H2S scavenger loại bỏ H2S

H2s treatment in oil and gas field H2S TREATMENT IN OIL AND GAS FIELD REV 01 BONY BUDIMAN 2021 https www linkedin cominbony budiman 39886031 COMMON QUESTIONS • What is H2S ? • Why H2S become a problem? • How to monitor and control ? • What is H2S Scavenger, hot it works ? • Field cases Courtesy picture https www google comurl?sa=iurl=https%3A%2F%2Fwww shutterstock com%2Fsearch%2Fh2spsig=AOvVaw3xkowshW9vnJFq8w39F2 Dlust=1637734120718000source=imagescd=vfeved=0CAsQjRxqFwoTCKjrzJrpr.

H 2 S TREATMENT IN OIL AND GAS FIELD REV.01

BONY BUDIMAN

2021

https://www.linkedin.com/in/bony-budiman-39886031/

COMMON QUESTIONS

• What is H2S ?

• Why H2S become a problem?

• How to monitor and control ?

• What is H2S Scavenger, hot it works ?

• Field cases !

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• Sharing some field cases

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quantities, they must be removed from a natural gas well stream.

• H2S could be present at gas phase, hydrocarbon phase and also in water phase as well

SOURCES OF H 2 S

• H2S is formed during the anaerobic decomposition of organic materials.

• This anaerobic process occurred during the formation of oil and gas millions of years ago This accounts for the small amount of H2S and other Sulfur compounds –typically one or two per cent –found in many crude oil and natural gas reservoirs around the world.

• H2S is also produced by chemical reactions within some sedimentary rocks At temperatures above 140 o C, the calcium sulphate (CaSO4) in gypsumreacts with hydrocarbons to produce H2S and compounds such as calcium carbonate (CaCO3).

CHARACTERISTIC OF H 2 S

• Has a structure similar to that of water But

H2S is not nearly as polar as H2O

• Colorless Gas

• Density = 1.393 g/L at 25 oC and 1 atm.This

is 18% greater than that of air

• Rotten Egg Odor

• Detectable at >10 ppb

• LC50 = 713 ppm

• Weak Acid

LIMITATION OF H 2 S CONTENT

• Most pipeline specifications limit H2S content to 0.25 gr per 100 cu ft of gas

• The maximum concentration of H2S in water is 400 ppm

• Wells with only 10 ppm or above can be labeled sour

• Partial pressures of only 0.05 H2S are considered

corrosive

CORROSION AND PLUGGING

• H2S is "acid" gases as it tends to lower the pH of water (make it more acid) when they dissolve in water They partially ionize when they dissolve and the degree of ionization is reflected by the pH (3)

H2S+H2O  H + + HS - + H2S

• The ion H + then react with iron to create corrosion product FeS

Corrosion caused by H2S dissolved in water is called "sour" corrosion and is usually pitting in nature

HEALTH EFFECT TO HUMAN (4)

Concentration

(ppm)

Symptoms/Effects

0.01-1.5 Odor threshold (when rotten egg smell is first noticeable to some)

2-5 Prolonged exposure may cause nausea, tearing of the eyes, headaches or loss of

sleep

20 Possible fatigue, loss of appetite, headache, irritability, poor memory, dizziness 50-100 May cause digestive upset and loss of appetite.

100 Throat irritation after 1 hour Death may occur after 48 hours.

500-700 Staggering, collapse in 5 minutes Death after 30-60 minutes.

700-1000 Death within minutes.

1000-2000 Nearly instant death

CATALYST POISON (5)

• Precious metal catalysts such as Platinum Group Metal (PGM) are crucial to the operation and economics of many hydrocarbon processing applications

• Feedstock poisons impair the performance of a catalyst by reducing its activity, either via

competitive adsorption onto active sites, or by alloy formation with site.

• Sulfur (S) species (H2S, RSH, RSSR…) are poisons for all catalytic processes employing

reduced metals as the primary active phase

• PGM catalyst(s) react readily with H2S to form sulfides

• Sulfur may cause significant deactivation even at very low concentrations, due to the

formation of strong metal-S bonds Sulfur chemisorbs onto and reacts with the active catalyst sites, preventing reactant access Furthermore, the stable metal-adsorbate bonds can lead to non-selective side reactions, which modify the surface chemistry

PRINCIPLES OF MONITORING

• Good sampling critical for good results

• Common mistakes

• Test influences

• agitation, temperature, vapor/liquid ratio

• coating of electrodes, interferences

MONITORING METHOD

• H2S may dissolved in water, in oil or mixture with others gasses

• To monitor H2S content we may refer to procedure :

MONITORING MAIN EQUIPMENT

There are some equipment that could be used to analysis H2S in gas or liquid :

• Gas Detection Tubes

• Gas Chromatography

• Electrochemical Analyzer

GAS DETECTOR TUBE

quantitative

• The Gas Detector Tube System consists of apump and glass detector tubes The tubes arefilled with an absorbent material and chemicalreagent which, when in the presence of the targetgas, produces a colour stain along the tube

• A calibration scale is printed on the tube toenable the user to easily match the length of thecolour stain to the concentration of the gaspresent

Courtesy picture : https://www.youtube.com/watch?v=d3FY992iPPM

GAS CHROMATOGRAPHY

• The test method may refer to ASTM D7621, ASTM D5623 and or ASTM D5504

• Sample could be gas or liquid

• The GC method could breakdown the sulphur compound : H2S, mercaptan and carbonyl sulfide

• This method is sensitive and quantitative but require competent personnel and high cost apparatus

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ELECTROCHEMICAL ANALYZER

• Gases emitted from the test vessel are passed through a cooled sorbent cartridge before they are measured by the electrochemical sensor

• The test method refer to IP 570; ASTM D7621; ISO 8217

• This used to measure the total H2S content of fuel oils, such as marine residual fuels, distillates and petroleum blend stocks

• The Analyser can measure H2S concentrations from 0

to 250 mg/kg (ppm) in the liquid phase

Courtesy Picture : https://www.stanhope-seta.co.uk/product/h2s-analyser/

H 2 S PARTITIONING

• At some case we may only able to measure H2S level in liquid phase but we need to

estimate the concentration in vapor phase From some experiences, the correlation is as below :

• 1 ppm in liquid can equate to > 50 ppm in vapor space

• 100 ppm in liquid can equate to 20,000 ppm in vapor space

• Please note carefully, that the correlation will depends on temperature and

pressure, viscosity, agitation and crude oil properties

CONTROL(1)

H 2 S SCAVENGER (1)

• Recovered Scavenger

These solutions undergo reversible reactions with acid gases

and can be regenerated in a cyclic process to remove

rather large amounts of sulfur Some of chemicals are :

o Monoethanolamine (MEA)

o Diethanolamine (DEA)

o N-methyldiethanolamine (MDEA)

o Diglycolamine (DGA)

• Non recovered Scavenger

This type effective and efficient to remove H2S at relatively low concentration, such as below 1% since the used chemicals will be discharged with the treated fluid Some of chemicals are :

IDEAL H 2 S SCAVENGER (2)

• Provide complete, efficient and reliable scavenging of harmful sulphide species

• Produce reaction products that are inert

• Be efficient under all likely condition of temperature, pressure, pH and in the pressure of

others chemicals additives

• Be non corrosive

• Be non hazardous to the health and safety of personnel and environmental friendly

• Be readily available and economical to use

Unfortunately, the ideal H 2 S Scavenger is a mhyth We shall find the most compromized one !!!!

NON RECOVERED SCAVENGER (1)

• This type of scavenger usually react with H2S to form sulphur salt Then the sulphur salt

disposed along the produced water.

• Water-based H2S scavengers normally require that the gas is water saturated to prevent solid reaction products

• Nonregenerative H2S scavengers that have been investigated can be divided into the following categories89:

SOLID SCAVENGERS (1)

• Solid scavengers cannot be injected and are therefore only useful in treating sour gas in

process facilities

• Solid scavengers are generally zinc- or iron-based materials

• A bed of zinc oxide, ZnO, was used successfully to remove H2S from the produced gas for one North Sea operator

• Improved solid iron oxide scavengers used in the industry today form innocuous iron pyrite (FeS2) as the reaction product The catalyst can be impregnated on an inert ceramic material, solving the pyrophoricity problem of the earlier iron-sponge type scavengers.

OXIDIZING CHEMICALS (1)

• Some chemicals could oxidize the H2S Some of them are : NaClO2, NaBrO3,

NaNO2peroxides, persulfates, thiourea dioxides, percarbonates, perborates,

diethylhydroxylamines, peracetic acids, and superoxides

• The reaction of these oxidizing agents, except the persalts, with H2S is complicated, but elemental sulfur is usually one of the products

H2S(g) + H2O2(aq)  SO4

2-(aq) + 4H2O(l) + 2H+

(aq)

• H2S must be present as ions (HS− or S2−) to react quickly and that the pH of the

peroxide product must be high

• High pH usually destabilizes hydrogen peroxide especially in the presence of

contaminants such as trace transition metals

ALDEHYDES (1)

• Aldehydes react with H2S to form various sulfur products

• Typical aldehydes that have been used include formaldehyde, glutaraldehyde, acrolein, and glyoxal

• Aldehydes are cost effective scavenger They also work as biocide

• Formaldehyde is more than 2 times better than triazine as

an H2S scavenger but the reaction kinetics do not favor this reaction therefore

• Formaldehyde will offer little immediate benefitMost of the products from reaction with H2S are poorly soluble in

water and the chemicals are toxic or even carcinogenic

Reaction of formaldehyde with H2S.

at excessive of salt will create inorganic deposit

• Low-toxicity characteristics and are usually biodegradable

• Cost effective treatment

TRIAZINE (2) (1)

• Triazines react faster with H2S than aldehydes, and also react with the HS− ion

• Triazines have low-toxicity characteristics and are usually biodegradable, but can contain small amounts of free formaldehyde, which is a suspected carcinogen

• The original triazine can be regenerated by treatment with hot aqueous base, but this is not normally economic in practice

• Triazine scavengers usually decompose at temperatures of 120°C–150°C

• The challenge if triazine is how to increase solubility of the sulphide salt as reaction

product with H2S Some producer blend triazine with glycol or add a scale inhibitor to get this purpose

MBO (6,7)

• 3,3'-methylenebis (5-methyloxazolidine) , MBO is a reaction product

of paraformaldehyde and 2-hydroxypropylamin

• MBO has been used in the oil industry for decades as a biocide

• Recently, its use as a potential H2S scavenger has gained interest by several suppliers and operators

• It exhibits a somewhat different reaction pattern with H2S compared

to triazines, through the release of formaldehyde

• Some user inform that the application of MBO is 1/3 compare to MMA-MEA triazine

Desulphurization by the use of H 2 S scavenger

 Process diagram for H2S removal by scavenger (see

downstream the injection point

 The scavenger is water-soluble and the main fraction

of the scavenger is discharged to the sea

WORKING MECHANISM

• Reaction of triazine with H2S forms water soluble reaction products, there are no solids to clog up systems

• Reaction products thermally stable so the H2S is permanently removed

• Triazines can be used in flowline or towers

• Triazine has an excellent cold handling properties and can be stored outdoors

N

N N

NH N

N N

CONCERNS WITH TRIAZINE

• Triazine reacts with H2S to form dithiazine

• Dithiazine is water soluble but has a saturation limit of 37% This means it can crystallize

or solidify at concentrations above 37% which may lead to plugging in the system

• Once these crystals have formed they may be no longer water soluble Dithiazine is

classed as a non-hazardous material

• Triazine is alkaline solution, has high pH.At excessive treatment, the pH of fluid will

increase and the scaling tendency will be more likelihood

H 2 S SCAVENGER TEST METHOD (SIMPLE)

• Inject H2S Scavenger at specified dosage to the crude oil

• Mix well, heated if necessary

• Measure the vapour using detection tube

• Compare to blank

MIX

H2S

Scavenger

H 2 S SCAVENGER TEST METHOD (COMPLEX)

• A test is performed by first filling the glass chambers with N2 gas containing 1000 ppm H2S

• Once a stable reading has been achieved on the

H2S sensor, the pump is turned on and the H2S scavenger solution begins to spray

• After a certain period of time, the reading on the H2S sensor reaches a new stable value and the test is stopped

Curtesy picture : https://osf.io/wb28v/download/

TREATMENT METHOD

• H2S Scavenger mechanism is refer to Stochiometric Law  simple mean : if

H2S content increase twice then the we need 2x dosage of H2S scavenger

• Some treatment method that usually used are :

- One way injection

- Circulating injection

ONE WAY INJECTION

• Injection of scavenger upstream the let down station, and removal of the scavenger in the filter separator

• The injection point for the scavenger is upstream the choke valve at the letdown station, to give a good mixing of the scavenger and the gas The pressure drop at the choke valve will create small droplets of the scavenger, and this will give a fast mass transfer of H2S into the droplets which in turn gives a high efficiency of the scavenger

CIRCULATING INJECTION

• In this process the spent scavenger separated in the filter separator will

contain partly unreacted scavenger and partly

scavenger reacted with

H2S

• The spent scavenger will

be mixed with fresh scavenger and re-injected into the pipeline.

FACTOR AFFECTING PERFORMANCE OF H 2 S SCAVENGER

• Gas flow rate, which affects mixing

• Retention time to achieve optimum reaction time

• Pressure, which affects the H2S partial pressure

• Compatibility with the fluids and other production chemicals

• Active content of H2S Scavenger

• pH

• Temperature

• Contact time / retention time

• Contact style

pH AND TEMPERATURE EFFECT (TRIAZINE)

for H2S scavenger to react 50% from initial weight

faster For example at pH 6.0 The half

is near 1 second Means the reaction at

temperature and more acid (lower pH)

of treated fluid

RETENTION TIME

• Retention time or contact time is the amount of time required for the chemical to be in contact with the sour production for effective treatment

• This includes the time for the H2S to diffuse, dissolve, find and react with the triazine The H2S must have enough time to fully react with the product

• The minimum contact time for gas is 15-20 seconds (8) ; minutes for water and till hours for oil

Courtesy Picture :

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FIELD APPLICATION

2 Charlie Oil Plant

3 Tiger Gas Plant

4 H2S in asphalt storage

5 Non Triazine H2S Scavenger

1 ROMEO GAS PLANT

• Romeo Gas Plant is a plant to collect gas from gas well and oil-gas separation

• Some equipment allowed by gas are leaking

• H2S content in Romeo Gas Plant is more than 200 ppm