H2S: Where Did It Come From, Where Should It Go?americanbiogascouncil.org/webinars/FINAL Webinar Presentation.pdf · March 6th, 2015 11:30 am-1:00 PM ET H2S: Where Did It Come From,

March 6th , 2015 11:30 am-1:00 PM ET

H2S: Where Did It Come From, Where Should It Go?

Webinar on H2S Removal Technologies

Special Thanks

Quick Notes • Two Audio Options: Streaming Audio

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American Biogas Council: The Voice of the US Biogas Industry

The only U.S. organization representing the biogas and anaerobic digestion industry

Over 220 Organizations from the U.S., Germany, Italy, Canada, Sweden, Belgium and the UK

All Industry Sectors Represented:

project developers/owners

anaerobic digestion designers

equipment dealers

waste managers

waste water companies

farms

utilities

consultants and EPCs

financiers, accountants, lawyers and engineers

Non-profits, universities and government agencies

Join Us! www.AmericanBiogasCouncil.org OR [email protected] OR 202.640.6595

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mailto:[email protected]

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on Farm (Dairy AND Swine)

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U.S. Biogas Market – Current and Potential

Presenters

Moderator: Sean Mezei, President, Dekany Consulting

Eugenio Giraldo, Chief Technology Officer, Natural Systems Utilities

Tom Jones, VP of Business Development, MV Technologies

Tim Robison, President, Clean Methane Systems

Agenda 1. Introduction

- Sean Mezei, Dekany Consulting

3. H2S Formation with AD Systems

- Eugenio Giraldo, Natural Systems Utilities

4. H2S Removal Technologies – Selection Criteria and Pros/Cons of Main Technology Types

- Tom Jones, MV Technologies

5. H2S Removal Economics

- Tim Robinson, Clean Methane Systems

6. Audience Q&A

Moderator: Sean Mezei President, Dekany Consulting Director, Business Development Carbotech (part of the Viessmann Group) Co-Chair, ABC RNG Working Group

Today’s Presentations:

1. H2S Formation Science

2. H2S Removal Systems


4. Questions and Answers









6. Audience Q&A

Leader in Distributed Wastewater Systems

Hydrogen Sulfide in Anaerobic Digesters – An Introduction

Eugenio Giraldo, Ph.D. Chief Technology Officer

March 6, 2015

3/6/2015 Slide: 11

Contents

• Introduction • Sulfur Cycle

• Significance in AD

• Sulfate Reduction and Methanogenesis

• Sulfide effects • Toxicity

• Corrosion

• Odor

• Sulfur Chemistry and In-Digester Control • Acid Base

• Precipitation

• Stripping

• Oxidation

• SRB inhibition

3/6/2015 Slide: 12

Biogeochemical Sulfur Cycle

3/6/2015 Slide: 13

Sulfate Reduction and Methanogenesis

Organic Macromolecules

Monomers (Sugars, Aminoacids,

Long chain fatty Acids)

Fermentation Products ( Ethanol, Butyrate, Propionate)

H2 and CO2 Acetate

CH4 and CO2

Hydrolysis

Fermentation

Acetogenesis

Methanogenesis SO4

=

H2S

Sulfate Reduction

H2S

SO4=

Sulfate Reduction

SO4=

H2S

Sulfate Reduction

Sulfate Reduction:

• Reduces methane production

• Creates Hydrogen Sulfide instead

• SRB outcompete methanogens

3/6/2015 Slide: 14

Odorous Compounds In Organics Management

Compound Name

Recognition

Threshold

parts per

million Odor Description

Allyl mercaptan 0.0015 Disagreeable, garlic

Ammonia 37 Pungent, irritating

Amyl mercaptan ---- Unpleasant, putrid

Diisopropyl amine 0.38 Fishy

Dimethyl amine ---- Putrid, fishy

Ethyl amine 1.7 Ammonia like

Ethyl mercaptan 0.001 Decayed cabbage

Hydrogen sulfide 0.0047 Rotten eggs

Indole ---- Fecal, nauseating

Methyl amine ---- Putrid, fishy

Methyl mercaptan 0.001 Rotten cabbage

From Table 2.1, Odor Control in Wastewater Treatment Plants ,

1995, WEF & American Society of Civil Engineers

• Sulfur Based

– Hydrogen Sulfide

– Sulfur Volatile Organic

Compound -SVOC

• Mercaptans, MM

• Dimethyl Sulfide, DMS

• Dimethyl Disulfide, DMDS

• Nitrogen Based

– Ammonia

– Amines

3/6/2015 Slide: 15

Hydrogen Sulfide Toxicity and Exposure

• Regulated by OSHA and NIOSH

• 8 hour - Permissible Exposure

Limit (PEL-TWA = 10 ppm)

• PEL short term (PEL-STEL = 15

ppm)

• NIOSH: 300 ppm immediately

dangerous to life

http://enviro-x.com/catalog/product_info.php?cPath=30&products_id=38&osCsid=f5cd1fa11d414473b2b9afab7046202c

3/6/2015 Slide: 16

Hydrogen Sulfide Induced Corrosion

• Concrete Corrosion

– Sulfuric Acid reacts with concrete

– Formation of Gypsum

• Metal Corrosion – Pitting, stress cracking, embrittlement

– Rebars, Electric Equipment, pumps, valves

Concrete Corrosion Metal Corrosion

3/6/2015 Slide: 17

Sulfur Transformations in an Anaerobic Digester

SO4 =

H2S

S =

Metal e.g. Fe

HS-

MeS (solid)

H2S

Acid e.g. VFA

Organic Matter

So or SO4

=

O2

SVOC e.g.

DMS, MM

3/6/2015 Slide: 18

More H2S at low pH and low temperature

H2S = HS- + Acid e.g VFA HS- = H2S + Base e.g Mg(OH)2

3/6/2015 Slide: 19

pH adjustment for H2S control

• Works well. See graph on

the left

• Increases soluble sulfide

– Odors in effluent

– COD of effluent

• Need to check for:

– High pH

– Hydrogen Sulfide toxicity

McFarland and Jewell – 1989 – Water Research

3/6/2015 Slide: 20

Hydrogen Sulfide Toxicity is pH dependent

• Methanogens are

affected (See Graph on

the left)

– Type of reactor makes a

difference

– Industrial Wastewater

Reactors e.g. UASB are

more resilient than slurry

digesters (e.g. sludge)

– Slurry digester are affected

at concentration higher

than 200 mg/L dissolved

Sulfide

– UASB type show slight

inhibition at that level Koster et al., 1986, Water Research

3/6/2015 Slide: 21

Sequestering Sulfides with Metal Salts

• Metal Sulfides have low solubility e.g. Iron Sulfide

• Iron Salt addition works well e.g FeCl2 10-100 lb/ton TS

• Iron has a complex chemistry with multiple competing reactions – Iron Carbonate

– Iron Phosphate –Vivianite – “Blue Scale” (Location of addition)

3/6/2015 Slide: 22

Example of Iron Salt Addition

• 90% removal using 2 lb

iron per lb S-SO4

• Higher dosages reduce

dissolved sulfides

McFarland and Jewell – 1989 – Water Research

3/6/2015 Slide: 23

SCOV generation

• Important for Dewatering and Storage Odor Generation and control

• Reactive Proteins

• Sulfur containing aminoacids: – Methionine

– Cysteine

• Methanogens can use methylated sulfur compounds

WERF - 2007

Du and Parker – 2012– Water Research

3/6/2015 Slide: 24

Sulfide Oxidation – Chemical - Biological

• Reverse of sulfate

reduction

• Sulfide oxidation to

sulfate or elemental sulfur

• Can be induced in the

headspace

– Risk of explosive

conditions 5-15% methane

in air

– Problems with N2 and

Oxygen for CNG

3/6/2015 Slide: 25

Summary

• Sulfur compounds are intimately linked to Anaerobic Digestion. Key species are Hydrogen Sulfide, Sulfate, Elemental Sulfur and SVOCs

• Reduced sulfur compounds in biogas are associated to Odor, Toxicity and Corrosion

• There is a complex set of reactions, biological, chemical and physical that control emissions and impacts. Understanding of the fundamentals is the basis of effective control.

• There are numerous alternatives to address sulfur compounds problems in AD

Leader in Distributed Wastewater Systems

Thank you for your attention! [email protected]

March 6, 2015










6. Audience Q&A

H2S Management for Biogas

Presented By: Tom Jones

V.P. of Business Development

H2S Management Decision Process

Frame the Treatment Objective

Understand Available Options

Determine Which Options

Meet Your Objectives

Compare Total Cost of

Ownership

• It is important to understand clearly your primary objective in removing H2S from your biogas stream.• There are many ways to remove H2S from a gas stream. Fortunately (or not), only a handful really

apply to a typical biogas application.• Based on the end-use and site-specific conditions, determine which options will meet your objectives.• Once you have determined the technologies that suit your objectives, use a structured cost comparison

approach to evaluate available technologies and make your decision.

STEP 1: Frame the Treatment Objective

Typical Decision Drivers Include:

• General System Maintenance Cost Reduction – Engine or Direct Use• Engine/Process Equipment Warranty or Performance Limitations• Air Quality Control Limits on Emissions• Pipeline/CNG Processing Limitations

These clearly are not mutually exclusive goals, but the range of available technologies for H2S removal includes options that meet

some of these objectives “better” than others, or in some cases, not at all.

Pipeline/CNG

Specifications

Maintenance

Cost Reduction

Warranty/Performance

Limitations

Air Quality

Emissions Limits

Increasing Degree of Difficulty

STEP 1: Frame the Treatment Objective

The cost per pound of H2S removed is a critical metric so it is important to develop an understanding of the amount of H2S generated under certain “typical” biogas flow and concentration combinations.

Flow Rate(SCFM)

H2S Reduction (PPM)

Annual H2S Removed

(LBS)

100

1,000 5,050

2,000 10,100

3,000 15,150

200

1,000 10,100

2,000 20,200

3,000 30,300

400

1,000 20,200

2,000 40,400

3,000 60,600

* Linear interpolation/extrapolation can be used to extend this table

http://www.mvseer.com/index.php/solutions/h2s-plus-calculator/index.html

QUICK CALCULATION FOR ANNUAL POUNDS OF H2S

http://www.mvseer.com/index.php/solutions/h2s-plus-calculator/index.html

STEP 2: Understand Your Options

In this presentation, we discuss the following technologies, and how they do or do notsupport the H2S removal objectives shown earlier and offer suggestions on how to makeyour final selection:

• Air Injection into the Digester Headspace – Bacterial action converts H2S to H2O+S• Addition of Ferric/Ferrous Chloride into the digester – Iron sulfide forms directly in digester• Activated Carbon Filtration – Captures the H2S; impregnated versions: chemical reactions• BioScrubber/BioTrickling Filters – Bacteria digest H2S to produce SO4+S• Dry Scrubbers – expendable iron-oxide coated media reacts with/neutralizes H2S

NOTE: Those with very large quantity H2S removal requirements should at least look at the range ofchemical and redox offerings, as well as combinations of two technologies such as biological scrubberwith dry scrubber “polisher”.

STEP 3: Consider the Options that Meet Your Objectives

General System Maintenance Cost Reduction– Engine or Direct Use

AIR INJECTION

Variable in removal effectiveness

“Control” to a target outlet objective is

challenging

Sulfur may end up in gas piping and create

clogging

May create engine fuel/air mix ratio

issues

FERRIC CHLORIDE

Varies in removal effectiveness but

works in this application


challenging

“Salt” buildup in digestate may have

impact on land-application

CAPEX varies from low-moderate. High OPEX per lb. of H2S removed. $13/#H2S

CARBON FILTRATION

Highly effective removal

Low CAPEX but high OPEX per lb. of H2S

removed – Carbon alone is $5-$13/# H2S

Even carbon people say avoid >200ppm

inlet

H2S is not converted, rather

captured/neutralized

BIOLOGICAL SCRUBBERS

Effective removal, but systems can be

intolerant to operating condition changes

Moderate-High CAPEX, low direct

OPEX

More operator attention required

Waste water disposal/treatment issues to address

DRY SCRUBBERS


Highly tolerant to operating condition

changes

Moderate CAPEX, moderate OPEX –consumable media

Little operator attention required



AIR INJECTION



challenging


clogging


issues

FERRIC CHLORIDE




challenging




CARBON FILTRATION





inlet







OPEX



DRY SCRUBBERS



changes





AIR INJECTION



challenging


clogging


issues

FERRIC CHLORIDE




challenging




CARBON FILTRATION





inlet







OPEX



DRY SCRUBBERS



changes





AIR INJECTION



challenging


clogging


issues

FERRIC CHLORIDE




challenging




CARBON FILTRATION





inlet







OPEX



DRY SCRUBBERS



changes





AIR INJECTION



challenging


clogging


issues

FERRIC CHLORIDE




challenging




CARBON FILTRATION





inlet







OPEX



DRY SCRUBBERS



changes



STEP 3: Consider the Options that Meet Your ObjectivesEngine or Process Equipment Warranty or Performance Limitations **Fewer available options

CARBON FILTRATION


Low CAPEX, but high OPEX

Can be used as a “polisher” behind other systems

Not really an option in this role unless biogas H2S concentrations

are low


Effective removal at these target levels

Moderate to high CAPEX, low to moderate direct OPEX per unit

of H2S removed

Systems “lag” in response to changes in incoming gas conditions. Operating

attention required – managing biology is non-trivial


DRY SCRUBBERS


Highly tolerant to operating condition changes.

No startup/shutdown lag (no lost revenue)

Low to moderate CAPEX, moderate OPEX – consumable

media

No waste water treatment issues. Low operator attention.


Pipeline/CNG Processing Limitations or Strict Air Quality Control Limits on Emissions

CARBON FILTRATION

Highly effective removal, but not really an option in this role unless biogas H2S concentrations are low

Low CAPEX, high OPEX

Can be used as a “polisher” behind other systems

Enhanced ACs require oxygen for optimal removal efficiency


Effective H2S removal at these target levels

High CAPEX, low direct OPEX

Systems “lag” in response to changes in incoming gas conditions

Adds air to gas stream which may create out of limit conditions on CNG

or Pipeline use

DRY SCRUBBERS


Highly tolerant to operating condition changes. No startup/shutdown lag

(no lost revenue)

Low to moderate CAPEX, moderate OPEX – Media costs <$1.20 per # of

H2S removed

No air addition required for effective removal >> no effect on gas spec

limits

STEP 4: Compare Total Cost of Ownership (TCOs)

Once you have determined the technologies that may suit your objectives, apply a structured approach to compare the cost of available technologies and make your decision. The Baseline for Comparison of TCO is Cost per Pound/Kilogram of H2S Removed per Unit Time under your operating conditions.

Cost elements often overlooked during comparison:• Power costs – pressure drop matters, i.e. dry-scrubber vs. activated carbon• Lost Revenue due to system downtime – maintenance/media

changes/scrubber cleanouts• Replacement of proprietary nutrients and/or chemical/caustic • The costs of testing for warranty or regulatory requirements• Operator attention time – it is not “free”

STEP 4: Compare Total Cost of Ownership (TCOs)

Once you complete the cost analysis there are other factors to consider:

• Total System Footprint/Profile:wind loading on tall towers

• Ease of expansion to handle growth:how modular is the system?

• System flexibility to handle either increased or decreased demand and maintain performance

• Consistency of performance,regulatory issue

Dry Scrubber Systems: What Makes Them a Good Choice

• Capital Cost is Low100 SCFM unit is <$100,000300 SCFM unit is <$150,000600 SCFM unit is <$250,000

• “Set and Forget” - recommended operator attention is less than 3 hours per week

• Operate at lower TCO per pound of H2S• Completely scalable – add tanks in

parallel as your gas volume grows• Can deliver performance without adding

air (O2/N2) to gas stream

• Dry scrubbers deliver designed outlet conditions constantly without regard to changes in inlet conditions.

Dry Scrubber Systems: What Makes Them a Good Choice

MV Technologies Iron Sponge Scrubber Systems

Biogas and Landfill Gas User Installations

• Treatment Flows: 50 - 4,000 scfm

• H2S Concentrations: 150 - 10,000 ppm

• Operating Costs*- less than $1.75 per pound of H2S, including:• new media cost• old media disposal• replacement labor/equipment• parasitic loads

* Excludes capital cost amortization.

Thank YouPresented By:

Tom JonesV.P. of Business Development

[email protected]

Call or email us for more details and a free H2S solutions kit.










6. Audience Q&A

H2S Removal Technologies

Timothy Robinson, President

www.methanesys.com

Clean Methane Systems LLC - www.methanesys.com

Concepts Covered

• What are the major technologies

• Key Selection Criteria • Use of the Gas

• Flow Rate

• Concentration Levels

• Site Conditions

• Technology

• What is the best way to deploy H2S removal technology to maximize the value of biogas

Clean Methane Systems LLC

CMS Services

Clean Methane Systems

Consumables

Gas Testing

Design/ Engineering

Service/ Support

Equipment

Carbon Monetization


Why Remove H2S

Major Drivers for Removal are:

1. Reduced Operating Costs

2. Air Permitting Regulations

3. Exhaust Catalyst


Why Remove H2S

Additional revenue and uptime when operating

with clean biogas.

Operating an engine with dirty gas requires approximately 30-

40% more frequent routine maintenance. This is time that the

engine is not operating and NOT GENERATING REVENUE.

A 350 kW engine with clean biogas will generate approximately

an additional 100,000 kWh electricity and 544 MMBTU heat per

year.

Clean biogas increases the overall life of the engine and

minimizes the risks of unscheduled maintenance.


Not All Sulfur Removal Technologies Are Equal!

CMS offers three primary hydrogen sulfide removal

technologies:

• Biological

• Chemical

• Fixed media


Sulfur Compound Removal Technology Selection Guide

The information contained in this chart is provided in good faith, and every reasonable effort has been made to ensure that it is accurate. This selection guide is to be

used as a reference point only. Please note there are several factors that must be considered when selecting a sulfur removal technology.

There are many factors that must be considered when selecting the type of technology to be used for the removal of sulfur compounds. It is

important to consider efficiencies, capital costs, operating costs and combined “life cycle” costs. Use this selection guide as a starting point

in your decision making process. Call Clean Methane Systems LLC for a free analytical model. It will show specific capital costs and

operating costs for the technology designed for your project.

ppmVH2S

100 250 500 750 1000 1500 2000 3000 4000 5000

SCFM

25 0.3 0.9 1.7 2.6 3.4 5.1 6.8 10.2 13.6 17.1

50 0.7 1.7 3.4 5.1 6.8 10.2 13.6 20.5 27.3 34.1

100 1.4 3.4 6.8 10.2 13.6 20.5 27.3 40.9 54.6 68.2

200 2.7 6.8 13.6 20.5 27.3 40.9 54.6 81.8 109.1 136.4

300 4.1 10.2 20.5 30.7 40.9 61.4 81.8 122.8 163.7 204.6

400 5.5 13.6 27.3 40.9 54.6 81.8 109.1 163.7 218.2 272.8

500 6.8 17.1 34.1 51.2 68.2 102.3 136.4 204.6 272.8 341.0

750 10.2 25.6 51.2 76.7 102.3 153.5 204.6 306.9 409.2 511.5

1000 13.6 34.1 68.2 102.3 136.4 204.6 272.8 409.2 545.6 682.0

1500 20.5 51.2 102.3 153.5 204.6 306.9 409.2 613.8 818.4 1023.0

2000 27.3 68.2 136.4 204.6 272.8 409.2 545.6 818.4 1091.2 1364.0

2500 34.1 85.3 170.5 255.8 341.0 511.5 682.0 1023.0 1364.0 1705.0

3000 40.9 102.3 204.6 306.9 409.2 613.8 818.4 1227.6 1636.8 2046.0

4000 54.6 136.4 272.8 409.2 545.6 818.4 1091.2 1636.8 2182.4 2728.0

5000 68.2 170.5 341.0 511.5 682.0 1023.0 1364.0 2046.0 2728.0 3410.0

Note: The numeric values equal the estimated pounds of H2S gas generated per day based on the air flow and the ppmV loadings.

Fixed Media Chemical Scrubber Bio-Filter

Clean Methane Systems LLC – www.methanesys.com

Sulfur Removal– Fixed Media

Most US based systems that treat the gas for hydrogen sulfide use fixed

media scavenger technology. The majority of sites use either SulfaTreat

or Iron Sponge media and although effective, may result in high

operational costs and frequent change-outs.

Due to the high concentration of hydrogen sulfide, CMS typically only

recommends fixed media removal for very small gas flow rates.


Sulfur Removal– Chemical

The Sulfurex System

This technology provides both moderate

capital and operational pricing.

Provides high equipment uptime.

The only operational expenses are a small

parasitic load and caustic.

The system automatically reacts to varying

levels of hydrogen sulfide in the raw gas

to ensure that the outlet gas always meets

spec.


Sulfur Removal– Biological

CMS offers the BioStrip, a sulfur removal

technology that provides significantly

reduced operating costs!

Makes past cost prohibitive projects

economically viable!

Utilizes the proven technology used in the

odor control industry.

For example, BioStrip reduces media costs

by over $200K/yr when compared to only

SulfaTreat technology with 200 scfm and

3,500 ppmv biogas. This value doesn’t

account for the additional costs of freight,

labor, and disposal.


Sulfur Removal- Pairing

However, by pairing biological or chemical sulfur removal with fixed

media removal, the system operates with minimal operating expenses

but is still able to clean the gas to meet the most stringent natural gas

engine requirements.

Adding a polishing fixed media vessel is typically a small incremental

cost, typically only adding 10-15% of the gas conditioning system price.

Raw Gas Biological or

Chemical Removal to <300 ppmv

Fixed Media Removal to <20

ppmv

Gas Compression and Moisture

Removal Cogeneration


BioStrip and SulfrPack ST BioStrip and SulfrPack CIS SulfrPack ST SulfrPack CIS

Capex $464,138 $490,853 $316,051 $338,098

Yearly Opex $46,087 $42,404 $401,856 $280,735

10 Year Total Expenses $925,007 $914,893 $4,334,611 $3,145,448

$-

$500,000

$1,000,000

$1,500,000

$2,000,000

$2,500,000

$3,000,000

$3,500,000

$4,000,000

$4,500,000

Cost Savings of Pairing Sulfur Removal Technologies

SulfaTreat Only Biological & SulfaTreat Biological & Iron Sponge Iron Sponge Only


Thank You

Timothy D Robinson President

Clean Methane Systems LLC

Office: 425.420.1979 Mobile: 503.780.2143 Email: [email protected] Skype: Tim.D.Robinson Linkedin: linkedin.com/in/timrobinson73

Q&A Ask questions using the Questions Panel on the right side of your screen. All questions and comments will be recorded.

A recording of the webinar and slides will be available by Monday, March 9th to all ABC Members and all attendees of the webinar.

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Documents

H2S: Where Did It Come From, Where Should It Go?americanbiogascouncil.org/webinars/FINAL Webinar Presentation.pdf · March 6th, 2015 11:30 am-1:00 PM ET H2S: Where Did It Come From,