The

reactors do not require special

internals beyond that ones that form

the bed support (The support of the

bed, a couple of meshes and a foam

filter). So this makes a robust system

that does not require special

maintenance.

The sizing and configuration of the system depend crucially on the amount of H2S

removed per day of operation and is affected mainly by two variables of operation:


a) Water saturation: The gas must be saturated with water in vapor state

b) Temperature: the kinetics of the reaction improved as the temperature is higher

Therefore; with high inlet temperatures are obtained smaller beds

The Sulfatreat reactors associated equipment is also very simple; its preference

against other alternatives is justified

as it is not so complex like other

H2S removal technologies. The

graph on the right illustrates a flow

diagram of a typical Sulfatreat

installation. Water injection is to

ensure the saturation of water

required and adding a heater rising the temperature of inlet gas to the system is an

alternative usually used.

Sulfatreat has developed different types of products based on the same reaction

and with different characteristics for each type of application. For example, there is

a special product with low pressure drop, others with higher or lower amount of

iron oxide per mass unit, others with incorporated catalysts that accelerate the

reaction rate when is required by the process conditions, etc. So the amount of

product required for the removal of H2S in an application it depends on the design

and the product that is chosen; but its generally between 8.5 and 11 kg SFT / kg

H2S.

This feature makes that Sulfatreat technology has a range of applicability which is

placed between liquids technology (which initial installation cost is zero but

operation costs are significantly higher) and other regenerative technologies

whose initial investment is high in contrast with its low cost per kilogram of H2S

removed.


The following

picture illustrates

these ranges of

applicability, with

the exception that

these limits are

empirical and

depends mainly on

market conditions.

This segment of

applicability has

meant that the

technology is widespread for sweetening natural gas, mainly in battery systems

installed in production prior to compression or entering dew point plants as the

reaction takes place in any pressure range.

In 2007 100 % of Argentinean Sulfatreat applications were operating according to

previous description, with a total processing flow in 16 different applications of

approximately 4,000,000 Sm3/d.

However, since 2005, with the Oil & Gas market having a growing tendency on

operational safety and focused attention on plants environmental impact,

industries began to analyze applications for removal of H2S from CO2 amine vent.

An Amine plant located inside an ethane, propane and butane Fractionation

Complex which is owned by an Argentinean company is the first of these

applications. It started years ago after a feasibility study and technology selection;

then was done the integration analysis to the existing amine plant ending with the


construction of the plant in the year 2007 and started operation in December of

that same year.

The proper settlement of design conditions for H2S removal plant was crucial to

the viability of the Project, mainly because of the wide dispersion on flows and

concentrations of the stream. These two variables display a high variability

between maximum and minimum values, which was a big challenge in defining the

design parameters to take. Originally the design flow for H2S removal system was

determined from 15.000 Sm3/d minimum up to 271.000 Sm3/d maximum, while

the H2S concentration was define from a minimum of 6 ppmv up to a maximum of

90 ppmv. However, when analyzing and reorder historical data of venting flow was

realized that there is a roughly linear function between the values of the flow and

the values of H2S concentration: if flow increases then the H2S concentration

decreases and vice versa. On the other hand pressure and temperature values

are quite stable because are controlled upstream by operating conditions of the

regeneration column of the amine plant.

At this point the technology advantage on the possibility of absorbing high level

flows and/or concentration without affecting the quality of the treated gas during

almost all of beds life time takes an important part. From an extensive analysis of

historical data using this feature, the final design conditions adopted were:

PARÁMETER Value

Gas Flow (Sm3/día) 230.000

Minimum Inlet Pressure (Kg/cm2g) 0,63

Minimum Inlet Temperature (ºC) 42

Maximum inlete H2S concentration

(ppmV) 33,5

% CO2 98

Water conten (% saturation) Saturated


For these conditions, the required installation for the H2S removal plant is: Two

reactors with the following characteristics:

PARAMETER Value

Number of Reactors 2

Internal Diameter (in) 160

S/S height (ft) 33

Sulfatreat Bed per vessel (lbs) 232.000

Approximate performance (Days) 1000

As an example, if the design conditions were specified in 271.000 Sm3/d @ 90

ppmv as how was initially thought, the minimum installation requirements would

have been the double of reactors with a resulting impact on the initial investment.

The following pictures, taken during Star-Up, show the two Sulfatreat reactors and

confirm the simplicity of the required installation for these type of applications.


The Star-Up of the application was performed in late December 2007. During the

first year operation the results were consistent with those predicted during

engineering stage of the Project. H2S levels were maintained without interruption

under the detectable level of the measurement instrument (under 0.2 ppmv)

During the second year operation a problem related to excessive Pressure Drop

appeared. Those problems were attributed to excessive water condensation

through the bed; forcing to insulate the vessels in order to minimize this effect.

Also channelizing appeared in the bed as a secondary effect from the

condensation that’s why the gas by-passed part of the bed generating the

mentioned pressure drop increase.


To correct this effect, during a new loading of the product, extreme precautions

were taken in order to generate homogeneous and evenly loading of the product

into the reactors (Following a rigorous loading procedure). This, in conjunction with

the insulation, corrected the effect of channelizing.

CONCLUSION

Sulfatreat, usually associated with sweetening in primary treatment facilities of gas

streams in the upstream segment, is a technology that can be effectively used to

remove H2S from CO2 vent stream coming from amine plant.

The plant application analyzed in this paper it’s a clear evidence of that

conclusion. The operating parameters obtained after starting operation confirm the

calculations made during conceptualization and basic engineering stages.

SulfaTreat has efficiently removed H2S coming from the regenerating column,

handling high levels of flow and concentration, reducing significantly the risks for

operators and residents of neighboring cities to the possible exposure to high

levels of Sulphidric Acid (H2S) in the air.

21 25 H2S Removal From CO2 Vent Stream Amine - · PDF file... is a technology well known on...

Documents

Transcript of 21 25 H2S Removal From CO2 Vent Stream Amine - · PDF file... is a technology well known on...