bc moe - final report€¦ · a review of current turbine technologies has been carried out. this...

© SNC-Lavalin Inc. 2011. All rights reserved Confidential

Regulatory Overview of Hazardous Waste Treatment Facility Emissions RFPGS13EPD017

11/05/2012 Proposal

Regulatory+Overview+of+Natural+Gas+Fuelled+Turbine+Emissions+

Final+Report+

Prepared for:

British Columbia Ministry of the Environment

March+31,+2013+

Internal(Ref:(511885(

Regulatory Overview of Natural Gas Fuelled Turbine Emissions 511885

03/31/2013 Final Report

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Table of Contents 1 EXECUTIVE SUMMARY ................................................................................................................................ 7 2 TECHNOLOGY REVIEW .............................................................................................................................. 10

2.1 Short History of Turbine Use and Key Turbine Vendors .................................................................. 10 2.2 Types of Turbines and Common Applications .................................................................................. 11 2.3 Combustion Turbine Emissions and Control Technologies .............................................................. 14

2.3.1 Water Injection .................................................................................................................... 16 2.3.2 Steam Injection .................................................................................................................... 16 2.3.3 Dry Control .......................................................................................................................... 16 2.3.4 Selective Control Reduction (SCR) ..................................................................................... 18 2.3.5 Catalytic Absorption System (SCONOx) ............................................................................. 18 2.3.6 Comparison of Costs between Control Technologies ......................................................... 18

2.4 Review of Present Day Turbines ...................................................................................................... 20 3 LITERATURE REVIEW ................................................................................................................................ 23

3.1 Selection of Jurisdictions for Review ................................................................................................ 23 3.2 Emissions Standards Related to Turbine Use .................................................................................. 24

3.2.2 Alberta Environment ............................................................................................................ 29 3.2.3 Australia .............................................................................................................................. 31

3.2.3.1 Western Australia ................................................................................................ 31 3.2.3.2 New South Wales ................................................................................................ 32 3.2.3.3 Queensland ......................................................................................................... 32

3.2.4 Ontario Ministry of the Environment .................................................................................... 33 3.2.5 US Environmental Protection Agency ................................................................................. 34 3.2.6 California Air Resources Board ........................................................................................... 34 3.2.7 European Union .................................................................................................................. 39

3.3 Monitoring Requirements for Turbine Use ....................................................................................... 39 3.3.1 British Columbia Ministry of the Environment ...................................................................... 39 3.3.2 Alberta Environment ............................................................................................................ 40 3.3.3 Ontario Ministry of the Environment .................................................................................... 40 3.3.4 US Environmental Protection Agency ................................................................................. 40 3.3.5 California Air Resources Board ........................................................................................... 41



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3.3.6 European Union .................................................................................................................. 42 4 SCENARIO ANALYSIS ................................................................................................................................ 44

4.1 Description of Scenarios .................................................................................................................. 44 4.2 Comparison of NOx Emissions from Electric and CT Drives ............................................................ 45

5 LIFE CYCLE ASSESSMENT AND ENERGY EFFICIENCY BETWEEN SCENARIOS ............................... 49 5.1 Projected Energy Costs .................................................................................................................... 50 5.2 Evaluated Life Cycle Differential Costs ............................................................................................ 50 5.3 Evaluated GHG Emissions ............................................................................................................... 52

6 RECOMMENDATIONS ................................................................................................................................. 55 6.1 Basis for Emissions Limits for New Turbines ................................................................................... 55 6.2 Divisions of the Turbine MW Rating Classes ................................................................................... 56 6.3 Requirements for Implementation of SCR/SCONOx ........................................................................ 56 6.4 Proposed NOx Emissions Limits for New Turbines .......................................................................... 57 6.5 Review of Existing Turbines ............................................................................................................. 59 6.6 Monitoring Requirements ................................................................................................................. 60 6.7 Further Studies ................................................................................................................................. 61

In-Text Figures 1: Comparison of DLN and SAC Combustion Chamber Designs .......................................................................... 17

2: Comparison of NOx Emission Standards across Different Jurisdictions ............................................................ 29

3: Typical Process Flows for a Liquefied Natural Gas (LNG) Facility.............................................................. ...... 49

4: Projected Costs of Natural Gas until 2035.............................................................. ........................................... 50

In-Text Tables 1: Comparison of Costs for Operating NOx Emission Control Technologies ......................................................... 19

2: Estimated Costs for Employing Various Emission Control Technologies for Permitted Facilities in the US ...... 20

3: Key Contacts at Each Jurisdiction ..................................................................................................................... 23

4: Emissions Limits Specific to Natural Gas Fuelled Turbines at Each Jurisdiction .............................................. 24



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5: Summary of Turbine Technology, the BACT Applied, and the Emission Limits for Approved Projects Utilizing

Natural Gas Fuelled Turbines in California ............................................................................................................. 36

6: Assumptions Used for the Scenario Analysis .................................................................................................... 46

7: Summary of Results from the Scenario Analysis ............................................................................................... 47

8: Summary of Assumptions Used for the Life Cycle Analysis .............................................................................. 51

9: Life Cycle Analysis Results ................................................................................................................................ 52

10: Summary of Data Used for the Determination of CO2 Emissions for Three Different CT Scenarios ................ 53

11: Comparison of the Current and Proposed Divisions in the Turbine MW Classes for Emissions Limits ............ 56

12: Current and Proposed NOx Emissions Standards for New Installations of Natural Gas Fuelled Turbines ........ 57

13: Recommended Monitoring Requirements for Turbines Based on Size Class and Location ............................ 60

Table of Abbreviations

Abbreviation Description

BACT Best available control technology

BARCT Best available retrofit control technology

BAT Best available technology

BATEA Best available technology economically achievable

BLIERs Base level industrial emission requirements

BREF Best available technique reference document (European Union)

Btu British thermal units

CCME Canadian Council of Ministers of the Environment

CEC California Energy Commission

CEMS Continuous emissions monitoring system

CFR Code of Federal Regulations (USA)

CO Carbon monoxide

CO2 Carbon dioxide

CT Combustion turbine

DLE Dry low emissions

DLN Dry low NOx

EFF Efficiency (used in calculations of emissions limits)

FO Fuel oil

GE General Electric

GHG Greenhouse gas

HAP Hazardous air pollutant



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HHV Higher heating value

HRSG Heat Recovery Steam Generator

HP Horsepower

ISO International Organization for Standardization

kW Kilowatts

LHV Lower heating value

LNG Liquefied natural gas

MACT Maximum achievable control technology

MCR Maximum continuous rating

MJ Megajoule(s)

MMBtu Million Btu

MoE The BC Ministry of Environment

mtpa Millions of tonnes per annum

MW Megawatt(s)

MWh Megawatt hour(s)

NG Natural gas

NOx Nitrogen oxides (specifically NO and NO2)

PAHs Polycyclic aromatic hydrocarbons

PM Particulate matter

ppbV Parts per billion by volume

ppm Parts per million

ppmV Parts per million by volume

ppmvd Parts per million, volumetric dry




Table of Concentration Conversions

Species Molecular Weight, g/mol

Concentration, mg/m3 a Comments

NOx 46 1.9 Molecular weight taken as that of NO2.

CO 28 1.1

UHCs 16–58 0.7–2.4 Range of concentration bounded by pure methane (lower) and pure butane (upper).

a Equation for conversion from ppmV to mg/m3 is: (Concentration, mg/m3) = (Concentration, ppm) × 0.0409 × MW, where MW refers to the molecular weight (in g/mol) of the species.

RACT Reasonably available control technology

SAC Single annular combustor

SCR Selective control reduction

STG Steam turbine generator

UHCs Unburned hydrocarbons

US EPA United States Environmental Protection Agency




1 EXECUTIVE SUMMARY

SLE understands that natural gas fuelled combustion turbines (CT) are of particular interest at present as there

are a number of proposals to construct natural gas liquefied plants in northwest BC which may use this

technology. The BC Ministry of Environment (MoE) is looking to update the current standards and regulations for

natural gas fuelled combustion turbines which were developed in the early 1990s. This research will be used to

inform the updates to the BC policy and regulatory framework.

A review of current turbine technologies has been carried out. This involved a review of the various categories

and sizes of combustion turbine generators. Combustion turbine emissions are reviewed for the main criteria air

contaminants with emphasis on nitrogen oxides (NOx = NO + NO2), carbon monoxide (CO), unburned

hydrocarbons (UHCs), and particulate matter (PM). While a thorough discussion of air toxics is beyond the scope

of this report, some basic discussion on air toxics is presented where appropriate. The applicable emission control

technologies, related capabilities and associated capital and operating costs are presented. The relative costs of

emission monitoring equipment for approved US projects involving natural gas fuelled turbines are presented.

A review of the current literature on emissions regulations specific to natural gas fuelled turbines was conducted.

This report includes a comparison of the current relevant legislation and policies available from the leading

agencies associated with natural gas fuelled turbines. The work has focussed on the relevant legislation,

regulations and policies from the leading agencies (US EPA, the California Air Resources Board, the provinces of

Alberta and Ontario, Environment Canada, Australia, and the European Commission). Information that is not

easily available through online searches (i.e., perspectives of regulators, attitudes from the point of view of the

relevant stakeholders) has been gleaned from a set of structured interviews with key agency contacts. This allows

for greater insight into the standards and methodologies, and the exercise provided context for how the policies

were developed. Moreover, a list of contacts at the selected agencies is available in this report for the MoE’s

reference.




The scenario analysis includes a comparison of the likely cost and emission implications associated with

powering a large liquefied natural gas (LNG) production facility using natural gas fuelled turbines versus electricity

generated by natural gas. A simplified lifecycle analysis (LCA) was conducted in order to assess the emissions,

energy consumption, and costs for the operation of an LNG facility until 2035.

A set of recommendations on new emission guidelines for emissions of NOx, CO, and ammonia slip (from SCR

use) from natural gas fuelled turbines has been put forward. The proposed emissions limits for NOx are

significantly more stringent than the current regulations, although we have presented these recommended NOx

limits as complementary “high stringency” or “lesser stringency” concentration values. The following table

provides a summary of the proposed NOx emissions limits, where differences in limits are largely based on

whether the new turbine installation is within a compromised airshed region of BC:

Size of Turbine Unit

Current Emissions Standard

Controlled Emissions after Application of SCR/SCONOx (Proposed)

Uncontrolled Emissions Without Application of SCR/SCONOx (Proposed)

1 MW to <4 MW

no standard High Stringency: 5 mg/m3 NOx

Lesser Stringency: 10 mg/m3 NOx High Stringency : 30 mg/m3

Lesser Stringency : 50 mg/m3 NOx

4 MW to <50 MW

80 mg/m3 (for >3 to ≤25 MW facilities), 17 mg/m3 (>25 MW facilities), 48 mg/m3 (>25 MW facilities,

no SCR)

High Stringency: 5 mg/m3 NOx Lesser Stringency: 10 mg/m3 NOx

High Stringency : 30 mg/m3 Lesser Stringency : 50 mg/m3 NOx

≥50 MW no standard



We have recommended that emissions limit for carbon monoxide should be set to 57 mg/m3 regardless of the

location and of the size of the installation. The recommended allowable ammonia slip from the SCR should be

limited to 3.5 mg/m3, which is achievable for many SCR applications. We do not recommend an SO2 standard on

natural-gas fuelled turbine emissions since the natural gas available in BC contains an extremely small amount of

sulphur.

We provide recommendations on the implementation of predictive emissions monitoring system (PEMS) and

continuous emission monitoring systems (CEMS). The following provides recommendations on whether facilities

are required to use CEMS, PEMS, or neither based on the size of the turbine unit.




Size of Turbine Unit Monitoring Requirement for Turbine Residing in a Compromised Airshed Region

Monitoring Requirement for Turbine Outside of Any Compromised Airshed Region

1 MW to <4 MW

Not Required Not Required

4 MW to <50 MW

PEMS for turbines up to 25 MW, CEMS for turbines up in 25–50 MW range

CEMS for turbines up in 25–50 MW range

≥50 MW CEMS CEMS

Lastly, we provide recommendations for additional studies that the MoE may choose to carry out to augment this

study. This includes a study of the demarcation of boundaries for compromised airshed regions in BC. Another

recommended area for study deals with creating a rule framework for the application of appropriate control

technologies and clarifying the trigger process for such considerations at both new and existing facilities. We

recommend a study that investigates the practices and outcomes of an emissions trading scheme for NOx

emissions from natural gas turbines. The study of the development and management of consistent PEMS output

(versus standard comparisons) for the purpose of reporting (specific to for natural gas turbines) and maintaining

auditable information might also provide useful information for informing policy.




2 TECHNOLOGY REVIEW

2.1 Short History of Turbine Use and Key Turbine Vendors

Gas turbines, also referred to as combustion turbines (CTs), were invented in the late 1700s. During the period

between 1800 and the early 1900s, there was great experimentation and numerous trials. The world’s first gas

turbine built for power generation was by the Brown Boveri Company of Switzerland in 1939. From this time

onwards to the 1960s, gas turbines were constructed for industrial use. From the 1960s to the present day, the

advent of metallurgy has brought about many significant technology improvements in the performance, efficiency

and air pollutant emission levels of gas turbines. Reference to the term “combustion turbine” is prevalent so this

report will adopt this term for the remainder of the text.

Combustion turbines have been in common use for the last 30 years for driving rotating equipment, powering

aircraft and for generating electrical power. A combustion turbine consists of three major components: (1) the

compressor, (2) the combustor, and (3) the power turbine. Ambient air enters into the compressor, where it is

compressed to the required pressure. The compressed air is then delivered to the combustor. Pressurized fuel

such as natural gas or diesel distillate is flowed into the combustor, where it mixes with the compressed air and is

ignited. The combusted gas is then passed through the power turbine section to convert the energy and heat into

mechanical power at the turbine shaft. The shaft power can be used to drive rotating equipment directly or to

produce electricity via a generator.

There are essentially three different types of CT: (1) the heavy frame CT, (2) the aeroderivative CT, and (3) the

microturbine. For a heavy frame CT, all of the major components and bearings are of industrial heavy

construction and are integrated and installed inside a frame skid. The design and construction of an

aeroderivative CT is derived from aircraft jet engines by converting the thrust turbine into a power turbine. A

microturbine is a small gas turbine that incorporates an internal recuperator heat exchanger. A microturbine

generally operates at speeds greater than 60,000 RPM, with power output in the range of 30–250 kW. Because of

its limited output, it is not used extensively in industry.

Today there are many global companies that manufacture combustion turbines for industrial applications and for

power generation. Major manufacturers of heavy frame CTs include Alstom, General Electric, Mitsubishi and

Siemens. Major manufacturers of aeroderivative CTs include General Electric, Pratt & Whitney and Rolls-Royce.




For smaller frame CTs, Solar Turbines has manufactured many CTs with sizes from 3.5–22 MW both for industrial

applications and also for power generation in Canada.

2.2 Types of Turbines and Common Applications

For industrial applications, CTs are used as mechanical drivers to power compressors and other rotating

equipment. There are many CT applications in North America for natural gas pipeline compressors, air

compressors, and liquefied natural gas (LNG) process compressors.

The thermal efficiencies of the CT drivers vary from about 20–40%, based on the fuel lower heating value (LHV)

(this measurement basis effectively excludes the latent heat of vaporization of water in the combustion product).

For a conventional power plant using a steam turbine as the prime mover, the plant thermal efficiency is generally

calculated based on the higher heating value (HHV). For natural gas fuel, the LHV is approximately 90% of the

HHV. Many CT drivers used in Canada are manufactured by GE, Pratt & Whitney, Rolls-Royce, and Solar.

For power generation CTs can be used to directly drive electric generators generally in the peaking mode during

periods with significant demand from the electric grid. The CTs would be shut down during periods of low grid

demand, such as in the night time. The operation is in simple cycle where the hot combustion gases from the CT

are exhausted to the atmosphere. The thermal efficiencies of simple cycle power plants are generally lower than

those for corresponding industrial applications, due to additional plant parasitic thermal load of approximately 5%.

Many of the CTs for simple cycle power plants are manufactured by Alstrom, GE, and Solar.

By recovering the energy from the CT exhaust gases, the thermal efficiency of a simple cycle power plant can be

improved significantly. To capture the energy, the exhaust gases are ducted to a heat recovery steam generator

or a waste heat unit. The heat recovery steam generator can generate process steam for plant heating processes.

The waste heat unit can transfer the heat to a thermal fluid media for use also by plant heating processes. If the

recovered energy is used directly for process application the configuration is referred to as a cogeneration plant.

As the heat recovery efficiency is extremely high, the LHV thermal efficiency of a cogeneration can be greater

than 90%. Westinghouse (no longer active in the turbine industry as the company has outsourced their turbine

manufacturing under a licensing agreement to Mitsubishi Heavy Industries) had provided two CTs for the

cogeneration plant (120 MW) in Taylor, BC. There are many installations in Alberta for the Oil Sand industries.

Many CTs for cogeneration plants in Canada are manufactured by Alstrom and GE whereas many in the rest of

the world are manufactured by GE, Siemens and Mitsubishi.




When a Heat Recovery Steam Generator (HRSG) is implemented to recover the energy from the CT exhaust

gases to generate steam to drive a steam turbine generator the configuration is referred to a combined cycle

power plant. The plant LHV thermal efficiencies vary in the range of 40–60% depending on steam conditions and

number of pressure levels. There is an Alstom 250 MW combined cycle power plant installed in Campbell River,

BC and a GE 125 MW plant located just a kilometer south of the BC border in Sumas, Washington. There are a

few plants installed in Alberta, Saskatchewan, and Ontario. However in the US there are many combined cycle

plant installations many of which are powered by CTs manufactured by GE.

In addition to power generation, when a combined cycle power plant also provides heat or energy for process

usage, the configuration is referred to a combined cycle cogeneration plant. There is no major plant of this type

installed in BC. However, just south of the BC border, the Sumas combined cycle cogeneration plant is powered

by a GE CT and generates steam for use by proximal lumber dry kilns.

Recently there has been further research and development to utilize integrated gasification combined cycle power

plants that use a process that turns coal into a cleaner fuel used by CTs for more efficient power generation. Due

to the initial high capital cost there are not many examples of this type of power plant in operation throughout the

world.

For industrial application and power generation, manufacturers have produced both types of CTs with various

sizes that can be categorized for the following applications:

1. Equipment Driver

! Frame CTs with shaft output varying from 1,119–375,000 kW.

! Aeroderivative CTs with shaft output varying from 4–60 MW (5,500 to 79,000 HP). With the new

addition of the GE-LMS100PA, the output can be increased to 119 MW.

! The efficiencies of the CTs vary from mid-20% to approximately 43% based on the fuel LHV at ISO

conditions (15°C, 60% relative humidity, sea level). If based on the fuel HHV, the corresponding

efficiency would be equivalent to: EHHV = ~90% × ELHV. The industry generally utilizes the LHV for

calculation of CT efficiencies.

2. Simple Cycle Peaking Power Plant

! Frame CTs with gross electrical output varying from a few MW to 339 MW, with plant output generally

limited by economic reasons and the ability of the CTs to be operated in a cyclical mode.




! Aeroderivative CTs with gross electrical output varying from 4 to 60 MW. With the new addition of the

GE-LMS100PA, the output can be increased to 119 MW.

! The gross efficiencies of the CTs for the simple cycle peaking power plants are basically the same as

those used as equipment drivers. The net efficiencies would be relatively lower due to additional

auxiliary power consumptions from the balance of plant equipment.

3. Cogeneration Power Plant

! CTs used for cogeneration power plants are the same ones used in a simple cycle peaking power

plant. An additional HRSG is incorporated to recover the energy from the CT exhaust to generate

steam (or other media) for process use. Therefore, for plants with the same CT configuration the

electrical output from a cogeneration plant is generally similar to that of a simple cycle power plant.

! Larger CTs are quite often used to generate higher electrical and heat output. If the required process

energy is higher than that from the CT exhaust, a duct burner system could be incorporate to generate

the required load.

! Depending on the amount of heat recovery, the efficiencies of cogeneration plants can be significantly

high (~90%+) as the process energy is also included as useful output. Thus, the efficiencies of

cogeneration plants would the best of all five plant configurations.

4. Combined Cycle Power Plant

! CTs used for combined cycle power plant are the same ones used in a simple cycle peaking power

plant. In addition, an HRSG and a steam turbine generator (STG) are incorporated to generate an

additional ~1/3 electrical output.

! The function of the HRSG is to recover the energy from the CT exhaust and transfer the heat to

generate steam for the STG.

! The STG received the steam from the HRSG to generate the additional electrical output. It exhausts

the steam to a condenser where it is condensed and pumped back to the HRSG.

! The gross outputs of combined cycle power plants are generally ~1/3 higher than those of simple cycle

power plants.




5. Combined Cycle Cogeneration Power Plant

! A combined cycle cogeneration plant is basically a combined cycle power plant except that process

energy steam is extracted from either an intermediate stage of the STG or directly from the HRSG.

Some plants utilize other thermal media fluid to supply energy to the process plant.

! The process steam is sent to the process plant where the energy would be utilized in the plant process.

The process steam is generally returned as condensate back to the HRSG.

! The gross efficiencies of combined cycle cogeneration plants would be generally below those of similar

cogeneration plants.

2.3 Combustion Turbine Emissions and Control Technologies

Before discussing the makeup of combustion turbine emissions it is essential to clarify what is meant by natural

gas. Natural gas is commonly understood to exist as a naturally occurring fluid mixture of light hydrocarbons (e.g.,

methane, ethane, or propane) produced in geological formations beneath the Earth’s surface that maintains a

gaseous state at standard atmospheric temperature and pressure under ordinary conditions. Additionally, natural

gas must either be composed of at least 70% methane by volume or have a gross calorific value in the range of

950–1,100 British thermal units (Btu) per standard cubic foot (35.4–41.0 MJ/m3).

Emissions from CTs include mainly carbon dioxide (CO2), hazardous air pollutants (HAPs) and non-HAP

pollutants. Perfect combustion occurs when the fuel and the oxygen combine in exactly the proper proportions to

completely burn the fuel. This condition, known as stoichiometric or zero excess air combustion, produces CO2

and water (H2O). The formula for theoretical, perfect combustion of hydrocarbons (with the general chemical

formula CxHy) in oxygen is:

For methane the above formula would become:

If the combustion occurs using air as the oxygen source (which is the case for CTs), the nitrogen available in air

(as N2) is incorporated into the reaction mechanism. It should be noted that nitrogen does not directly take part in

the reaction unless there is an excess of oxygen. The oxidation of nitrogen is thermodynamically favourable only

+ (x + ) ! x + ( ) O CxHyy

4O2 CO2

y

2H2

+ ! + O CH4 2O2 CO2 2H2




at high temperatures, and at such conditions nitrogen gas plays a minor role in the combustion process and some

nitrogen oxides (NOx = NO + NO2) will form. In the case of methane undergoing combustion in an oxygen-rich air

environment, the following non-stoichiometric chemical equation applies:

Note that in the above equation an incomplete combustion of methane has occurred resulting in the formation of

carbon monoxide (CO) in addition to the expected CO2. Incomplete combustion also produces elemental carbon,

which leads to the formation of soot which is a form of particulate matter (PM). Soot formation is typically highest

when too little air is supplied to the burner since there is not enough oxygen to completely form CO2 with all the

carbon in the fuel. A final consequence of too little supply air is the presence of unburned hydrocarbons (UHCs) in

the exhaust gas.

With natural gas fired CTs, formaldehyde is the main contributor to the HAP emissions with the remaining from

polycyclic aromatic hydrocarbons (PAHs) and other compounds. The Non-HAP emissions (i.e., the criteria air

contaminants) include NOx, CO, the UHCs, and PM. Although this report mainly focuses on the Non-HAP

emissions (and with greater emphasis on NOx), brief discussion of HAP emissions will be presented where

appropriate.

When quantifying emissions from turbines, there are several types in units for doing so. The most frequent units

are those in parts-per notation by volume (e.g., parts per million, or ppmv; parts per billion, ppbv) or as a

concentration in the form of mass over volume (i.e., mg/m3). For the purpose of consistency and to aid in

comparisons, all emissions units have been converted to mg/m3 values where possible.

In the 1970s, for natural gas fired combustion turbines manufacturers could guarantee NOx emission at 141

mg/m3. In the 1980s, the guarantees were improved to 79 mg/m3. However, the corresponding CO emissions

could vary significantly depending on the technology used to control NOx emission. At present, depending on the

type and sizes of the CT, NOx and CO emissions in the ranges of 17–47 (mg NOx)/m3 and 10–30 (mg CO)/m3 are

achievable. There are two basic mechanisms in the formation of NOx: thermal NOx and organic NOx. Thermal NOx

is formed from the oxidation of the free nitrogen in the combustion air or fuel, which increases with fuel to air ratio

or with firing temperature. It increases exponentially with combustor inlet air temperature. Organic NOx is formed

from the oxidation of organically bound nitrogen in the fuel with near 100% conversion efficiency. For CTs firing

on natural gas, emissions of organic NOx is not significant since natural gas contains very low amounts of

nitrogen-containing organic compounds (i.e., the available nitrogen is in the form of nitrogen gas). PM emissions

generally result from residual particulate matter in the natural gas fuel as there is insignificant residual carbon in

+ 2 + ! 2 O + + CO + NO + CH4 O2 N2 H2 CO2 NO2




the combustion product. Thus, PM emissions from various modern CTs are similar but increase with increasing

size of the turbine. For example, PM2.5 emissions from GE turbines range from 1.5 kg/hour for 18-33 MW simple

cycle CTs but increase to 3 kg/hour for CTs at ca. 100 MW. There is also some variations in PM2.5 emissions

from similarly sized turbines from different vendors (e.g., the Hitachi simple cycle H-80 turbine at 99.3 MW emits

PM2.5 at 0.8 kg/hour whereas the GE simple cycle LM100PA turbine at 103.5 MW emits PM2.5 at 3.0 kg/hour). The

following sections provide information on the general types of emission controls for CTs.

2.3.1 Water Injection

In the 1980s and 1990s, one form of NOx emission control is by injection of water into the single annular

combustor (SAC) combustion cover / fuel nozzle area. This reduces the combustion flame temperature in the

combustor, which in turn reduces the production of thermal NOx. The water injection system, which is controlled

by the CT microprocessor system, consists of a water pump and filter, flow meters, and stop and control valves.

With this control technology, NOx emissions can be reduced to 79 mg/m3 but that comes at a cost of significantly

increasing emissions of CO. By reducing the combustion gas temperature in the CT, additional gas mass flow can

be sent through the turbine to increase the output capacity. However, at the earlier implementation stage, this

control technology caused premature replacement or repairs of the combustor but has improved since. Due to

energy required for evaporation of the water, the process reduces the thermal efficiency of the CT. At present in

North America, water injection is still in use on aeroderivative CTs to increase capacity during hot ambient

conditions but not widely used in large frame CT application.

2.3.2 Steam Injection

Steam injection is a varied form of water injection for controlling of NOx emission from CTs. It achieves similar

reduction in NOx emission by reducing the combustion flame temperature in the combustor. As the steam is

already in vapour form, it is not necessary to give up the energy to the water’s latent heat. Consequently, there is

no significant reduction of the overall thermal efficiency of the plant. However, there is additional cost for

equipment to generate the steam. At present, in North America steam injection for NOx emission control for CTs is

no longer widely used.

2.3.3 Dry Control

In the 1990s to 2000s as the demand for lower NOx emissions was imposed, new control technologies were

developed which led to the introduction of the dry control technology known as Dry Low NOx (DLN) or Dry Low




Emissions (DLE). Many CT manufacturers have implemented the dry control technology for their CTs. General

Electric (GE), a large CT manufacturer in the US, developed dry low NOx systems (DLE, DLN-1, DLN-2, DLN-2.6)

for its fleet of CTs.

According to a US EPA report on gas turbines:

The combustion process in a gas turbine can be classified as diffusion flame combustion or lean-

premix staged combustion. In the diffusion flame combustion the fuel/air mixing and combustion

takes place simultaneously in the primary combustion zone. This generates regions of near-

stoichiometric fuel/air mixtures where the temperatures are very high. For lean-premix combustors,

fuel and air are thoroughly mixed in an initial stage resulting in a uniform, lean, unburned fuel/air

mixture which is delivered to a secondary stage where the combustion reaction takes place.

Manufacturers use different types of fuel/air staging, including fuel staging, air staging, or both;

however, the same staged, lean-premix principle is applied. Gas turbines using staged combustion

are also referred to as Dry Low NOx combustors. The majority of gas turbines currently

manufactured are lean-premix staged combustion turbines.

The basic concept of a DLN or DLE system is based on staged combustion of lean premixed mixtures, which can

achieve 47 mg/m3 NOx emissions. With further development and refinement, the dry control system is able to

achieve NOx emissions in the range of 17–28 mg/m3. Figure 1 shows the typical differences between the SAC

and DLN combustion chamber designs for a GE LM2500 engine.

Figure 1: Comparison of DLN and SAC Combustion Chamber Designs

Image source: GE LM2500 to LM2500+DLE Repowering Gas Turbine Combined Cycle Plant RePowering – City of Medicine Hat.

Premixers Heat Shields Single Fuel Nozzle Passage

Dry Low Emissions Single Annular Combustor




2.3.4 Selective Control Reduction (SCR)

In addition to the aforementioned types of emission controls, additional control can be achieved by using selective

control reduction (SCR) to treat the exhaust gas after it leaves the CT. By utilizing catalysts, generally of precious

metals, and reductants such as ammonia or urea, the SCR converts the NOx back to nitrogen and oxygen. Its

conversion efficiency is greater than 90% and is dependent on the allowance of ammonia slip (non-reacted) in the

gas stream, generally well below 7 (mg NH3)/m3. There are two main types of SCR: (1) high temperature and (2)

conventional. The high temperature SCR are capable of operation with CT exhaust gas temperature in the range

of 400–600 °C for simple cycle operation. Conventional SCR is effective within a temperature range of 315–400°C

for CT combined cycle and cogeneration power plants.

2.3.5 Catalytic Absorption System (SCONOx)

SCONOx™, patented by Goal Line Environmental Technologies (now distributed by EmeraChem), is a post-

combustion alternative to SCR that has been demonstrated to reduce NOx emissions to less than 1.9 mg/m3 and

can effect a nearly 100% removal of CO. SCONOx combines catalytic conversion of CO and NOx with an

absorption / regeneration process that eliminates the ammonia reagent found in SCR technology. It was identified

as lowest achievable emission rate technology for gas turbine NOx control by U.S. EPA Region 9 in 1998.

2.3.6 Comparison of Costs between Control Technologies

For the purpose of cost comparison, the costs (based on 1999 data) of utilizing the aforementioned technologies

for NOx emission control for CTs are summarized in Table 1.

As shown on Table 1, the DLN technology is the most cost effective technology for NOx reduction. However, with

improvements to the technology underlying water injection, NOx emissions can presently be controlled to 47

mg/m3 (compared with a typical value of 79 mg/m3 during the late 1990s as in Table 1) If it is necessary to offset

the CT capacity degradation during months with high ambient temperature, water injection is still viable for

simultaneous NOx emission control and power augmentation. High temperature SCR (for simple cycle operation),

conventional SCR (for combined cycle or cogeneration operation), and SCONOx controls are applicable to reduce

NOx emission after the exhaust gas is discharge from the CT. They are generally used in series with the turbine’s

NOx emission control systems (i.e., DLN or DLE).

In the US EPA’s National CT List, cost estimates are provided for different technologies that provide emissions

reduction capabilities beyond what was finally implemented in the project. Table 2 provides selected data from the




National CT List for turbine applications in the power generation sector. As shown in Table 2, the facilities used

some implementation of DLN and, in many cases (though not apparent in the limited data shown in Table 2) an

additional emissions control technology such as water injection or SCR was used. These data provide a good

indication of the approximate costs per US ton of pollutant removed with different control technologies for

individual facilities. Unfortunately, the US EPA’s National CT List is no longer being maintained, so the data is

limited to the period of 1993–2008.

Table 1: Comparison of Costs for Operating NOx Emission Control Technologiesa

NOx Emission Control Technology

NOx Emissions Limit, mg/m3 b

5 MW Class 25 MW Class 150 MW Class

$/US ton ¢/kWh $/US ton ¢/kWh $/US ton ¢/kWh

DLN/DLE 47 260 0.075 210 0.124 122 0.054

Water/Steam Injection 79 1,652 0.410 692 0.215 371 0.146

Conventional SCR 16.9 9,274 0.469 3,541 0.204 1,938 0.117

High-temp SCR 16.9 7,148 0.530 3,841 0.221 2,359 0.134

SCONOx 3.8 16,327 0.847 11,554 0.462 6,938 0.289

a These data are reproduced from Table A-1, Contract No. DE-FC02-97CHIO877 of US Department of Energy, available at: http://www1.eere.energy.gov/manufacturing/distributedenergy/pdfs/gas_turbines_nox_cost_analysis.pdf.

b Corrected to 15% O2.




Table 2: Estimated Costs for Employing Various Emission Control Technologies for Permitted Facilit ies in the USa

Facility Name and US State

Power (MW)

Turbine Model NOx Limit CO Limit

Control Methods Used

Cost Evaluations for Other Emission Control Technologies

Duke Energy, Ft. Pierce (FL) 640

GE 7EA (80 MW)

19.8 mg/m3 NG,

79.0 mg/m3 FO

47.0 mg/m3 NG,

37.6 mg/m3 FO

DLN; water injection

SCR: $50,602 / US ton NOx (2001)

Duke Energy, Autuga (AL) 630

GE 7FA (170 MW)

6.6 mg/m3 17.2 mg/m3 DLN, SCR

SCONOx: $18,760 / US ton NOx, CatOx: $5,006 / US ton CO (2001)

Duke Energy, Dale (AL) 630

GE 7FA (170 MW)

6.6 mg/m3 0.33 lb/mmbtu

SCONOx: $18,403 / US ton NOx, CatOx: $2,634 / US ton CO (2001)

Reliant Energy - Choctaw Co., LLC (MS)

844 GE 7FA

(170 MW) 6.6 mg/m3 34.6

mg/m3 DLN, SCR SCONOx: $48,663 / US ton NOx, CatOx: $3,550 / US ton CO (2001)

Wisconsin Public Service (WI) 360

GE 7EA (102 MW)

16.9 mg/m3 NG,

79.0 mg/m3 FO

47.0 mg/m3 NG,

37.6 mg/m3 FO

DLN

SCR: $13,866 / US ton NOx; CatOx: $6053 / US ton CO incremental cost (1999)

MEA of Georgia – W.R. Clayton (GA)

500 GE 7FA

(170 MW)

22.6 mg/m3 NG,

79.0 mg/m3 FO

24.7 mg/m3 NG,

61.0 mg/m3 FO

DLN; water injection

Hot SCR: $14,100 / US ton NOx, CatOx: $15,000 / US ton CO (2003)

a Taken from dataset available at: http://www.epa.gov/region4/air/permits/national_ct_list.xls.

2.4 Review of Present Day Turbines

Turbine vendors were directly contacted to supply information about their natural gas fuelled turbines (i.e.,

mechanical drive, simple cycle, and combined cycle). The selection of vendors was comprehensive and the

specific turbine models for which information was requested comprise the bulk of the current global turbine use.

The vendors queried include: (1) GE, (2) Hitachi, (3) Mitsubishi (4) Pratt & Whitney, (5) Rolls-Royce, (6) Siemens,

and (6) Solar. Appendix I provides tabular summaries of vendor-supplied data specific to each turbine model; the

types of data include the emissions control methods applicable to each turbine, the emissions of NOx, CO, PM,

and UHC, and engine specific power and efficiency parameters. All engine manufacturers that were contacted




had supplied some or all of the information requested. However, where engine information was not provided in a

timely manner, published data was utilized. Data that was not available was left blank in the Appendix I tables.

Typical modern day CT engines can achieve emissions levels of 47 mg/m3 NOx and 57.3 mg/m3 CO in order to be

in compliance with applicable emissions standards. Analysis of the table data in Appendix I shows that most

engine manufacturers can readily achieve these levels for NOx and are well under these levels for CO (typical

range of 11.5–28.6 mg/m3) for either mechanical drive or electric power generation applications at 100% MCR

(maximum continuous rating) load conditions using DLE (dry low emissions) control technology. This is important

because in order to still be in compliance with applicable emission standards at loads below 100% MCR, NOx

emissions typically go down due to lower combustion temperatures but both CO and unburned hydrocarbon

emissions typically increase due to incomplete combustion at lower loads.

Some engine manufacturers can achieve NOx levels of 28.2 mg/m3 at 100% MCR load conditions using DLE

technology on some engine models with even further reductions to 16.9 mg/m3 using advanced DLE technology.

Advanced DLE technology essentially consists of introducing combustion air at sequential stages into the

combustion process in order to better control and minimize the combustion flame temperature. NOx emissions

less than 16.9 mg/m3 require the use of SCR along with advanced DLE technology as explained in Section 2.3.

DLE for NOx control using lean pre-mixing to achieve a uniform air/fuel mixture before combustion is a well

developed technology with extensive operating experience worldwide and is now widely used in many industrial

and power plant applications.

Water/steam injection can only achieve NOx emission levels of 47.0 mg/m3. The use of water injection for NOx

control is associated with a decrease in machine efficiency of approximately 2–3% and typically adds complexity

in order to treat and deliver the water at the correct pressure and quality to the turbine. Note also that water

injection causes the CO emissions to increase even further at loads below 100% MCR since the addition of the

water mass reduces the effectiveness of how CO oxidizes to CO2.

Filterable emissions of particulate matter (PM) from gas turbines are typically low. They are considered to be

primarily a result of carryover from non-combustible trace matter constituents in the fuel. Trace matter fuel

components are largely removed during the upstream processing and filtering of the fuel gas before it is delivered

into the natural gas supply system. Any trace matter constituents that remain in the fuel after upstream treatment

pass through the turbine to be emitted as PM. According to the US EPA report AP-42, PM from natural gas

combustion has been estimated to be less than 1 micrometer in size and has filterable and condensable fractions.

Particulate matter in natural gas combustion has been found to consist mainly of larger molecular weight




hydrocarbons that are not fully combusted. Poor air/fuel mixing or maintenance issues my lead to increased PM

emissions.




3 LITERATURE REVIEW

3.1 Selection of Jurisdictions for Review

The following air quality jurisdictions for chosen for this review: (1) Alberta Environment, (2) the Ontario Ministry of

the Environment, (3) Environment Canada, (4) the California Air Resources Board, (5) the Australian state-level

EPAs, (6) the United States Environmental Protection Agency (US EPA), and (7) the European Union. These

agencies/jurisdictions, while diverse, were chosen since they either reside in Canada and/or are widely

recognized as the leading agencies with regard to the stringency of emissions regulations related to turbine use.

Wherever possible, key contacts at these jurisdictions were identified and interviewed (Table 3 provides a listing

of the agency personnel that provided useful information to support this review). Potential contacts at

Environment Canada and the U.S. EPA were unavailable for discussion.

Table 3: Key Contacts at Each Jurisdiction

Contact Name and Position Details Contact Information

Randy Dobko Senior Engineer Alberta Environment and Sustainable Resource Development Air Policy Section

9820 – 106 Street Edmonton, AB phone: (780) 427-6869 [email protected]

Chris Gallenstein Staff Air Pollution Specialist, Source Review Permitting & Coatings Airborne Toxic Control Measures California Air Resources Board, Stationary Source Division

P.O. Box 2815 Sacramento, CA 95812 phone: (916) 324-8017 [email protected]

Denis Maftei Source Assessment Engineer, Technology Standards Section Ontario Ministry of the Environment

9th & 7th Flr 40 St. Clair Ave W Toronto, ON M4V 1M2 phone: (416) 327-6995 [email protected]

Ralph Riese Project Support, Statewide Environmental Assessment Dept of Environment and Heritage Protection Queensland EPA

400 George Street Brisbane, Qld 4000 Phone: 61 7 3330 5706 [email protected]

Adrian Kesterson Sr. Environmental Officer, Industry Regulation Licensing Branch Environmental Regulation Division, Department of Environment and Conservation Western Australia EPA

Level 7, 168 St. Georges Terrace Perth, WA 6000 phone: +61 8 6467 5054 [email protected]

Krystyna Panek-Gondek Seconded National Expert, Policy Officer, Unit Industrial Emissions, Air Quality & Noise Directorate-General for the Environment European Union

BU-9 05/037 Avenue de Beaulieu 5, B-1049 Brussels/Belgium phone: +32 2 295 26 67 [email protected]




3.2 Emissions Standards Related to Turbine Use

The jurisdictions that were reviewed as part of this study have widely varying rules and emissions standards with

regard to natural gas fuelled turbines. Table 4 presents a summary of emission limits specific to natural gas

turbine use. All values presented within the table are corrected to reference conditions of 20°C and 101.325 kPa

at 15% O2 on a dry volume basis. The emissions standards for British Columbia are provided as a frame of

reference (a copy of the drafted regulations is provided in Appendix II). As there is a large number of emissions

limits for NOx across the selected jurisdictions, a visual representation of the NOx limits (i.e., an annotated plot of

NOx emission limits versus turbine installation MW rating) is provided as Figure 2.

Table 4: Emissions Limits Specific to Natural Gas Fuelled Turbines at Each Jurisdiction

Description of Emissions Limits mg/m3 Notes Ref.

British Columbia Ministry of the Environment

• >3(to(≤25(MW(plant:(80(mg(NOx/m3(

• >25(MW(plant:(17(mg(NOx/m3(

• >25(MW(plant:(48(mg(NOx/m3((where(SCR(is(inappropriate)(

80(

17(

48(

Reference(conditions(of(20°C,(101.325(kPa((ISO(conditions),(and(dry(gas(concentration(corrected(to(flue(gas(oxygen(content(of(15%(by(volume.(These(emissions(criteria(were(published(in(December(1992.(

a

• >3(to(≤25(MW(plant:(80(mg(CO/m3(

• >25(MW(plant:(58(mg(CO/m3(

80(

58(

All(corrected(to(ISO(conditions(at(15%(O2(on(a(dry(volume(basis.(These(emissions(criteria(were(published(in(December(1992.(

a

Alberta Environment

• 0–20(MW(plant:(0.6(kg(NOx/MWhoutput(


• >60(MW(plant:(0.3(kg(NOx/MWhoutput(

55(

42(

35(

All(corrected(to(ISO(conditions(at(15%(O2(on(a(dry(volume(basis.(All(limits(effective(January(1,(2006.(Applies+to+each+new+generating+unit.(The(MWh(value(shall(include(both(the(combined(total(thermal(energy(and(the(net(generation(of(electricity(excluding(any(electricity(used(to(produce(the(electricity.(

b



• >60(MW(plant:(0.3(kg(NOx/MWhoutput(

55(

42(

35(

All(corrected(to(ISO(conditions(at(15%(O2(on(a(dry(volume(basis.(All(limits(effective(January(1,(2006.(Applies+to+generating+units+that+have+reached+the+end+of+their+design+life.(For(generating(units(that(have(reached(the(end(of(their(design(life(before(January(1,(2010,(the(specified(limits(will(be(in(effect(on(January(1,(2011.(The(MWh(value(shall(include(both(the(combined(total(thermal(energy(and(the(net(generation(of(electricity(excluding(any(electricity(used(to(produce(the(electricity.(

b





• 1.008(kg(NOx/MWh(×(maximum(continuous(rating(in(MW(×(1500(hours(

( All(corrected(to(ISO(conditions(at(15%(O2(on(a(dry(volume(basis.(Applies(to(peaking(units.(Formula(yields(annual(maximum(mass(emission.(

b

3.2.1.1.1.1.1.1 Ontario Ministry of the Environment

• 0–3(MW(unit:(0.50(kg(NOx/GJoutput(

• 3–20(MW(unit:(0.24(kg(NOx/GJoutput(

• >20(MW(unit:(0.14(kg(NOx/GJoutput(

137(

73(

49(

All(corrected(to(ISO(conditions(at(15%(O2(on(a(dry(volume(basis.(Ontario(adopts(emissions(limits(from(the(CCME(‘National(Emission(Guidelines(for(Stationary(Combustion(Turbines’,(published(December(1992.(Applies+to+nonFpeaking+turbines.(

c

• 0–3(MW(unit:(exempt((NOx)(

• >3(MW(unit:(0.28(kg(NOx/GJoutput(

—(

83(

All(corrected(to(ISO(conditions(at(15%(O2(on(a(dry(volume(basis.(Ontario(adopts(emissions(limits(from(the(CCME(‘National(Emission(Guidelines(for(Stationary(Combustion(Turbines’,(published(December(1992.(Applies+to+peaking+turbines.(

c

• 50(ppmV(CO(

(

57( All(corrected(to(ISO(conditions(at(15%(O2(on(a(dry(volume(basis.(Ontario(adopts(emissions(limits(from(the(CCME(‘National(Emission(Guidelines(for(Stationary(Combustion(Turbines’,(published(December(1992.(Applies+to+all+turbines+covered+by+the+NOx+provisions.((

c

• 0.80(kg(SO2/GJoutput((nonbpeaking(unit)(

• 0.97(kg(SO2/GJoutput((peaking(unit)(

294(

353(

All(corrected(to(ISO(conditions(at(15%(O2(on(a(dry(volume(basis.(Ontario(adopts(emissions(limits(from(the(CCME(‘National(Emission(Guidelines(for(Stationary(Combustion(Turbines’,(published(December(1992.(Emissions(limits(are(based(on(the(lower(heating(value(of(the(fuel.(Units(that((1)(have(a(power(rating(<3(MW(and((2)(are(used(exclusively(to(power(natural(gas(field(compressors(upstream(of(natural(gas(processing(facilities(are(exempt(from(the(SO2(limits.(

c

California Air Resources Board

• <10(MW(unit:(exempt((NOx)(

• ≥10(MW(unit:(9(ppmV(NOx(×((EFFd/25%)(

—(

17(×(...(

(

All(corrected(to(ISO(conditions(at(15%(O2(on(a(dry(volume(basis.(From(Rule(425(entitled(‘Cogeneration(Gas(Turbine(Engines’,(first(adopted(on(August(16,(1993.(Applies+to+existing+turbines.(The(purpose(of(the(rule(is(for(retrofitting(of(NOx(best(available(control(technology((BACT)(to(cogeneration(gas(turbine(engines(subject(to(California(Health(&(Safety(Code(Section(40918((b)(and(compliance(with(reasonably(available(control(technology((RACT)(NOx(limits(for(cogeneration(gas(turbine(engines(subject(to(1990(Federal(Clean(Air(Act(Section(182(f).(

e





• 0.3(to(<2.9(MW(unit:(25(ppmV(NOx(×((EFFf(/(25%)(

• 2.9(to(<10.0(MW:(9(ppmV(NOx(×((EFFf(/(25%)(

• 2.9(to(<10.0(MW,(No(SCR:(15(ppmV(NOx(×((EFFf(/(25%)(

• ≥10.0(MW:(9(ppmV(NOx(×((EFFf(/(25%)(

• ≥10.0(MW,(No(SCR:(12(ppmV(NOx(×((EFFf(/(25%)(

• ≥60(MW(and(Over(Combined(Cycle,(No(SCR:(15(ppmV(NOx(×((EFFf(/(

25%)(

• ≥60(MW(and(Over(Combined(Cycle:(9(ppmV(NOx(×((EFFf(/(25%)(

47(×(...(

17(×(...(

28(×(...(

17(×(...(

23(×(...(

28(×(...(

(

17(×(...(

All(corrected(to(ISO(conditions(at(15%(O2(on(a(dry(volume(basis.(From(Rule(1134((South(Coast(Air(Quality(Management(District),(first(adopted(on(August(4,(1989((Amended(on(December(7,(1995;(April(11,(1997;(and(August(8,(1997).(Applies(to(all(existing(stationary(gas(turbines(of(0.3(MW(and(larger,(as(of(August(4,(1989.(

g

• <0.3(MW(unit:(exempt((NOx)(

• ≥0.3(MW(unit:(42(ppmV(NOx(

—(

79(

(

All(corrected(to(ISO(conditions(at(15%(O2(on(a(dry(volume(basis.(From(Rule(69.3((Stationary(Gas(Turbine(Engines(b(Reasonably(Available(Control(Technology),(first(adopted(and(effective(on(September(27,(1994((revision(of(which(was(adopted(and(effective(on(December(16,(1998).(Applies(to(stationary(gas(turbines(situated(in(the(San(Diego(County(Air(Pollution(Control(District.(Applies(to(all(turbines(when(operated(on(a(gaseous(fuel.(

h

Australia, New South Wales Environmental Protection Authority

• 70(mg/m3( 70( All(corrected(to(ISO(conditions(at(15%(O2(on(a(dry(volume(basis.(New(cogeneration(proposals(involving(gas(turbines(located(outside(of(the(in(Sydney(and(the(Illawarra(geographic(zones(are(required(to(meet(this(NOx(limit(as(outlined(in(the(Protection(of(the(Environment((Clean(Air)(Regulation(2002.(

i

U.S. Environmental Protection Agency

• <50(MMBtu/h(heat(input(at(peak(loadj:(42(ppmV(NOx(or(2.3(lb(NOx/MWh(

79( All(corrected(to(ISO(conditions(at(15%(O2(on(a(dry(volume(basis.(From(EPA(40(CFR(Part(60((latest(revision,(published(July(1,(2012).(Applies(to(new(turbines(firing(natural(gas,(electric(generating.(

k


188( All(corrected(to(ISO(conditions(at(15%(O2(on(a(dry(volume(basis.(From(EPA(40(CFR(Part(60((latest(revision,(published(July(1,(2012).(Applies(to(new(turbines(firing(natural(gas,(mechanical(drive.(

k

• 50–850(MMBtu/h(heat(input(at(peak(loadj:(25(ppmV(NOx(or(1.2(lb(NOx/MWh(

47( All(corrected(to(ISO(conditions(at(15%(O2(on(a(dry(volume(basis.(From(EPA(40(CFR(Part(60((latest(revision,(published(July(1,(2012).(Applies(to(new(turbines(firing(natural(gas.(

k

• >850(MMBtu/h(heat(input(at(peak(loadj:(15(ppmV(NOx(or(0.43(lb(NOx/MWh(

28( All(corrected(to(ISO(conditions(at(15%(O2(on(a(dry(volume(basis.(From(EPA(40(CFR(Part(60((latest(revision,(published(July(1,(2012).(Applies(to(new,(modified,(or(reconstructed(turbines(firing(natural(gas.(

k






282( All(corrected(to(ISO(conditions(at(15%(O2(on(a(dry(volume(basis.(From(EPA(40(CFR(Part(60((latest(revision,(published(July(1,(2012).(Applies(to(any(modified(or(reconstructed(turbine(regardless(of(fuel(type.(

k

• 50–850(MMBtu/h(heat(input(at(peak(loadj:(42(ppmV(NOx(or(2.0(lb(NOx/MWh(

79( All(corrected(to(ISO(conditions(at(15%(O2(on(a(dry(volume(basis.(From(EPA(40(CFR(Part(60((latest(revision,(published(July(1,(2012).(Applies(to(any(modified(or(reconstructed(turbine(firing(natural(gas.(

k

• <30(MW(output:(150(ppm(NOx(or(8.7(lb(NOx/MWh( 282( All(corrected(to(ISO(conditions(at(15%(O2(on(a(dry(volume(basis.(From(EPA(40(CFR(Part(60((latest(revision,(published(July(1,(2012).(Applies(to(any(turbine,(regardless(of(fuel(type,(if(either(of(these(conditions(is(true:((1)(turbine(located(north(of(the(Arctic(Circle((66.5°N),((2)(turbine(operating(at(<75%(of(peak(load,((3)(modified(and(reconstructed(offshore(turbines,(or((4)(turbines(operating(at(temperatures(less(than(0°F((–17.8°C).(

k

• 0.90(lb(SO2/MWh,(or,(

• fuel(sulphur(content(limit:(0.060(lb(SO2/MMBtu((500(ppmw(SO2)(

(

59( All(corrected(to(ISO(conditions(at(15%(O2(on(a(dry(volume(basis.(From(EPA(40(CFR(Part(60.(Applies(to(any(turbine(located(in(continental(areas,(regardless(of(fuel(type.(Choice(in(compliance(with(the(SO2(limit(itself(or(with(a(limit(on(the(sulphur(content(of(the(fuel.(

k

• 6.2(lb(SO2/MWh,(or,(

• fuel(sulphur(content(limit:(0.060(lb(SO2/MMBtu((500(ppmw(SO2)(

288( All(corrected(to(ISO(conditions(at(15%(O2(on(a(dry(volume(basis.(From(EPA(40(CFR(Part(60.(Applies(to(any(turbine(located(in(nonbcontinental(areas,(regardless(of(fuel(type.(Choice(in(compliance(with(the(SO2(limit(itself(or(with(a(limit(on(the(sulphur(content(of(the(fuel.(

k

European Union

• 50–500(MWh,(300(mg(NOx/m3((ca.(159.5(ppmV(at(ISO(conditions)(

• >500(MWh,(200(mg(NOx/m3((ca.(106.3(ppmV(at(ISO(conditions)(

300(

(

200(

All(corrected(to(ISO(conditions(at(15%(O2(on(a(dry(volume(basis.( From(Directive(2001/80/EC,(Annex(V.( Limit( values(apply(to(new(and(existing(turbines(using(gaseous(fuels(in(general((including(natural(gas).(

l

• >500(MWh,(350(mg(NOx/m3((ca.(186.1(ppmV(at(ISO(conditions)( 350( All(corrected(to(ISO(conditions(at(15%(O2(on(a(dry(volume(

basis.( From(Directive(2001/80/EC,(Annex(V.( Limit( values(apply(to(new(and(existing(turbines(using(gaseous(fuels(in(general( (including( natural( gas)( that( are( located( in(specified( ‘Outermost(Regions’( (i.e.,( the( French(Overseas(Departments( with( regard( to( France,( the( Azores( and(Madeira(with( regard( to(Portugal( and( the(Canary( Islands(with(regard(to(Spain).(

l





• >400(MWh,(800(mg(NOx/m3((ca.(425.4(ppmV(at(ISO(conditions)( 800( All(corrected(to(ISO(conditions(at(15%(O2(on(a(dry(volume(

basis.( From(Directive(2001/80/EC,(Article(5.( Limit( values(apply( to(existing( turbines(using(gaseous( fuels( in(general((including(natural(gas),(and,(must(not(operate(more(than(2000( hours/year( (until( December( 31,( 2015)( or( 1500(hours/year( (from( January(1,(2016)(where( the( figure( is( a(5byear(rolling(average.(

l

• 35(mg(SO2/m3((ca.(13.4(ppmV(at(ISO(conditions)( 35( All(corrected(to(ISO(conditions(at(15%(O2(on(a(dry(volume(

basis.( From(Directive(2001/80/EC,(Annex(V.( Limit( values(apply(to(new(and(existing(turbines(using(gaseous(fuels(in(general((including(natural(gas).(

l

a Emission Criteria for Gas Turbines (December 1992). Available at: http://www.bcairquality.ca/reports/ecfgt.html. b Alberta Air Emission Standards for Electricity Generation and Alberta Air Emission Guidelines for Electricity Generation, ENV-569-OP,

Alberta Environment, ISBN: 0-7785-6759-2, 1995. Available at: http://www.environment.gov.ab.ca/info/library/7837.pdf c National Emission Guidelines for Stationary Combustion Turbines, CCME-EPC/AITG-49E, Canadian Council of Ministers of the

Environment (CCME), ISBN: 0-919074-85-5, 1992. Available at: http://www.ccme.ca/assets/pdf/pn_1072_e.pdf d EFF here is taken as the higher of EFF1 or EFF2: EFF1 = (3412 Btu/kW-hr × 100%) / (Actual Heat Rate at HHV in Btu/kW-hr), and, EFF2 =

EFFmfr × (LHV/HHV), where HHV and LHV are the higher and lower heating values of the fuel, EFFmfr is the manufacturer's continuous rated percent thermal efficiency of the gas turbine engine with air pollution control equipment in operation and using fuel LHV.

e Rule 425, Cogeneration Gas Turbine Engines, Kern Country Air Pollution Control District, Adopted August 16, 1993. Available at: http://www.arb.ca.gov/DRDB/KER/CURHTML/R425.HTM

f EFF in this case can be defined in several ways: (1) EFF1 = 3413 × (100% of the actual heat rate at the HHV of the fuel in Btu/kW-hr), (2) EFF2 = EFFmfr × (LHV/HHV), or (3) EFF3 could be defined as: (a) the demonstrated percent efficiency of the gas turbine unit only as calculated without consideration of any downstream energy recovery from the actual heat rate, corrected to the HHV (higher heating value) of the fuel, as measured at peak load for that facility, (b) the manufacturer's continuous rated percent efficiency (manufacturer's rated efficiency) of the gas turbine unit after correction from LHV (lower heating value) to the HHV of the fuel, whichever efficiency is higher, or (c) the value of EFF shall not be less than 25%; gas turbine units with lower efficiencies will be assigned as 25% efficiency for this calculation.

g Rule 1134, Emissions of Oxides of Nitrogen from Stationary Gas Turbines, South Coast Air Quality Management District, Adopted August 4, 1989 (Amended December 7, 1995; April 11, 1997; August 8, 1997). Available at: https://www.aqmd.gov/rules/reg/reg11/r1134.pdf

h Rule 69.3, Stationary Gas Turbine Engines - Reasonably Available Control Technology, San Diego County Air Pollution Control District, Adopted September 27, 1994 (Amended December 16, 1998). Available at: http://www.sdapcd.org/rules/Reg4pdf/R69-3.pdf

i Interim DECC Nitrogen Oxide Policy for Cogeneration in Sydney and the Illawarra, DECC 2009/124, Department of Environment and Climate Change NSW, ISBN: 978-1-74232-147-9, February 2009.

j Peak load refers to 100% of the manufacturer’s design capacity of the combustion turbine at ISO conditions. k Environmental Protection Agency 40 CFR Part 60, Standards of Performance for Stationary Combustion Turbines; Final Rule, July 2006.

Available at: http://www.epa.gov/ttn/atw/nsps/turbine/fr06jy06.pdf. l Directive 2001/80/EC on the Limitation of Emissions of Certain Pollutants into the Air from Large Combustion Plants, October 2001.

Available at: http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=OJ:L:2001:309:0001:0021:EN:PDF.




Figure 2: Comparison of NOx Emission Standards across Different Jurisdictions

The following subsections provide information on the official legislative documents that outline the emissions

standards for natural gas fuelled turbines and rationale for the standards. This includes information on whether

new regulations are currently being explored, whether standards are region-specific and which requirements for

monitoring are enforced.

3.2.2 Alberta Environment

The issue of turbines in Alberta has always been a complicated one. Randy Dobko, currently at Alberta

Environment and Sustainable Resource Development, was involved in the first emissions standards for gas

turbines: The National Emission Guidelines for Stationary Combustion Turbines (CCME, 1992). Mr. Dobko was

part of the working group, representing Alberta Environment at the time.

Ontario MoE

BC MoE

Alberta Environment

California ARB

Australia, NSW EPA

European Union

Jurisdictions

NOx Emissions Limit, mg/m30 20 40 60 80 100 120 140

MW

Rat

ing

0

20

40

60

80

100

NOx Emissions Limit, mg/m3200 250 300 350 400

100

200

300

400

500

600

0M

W R

atin

g

w/o SCR

all

new,w/o SCR

new,cogen,

w/o SCR

BCand

CARBwith

samelimits

new,w/ SCR

BC:w/ SCR

CARB:new,

w/ SCR

peaking units

all non-peaking units

units inoutlyingregions

new andexisting

units

all




In Alberta, the electricity generation sector and the oil sands sector have both shaped the province’s history of

turbines. Gas and electricity were both inexpensive until the end of the 1990s. In 2001, a coal-fired electricity

generation facility was built. A review of emission management in the utility sector was prepared as a result. This

led to a report by the Clean Air Strategic Alliance in 2003. They proposed gas turbine emission regulations that

were less stringent than those in available in the CCME turbine emissions guidelines and they wouldn’t consider

more stringent limits unless emission credit generation was to be possible. This introduced a system of emissions

trading within the electricity sector, known as the Emission Trading Regulation (Alberta Regulation 33 / 2006).

This regulation effectively provides an incentive for power stations to reduce NOx and SOx emissions prior to

mandatory improvements imposed by industrial approvals as outlined in the Environmental Protection and

Enhancement Act.

Mr. Dobko wrote a standards document in 2005 (coming into force in 2006). There are two complementary parts

to the document: “Alberta Air Emissions Standards for Electricity Generation” and “Alberta Air Guidelines for

Electricity Generation”. There were more stringent requirements (Policy 2) north of Ft. McMurray due to the large

presence of industrial activity in the oil sands.

There is a commitment at Alberta Environment to review emissions standards every 5 years to ensure that

standards don’t become dated. At the time of the first five year review, insofar as the question of “what are

appropriate emissions standards?”, the Canadian Association of Petroleum Producers, several utilities, the

government, and other stakeholders could not agree on matters. This disagreement greatly slowed down

progress towards the development of the current emissions standards. The Canadian Association of Petroleum

Producers, the refiners, and chemical producers did not agree on emission standards based on the use of

selective catalytic reduction (SCR) as a form of the Alberta BATEA (best available technology economically

achievable) requirement.

The 2010 review is actually somewhat dated, since turbines have evolved quickly. The Clean Air Strategic

Alliance had produced a 5-year review report and this is available online. A relevant report on cogeneration

technology has been produced by Jacobs Consultancy; this is available online on this website:

http://www.casahome.org/DesktopModules/Bring2mind/DMX/Download.aspx?EntryId=566&Command=Core_Do

wnload&PortalId=0&TabId=145

Alberta now has various guidelines/standards (both existing and proposed) on gas turbine use. The Air Quality

Management (AQMS) Base Level Industrial Emission Requirements (BLIERs) review is finished but it doesn’t fully




address Alberta standards going forward as their requirements are already more stringent. There are GHG

requirements for turbines being contemplated by Environment Canada.

For Continuous Emission Monitoring System (CEMS) requirements, facilities >25 MW must have a CEMS in

place for NOx and record other stack parameters (e.g., moisture, flue gas opacity, etc.). Facilities <25 MW

typically require 1–2 manual stack surveys per year.

There is a precedent for the successful use of SCR in Alberta: it’s used in a power plant in east Edmonton, in a

power plant north of Calgary, and at a nitric acid plant southeast of Calgary. As far as length of time between

approvals for industrial facilities, that is typically 10 years. There is no substantial grandfathering of previous

permits (and this is definitely not the case for turbines as the Alberta fleet is relatively young, unless the specific

turbines are low-use as in peaking operations). To clarify how the BATEA works: Alberta Environment sets the

standard; it doesn’t directly dictate the technology to be used. The standard is set strategically to allow for several

combinations of turbine and associated emission controls to meet BATEA. The final choice of technology would

be decided by a proponent.

3.2.3 Australia

3.2.3.1 Western Australia

In the state of Western Australia, power generation is prescribed under the Western Australian Environmental

Protection Regulations (1987) and such facilities will require a works approval for construction and a license to

operate if they have a design capacity of 20 MWe or more. There are a number of licensed gas turbines currently

in operation in Western Australia. At the time of writing, the Western Australia licensing system is undergoing a

modernization process since the current system does not produce consistent licenses for similar processes. As

an example, a gas turbine license in one region may have different conditions than one issued in another region.

The Western Australia EPA is in the process of introducing template licenses and developing better procedures

for assessing applications. The ultimate aim is to set consistent licenses with the same or similar emission limits

and controls across industry sectors.

Currently there are no Western Australia State technical guidance notes for industry sectors. Licensing officers

may refer to any relevant Australian or international industry sector guidance notes to assess license and works

approval applications, such as EU BREF notes (available at http://eippcb.jrc.es/reference/), the US EPA, and UK

sector guidance. There are currently no changes to the current standards, guidelines, or directives being

investigated.




Licenses to operate natural gas fuelled turbines can specify emission limits, target limits, and associated

monitoring. However, at the moment, the currently issued licenses are likely to be inconsistent in what they

specify. There are some location-specific air quality criteria and the current licensing system tends to consider the

ambient air quality primarily. So, if a particular application demonstrates that the local air quality standards are

being met, the licensing officer will likely not push for tighter emission standards. This practice is set to change

under the new system and licensing officers will need to consider whether the technology and emissions are in

line with best practice, which the Western Australia Environmental Protection Act 86 does require.

3.2.3.2 New South Wales

There is a recent document published by the Department of Environment and Climate Change (DECC) New

South Wales (NSW) entitled Interim DECC Nitrogen Oxide Policy for Cogeneration in Sydney and the Illawarra

that explains the policy requirements for all new cogeneration projects. Essentially these regulations for these

geographic zones stipulate that new cogeneration projects shall:

• have no adverse impact on human health or the environment in accordance with the requirements of the

Approved Methods for the Modelling and Assessment of Air Pollutants in New South Wales

• be NOx neutral or required to achieve best available technique (BAT) emission performance

An objective of no net increase in emissions from new NOx sources would greatly assist in meeting the clean air

standards. The policy allows the flexibility to choose the least cost approach between implementing best available

techniques or by offsetting their NOx emissions through abatement actions.

This policy extends the related policy in Action for Air (1998) which stated that “for greenfield sites, the EPA will

seek emission limits consistent with best available control technology, dependent on an economic impact analysis

of the cost of achieving these limits.” Proposals can be NOx neutral by either operating within existing approved

capacity for NOx emissions, and/or achieving an equivalent emission reduction off-site.

New cogeneration proposals outside of these geographic zones are required to meet the Protection of the

Environment (Clean Air) Regulation 2002 NOx emission limits of 70 mg/m3 for gas turbines.

3.2.3.3 Queensland

In Queensland, regulators rely on the emission concentration standards contained in the New South Wales and

Victorian legislation. Also, as in New South Wales, there is no intention to change the current standards,

guidelines, or directives with regard to combustion turbine emissions.




While specific emission control technologies are not officially recognized as part of the current emission standards

for natural gas fuelled combustion turbine generators, information regarding specific control technologies is

usually provided with an application and is project-specific. There is a requirement for project applications to

demonstrate that those control technologies proposed will result in compliance with the relevant emission

standards.

Monitoring and reporting requirements in Queensland are developed on a project-specific basis as part of the

approval-to-operate process. There are no special geographic zones: standards are applied state-wide.

3.2.4 Ontario Ministry of the Environment

Denis Maftei was involved in the first emissions standards for gas turbines: the National Emission Guidelines for

Stationary Combustion Turbines (CCME, 1992). Denis was part of the working group, representing MoE Ontario.

MoE Ontario implements the CCME 1992 regulations. There is also a relevant electricity sector regulation: EPS-

PG7.

For >25 MW facilities, there are stack monitored CEMS limits for NOx and SOx. The facility bears the costs for

capital and maintenance of the CEMS system. For <25 MW facilities, they simply follow the guidelines and there

is no mandatory reporting. For any facility, regardless of size, the implementation of CEMS is carried out by the

facility. If any facility is presumed to emit higher than expected an investigation may result. There is a site-by-site

evaluation for approvals.

There have been issues with CO emissions, due to the way the regulation was initially drafted. The CO averaging

time is problematic (24 h). Originally, the legislation was drafted when turbines were mainly used in compressor

stations; now, there are many electricity generation facilities that use turbines. For electricity generation, starts

can occur multiple times a day, creating many spikes in CO emission levels. There is currently a single emission

limit (regardless of turbine size) of 57.3 mg/m3 for CO, which is essentially the same as the current British

Columbia limit of 58 (mg CO)/m3 that applies for turbines in BC that are >25 MW

There are no special zones/districts where regulations are different. Furthermore, there are no GHG requirements

for turbines, certainly nothing equivalent to the Alberta Environment standard.




3.2.5 US Environmental Protection Agency

The US EPA had issued requirements to reduce toxic air emissions from stationary combustion turbines (August

29, 2003). These requirements apply to natural gas fuelled turbines (amongst other turbines that use other fuels)

used at facilities such as power plants, chemical and manufacturing plants, and pipeline compressor stations.

The EPA is not only concerned with the criteria air contaminants. The final rule serves to reduce emissions of a

number of toxic air pollutants such as formaldehyde, toluene, acetaldehyde, and benzene. These air toxics are

known or suspected to cause adverse health and environmental effects. This rule limits the amount of air pollution

that may be released from exhaust stacks of any new stationary combustion turbine (built after January 14, 2003).

It is important to note that existing turbines do not have to meet the emission limitations.

Based on the emissions levels achieved by the best-performing facilities, the EPA can identify air toxics controls

to adhere to the requirements of the Clean Air Act. The Clean Air Act requires the EPA to develop standards for

categories of facilities that emit one or more of 188 listed air toxics. Such standards require the applications of

stringent air emissions controls otherwise known as maximum achievable control technology (MACT), which are

applicable in select cases. To complicate matters somewhat, the baseline for controls is established differently for

new and existing sources. Regarding stationary combustion turbines, there was a lack of existing turbines in use

with controls. Thus it was difficult to establish a baseline level of control. The requirement for these facilities to

add controls that are required for new turbines was found to be cost prohibitive, thus no formal requirement to this

effect was made.

The EPA requires that facility owners or operators of turbines install carbon monoxide catalytic oxidation systems.

These systems serve a dual purpose: they can reduce carbon monoxide emissions, and, they can also reduce

emissions of air toxics such as benzene, toluene, formaldehyde, and acetaldehyde.

Since testing for CO emissions has many advantages over testing for emissions of hazardous air pollutants

(HAPs), most of the emission standards have been finalized in terms of CO as the only regulated pollutant. The

standards are applicable to existing engines, as separate regulations have been adopted to control emissions

from new stationary engines.

3.2.6 California Air Resources Board

Chris Gallenstein was contacted at the California Air Resources Board (CARB) to speak on the current emissions

standards related to turbine use. The NOx emissions limits imposed on gas turbines are possibly the most

stringent of any agency at the time of writing. There are several districts within California that have different rules




that limit turbine emissions. Several of these (e.g., South Coast Air Quality Management District, San Diego Air

Pollution Control District) are highly stringent and are presented in Table 4.

The California Statewide Best Available Control Technology (BACT) Clearinghouse is a database developed by

the Air Resources Board staff and staffs from various air pollution control and air quality management districts.

ARB staff manages the database under the direction of the California Air Pollution Control Officers Association's

Engineering Managers Committee and coordinates the submittal of BACT determinations made by the districts to

the U.S. Environmental Protection Agency. The database query page is available at:

http://www.arb.ca.gov/bact/bactnew/rptpara.htm

This database provides detailed information on emissions for approved facilities using natural gas fuelled

turbines. Table 5 provides a summary of projects that have been approved and their attendant emissions limits

that are made possible by the selection of the BACT.

The California Energy Commission (CEC) has exclusive statewide authority for the licensing of thermal power

plants (and related facilities) with a net generating capacity of at least 50 MW or more. The CEC's certificate

(license) is in lieu of any permit, certificate, or similar document required by any state, local, or regional agency to

the extent permitted by federal law. The site certification process is designed to eliminate duplication and

regulatory uncertainty. A request for an exemption from the application for certification process, referred to as a

small power plant exemption, can be filed for plants with <100 MW capacity.

For retrofitting turbines in present use there is a formal BARCT process (“best available retrofit control

technology”). BARCT is a state version of RACT, although its stringency is more akin to BACT as defined by the

federal Clean Air Act. BARCT is required under certain conditions in California districts having moderate, serious,

severe, or extreme air pollution. If the severity of state AAQS violations is serious to extreme, then the BARCT

process is required for all permitted stationary sources. Otherwise, the federal RACT process applies to facilities

emitting 5–250 US tons/year, and BARCT applies to facilities with >250 US tons/year of emissions.




Table 5: Summary of Turbine Technology, the BACT Applied, and the Emission Limits for Approved Projects Util izing Natural Gas Fuelled Turbines in California

Plant Name Capacity/ Dimension BACT Info Turbines

Used Equipment Function

Emission Limits @ 15% O2

NOx CO VOCsa PM

Combined(Cycle,(<50(MW(

Vernon(City(Light(&(Power(

43(MW(gas(turbine,(55(MW(steam(turbine(

SCR(system(and(oxidation(catalyst(

Alstrom(GTX100( Power(Generation(

2(ppmvd,(3.8(mg/m3(

2(ppmvd,((5.2(mg/m3(

2(ppmvd,(1.3–4.7(mg/m3(

353.1(mg/m3(

CP(Kelco(US( 3(turbines,(3(duct(burners,(3(boilers((up(to(10.3(MW)(

Addbon(and(Pollution(Prevention(

Solar(MARS(100(Tb15,000S(

Electricity(Generation,(Steam(Production(

28.6(ppmvd,(53.8(mg/m3(

100(tons/yr( N/A( N/A(

University(of(California,(San(Diego(

2(turbines,(each(12.984(MW(

Low(NOx,(SCONOX,(and(SCOSOX(

Solar(Titan(130S( Electricity(Generation(

2.5(ppmvd,(4.7(mg/m3(

5(ppmvd,(13.1(mg/m3(

N/A( N/A(

Applied(Energy(LLC( 42(MW(cogen(gas(turbine(

Addbon,(SCR( GE(LM6000PD( Power(Generation(

2(ppmvd,(3.8(mg/m3(

N/A( 2(ppmvd,(1.3–4.7(mg/m3(

N/A(

Qualcomm(Inc.( 4.37(MW(cogen(gas(turbine(

Addbon,(SoLoNOx(burners(

Solar(Mercury(50b6400R(

Electricity(Generation(and(Hot(Water(

5(ppmvd,(9.4(mg/m3(

N/A( N/A( N/A(

Grossmont(Hospital(

4.6(MW(cogen(gas(turbine(with(duct(burner(

Addbon,(SoLoNOx(burners(

Solar(Mercury(50b6400(R(

Power(Generation(and(Waste(Heat(


N/A( N/A( N/A(

Combined(Cycle,(>50(MW(

IDC(Bellingham(LLC(



GE(7FA( Power(Generation(

1.5(ppmvd,(2.8(mg/m3(


1(ppmvd,(0.7–2.4(mg/m3(

0.008(

Three(Mountain(Power,(LLC(

Two(gas(turbines,(one(steam(turbine(


GE(PG7241FA,((Westinghouse(501F(

Power(Generation(

2.5(ppmvd,(4.7(mg/m3(


2(ppmvd,(1.3–4.7(mg/m3(

42.4(mg/m3(@(3%(CO2(

Western(Midway(Sunset(Power(Project(



GE(F7A,((Westinghouse(501F(

Power(Generation(



1.4(ppmvd,(0.9–3.3(mg/m3(

N/A(







NOx CO VOCsa PM

Elk(Hills(Power(Project(



GE(PG7241FA( Power(Generation(

2.5(ppmvd,(4.7(mg/m3(


2(ppmvd,(1.3–4.7(mg/m3(

N/A(

Calpine(Corporation(

170(MW(gas(turbine,(160(MW(steam(turbine,(duct(burner(

Dry(lowbNOx(combustors,(SCR(system(and(oxidation(catalyst(

Westinghouse(501F(

Power(Generation(

2.5(ppmvd,(4.7(mg/m3(


1(ppmvd,(0.7–2.4(mg/m3(

11.5(lb/h(

Magnolia(Power(Project,(SCPPA(

181(net(MW(gas(turbine(w/(steam(injection(


GE(PG7241FA( Power(Generation(



2(ppmvd,(1.3–4.7(mg/m3(

353.1(mg/m3(

SMUD,(Clay(Station,(CA(

1611(MMBtu/h( Addbon,(SCR( GE(F7A( Power(Generation(



1.4(ppmvd,(0.9–3.3(mg/m3(

9(lb/h(

Otay(Mesa(Energy(Center(LLC(

171.1(MW( Addbon,(SCR( GE(F7A( Power(Generation(


N/A( 2(ppmvd,(1.3–4.7(mg/m3(

N/A(

Simple(Cycle,(<50(MW(

EI(Colton,(LLC( 48.7(MW( SCR((high(temp(SCR(catalyst)(

GE(LM6000((Enhanced(Sprint)(

Power(Generation(

3.5(ppmvd,(6.6(mg/m3(


2(ppmvd,(1.3–4.7(mg/m3(

353.1(mg/m3(

Lambie(Energy(Center(

49.9(MW( SCR(system(and(oxidation(catalyst(

GE(LM6000PC( Peak(Power(Electricity(Generation(

2.5(ppmvd,(4.7(mg/m3(


2(ppmvd,(1.3–4.7(mg/m3(

3(lb/h(

Indigo(Energy(Facility((Wildflower(Energy(LP)(

45(MW( SCR(system(and(oxidation(catalyst(

GE(LM6000((Enhanced(Sprint)(

Power(Generation(



2(ppmvd,(1.3–4.7(mg/m3(

353.1(mg/m3(

LA(Department(of(Water(and(Power(

47.4(MW( SCR(system(and(oxidation(catalyst(

GE(LM6000( N/A( 5(ppmvd,((9.4(mg/m3(


2(ppmvd,(1.3–4.7(mg/m3(

353.1(mg/m3(

CalPeak(Power(El(Cajon(LLC(

Total(49.5(MW(and(500(MM(Btu/hr(


Pratt(&(Whitney(FTb8(DLN(Twin(Pac(

Peak(Power(Electricity(Generation(

3.5(ppmvd,(6.6(mg/m3(

50(ppmvd,(131(mg/m3(

2(ppmvd,(1.3–4.7(mg/m3(

N/A(

Orange(Grove(Project(

49.8(MW( SCR(system,(water(injection,(and(oxidation(catalyst(

GE(LM6000( N/A( 2.5(ppmvd,(4.7(mg/m3(

N/A( 2(ppmvd,(1.3–4.7(mg/m3(

N/A(







NOx CO VOCsa PM

Escondido(Energy(Center(LLC(


GE(LM6000( Peak(Power(Electricity(Generation(

2.5(ppmvd,(4.7(mg/m3(

N/A( 2(ppmvd,(1.3–4.7(mg/m3(

N/A(

El(Cajon(Energy(LLC(


GE(LM6000PC( Peak(Power(Electricity(Generation(

2.5(ppmvd,(4.7(mg/m3(

N/A( 2(ppmvd,(1.3–4.7(mg/m3(

N/A(

a Conversion to mg/m3 units assumes a VOC molecular weight range of 16–58 g/mol (low and high bounds of range correspond to methane and butane, respectively).

There are notable contrasts between the federal and state-level approaches to stationary source regulation. One

of the key differences is that federal regulations are structured to regulate sources on a facility basis under site

specific permits for each facility. Most California districts issue individual permits for each process for the facility

such as a combustion turbine. A new facility and changes or additions to an existing facility requiring the issuance

of one or more new permit is evaluated as a project and the cumulative impact of several units composing a

project may trigger additional requirements beyond those triggered by any individual unit. Secondly, California

siting requirements address minor as well as major stationary sources. However, certain emissions units are

exempt from requirements for a permit.

There are two important consequences of these differences. First, minor sources are given permits in California.

The second is that permits are issued mostly on a unit basis rather than a facility- wide basis. As a result, more

sources are permitted in California than would otherwise be required under the federal permitting programs. Also

worth noting are the differences in operating permit programs. Prior to Title V requirements of the 1990 federal

Clean Air Act Amendments, the federal program had only required the issuance of a preconstruction permit.

Finally, federal construction permitting requirements address major new sources and major modifications (i.e., at

a facility- wide level).

In addition to permitting requirements, a new project siting in California must meet the requirements of the

California Environmental Quality Act (CEQA). The act requires an evaluation of any project that may have a

significant effect on the environment. It provides for the evaluation of the potential impact of new projects and the

identification of potential mitigation measures.




CEQA review is coordinated by a local or state agency with the broadest discretionary authority in approving the

project. Such a lead agency is usually a local land-use planning agency, such as a county planning department.

The lead agency is responsible for coordinating with a state-wide CEQA clearinghouse and responsible agencies,

which are defined as agencies which issue permits. By law, no agency is supposed to issue any permits until the

project has been approved by the lead agency.

3.2.7 European Union

Directive 2001/80/EC of the European Parliament and of the Council explains the limitations of emissions of

certain pollutants into the air from large combustion plants. That document, sometimes referred to as “the LCP

directive”, can be found at:

http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=OJ:L:2001:309:0001:0021:EN:PDF

The directive was put in place on October 23, 2001. The precursor to this particular directive is Council Directive

88/609/EEC (dated November 24, 1988) that also specifically deals with the limitations of emissions of certain

pollutants into the air from large combustion plants. The new directive was promulgated in the interest of

enhancing the clarity of the regulations. Notable in the text of the directive is the intent of the European’s

Community to reduce carbon dioxide emissions. It is stated that, where it is feasible, the combined production of

heat and electricity represents a valuable opportunity for significantly improving overall efficiency in fuel use.

Directive 2001/80/EC applies only to turbines used in combustion plants designed for production of energy (the

exception is those facilities that make direct use of the products of combustion in manufacturing processes). EU

emission limit values are defined for SO2, NOx, and dust.

3.3 Monitoring Requirements for Turbine Use

The following sections provide summaries of the monitoring and CEMS requirements for natural gas fuelled

turbines across several jurisdictions.

3.3.1 British Columbia Ministry of the Environment

Continuous emission monitoring of oxygen, NOx, CO, and ammonia, is required for gas turbines larger than 25

MW.




3.3.2 Alberta Environment

For natural gas fired or cogeneration power plants, continuous emission monitoring shall be required on the

stack for nitrogen oxides (NOx) and stack effluent velocity or flow rate in the effluent stream along with any other

parameters necessary to determine mass emissions. If the natural gas contains sulphur compounds, continuous

emission monitoring for SO2 may be required.

These technical requirements, along with performance specifications and use of equivalent methodologies such

as predictive emission monitoring systems are outlined in the Alberta Continuous Emission Monitoring System

(CEMS) Code. Any additional continuous emission monitoring parameters or contaminants or manual stack

surveys will be determined during the approval issuance phase and in consultation with Alberta Environment’s

Regional Approvals staff.

Typically, facilities >25 MW must have a CEMS in place and facilities <25 MW require 1–2 manual stack surveys

per year (pers. comm.). Also, ambient air monitoring in the vicinity of the power plant may additionally be

required. These requirements would be determined in consultation with Regional Approvals staff.

3.3.3 Ontario Ministry of the Environment

Ontario follows the CCME requirements for CEMS, where energy flows (e.g., fuel consumption, electricity and

shaft power, etc.) should be measured directly along with emissions. Operators should also regularly measure

fuel properties such as heating value and sulphur content. Non-peaking combustion turbine units >25 MW that

produce electricity require CEMS or a comparably effective method. For other units, emissions should be

monitored as required.

3.3.4 US Environmental Protection Agency

Within the text of EPA 40 CFR Part 60 (in particular, Subpart KKKK—Standards of Performance for Stationary

Combustion Turbines), there is a highly detailed section on the turbine user’s requirements for reporting. As the

official text is exhaustive, only a summary of the more important requirements will be provided here. Any turbine

user employing water or steam injection to control NOx emissions is required to install, calibrate, maintain and

operate a CEMS to monitor and record the fuel consumption and the ratio of water or steam to fuel being fired in

the turbine when burning a fuel that requires water or steam injection for compliance. Also, a CEMS can consist of

a NOx monitor and a diluent gas (i.e., O2 or CO2) monitor to determine the hourly NOx emission rate as ppm or

lb/MMBtu values. For those turbine units that comply with the output-based standard, a fuel flow meter should be




installed, calibrated, maintained, and operated to continuously measure the heat input to the affected unit.

Alternatively, a wattmeter (or several meters) should be used to continuously measure the gross electrical output

of the unit in megawatt-hours. For combined heat and power turbine units complying with the output-based

standard, the user should install, calibrate, maintain, and operate meters for useful recovered energy flow rate,

temperature, and pressure, to continuously measure the total thermal energy output in units of Btu/h.

The monitoring section of EPA 40 CFR Part 60 provides methodologies for demonstrating continuous compliance

for NOx emission standards if water or steam injection is not used as an emissions control technology. There is

guidance available here on the correct means for documenting a proper parameter-monitoring plan. To aid in the

turbine user’s continuous compliance in SO2 emissions, there are sections on: (1) determining exemption from

monitoring the total sulphur content of the fuel, and (2) gauging the frequency of tests for the sulphur content of

the turbine fuel.

Finally, EPA 40 CFR Part 60 provides information on which reports must be submitted to the EPA, the timing and

frequency of the reports, and which performance tests must be carried out (and which EPA methods must be

used for the specific tests).

3.3.5 California Air Resources Board

For cogeneration and combined cycle gas turbine units 2.9 MW and larger (continuous rating by the manufacturer

without power augmentation), the facility owner must install, operate, and maintain such turbines in calibration a

continuous in-stack NOx and oxygen monitoring system. The CEMS system must meet the requirements of the

regulation entitled 40 CFR Part 60, Appendix B. That document can be found at:

http://www.deq.state.or.us/aq/forms/sourcetest/appendix_b.pdf

Specifically, that appendix section has two specifications that need to be met: (1) Spec. 2 for NOx and (2) Spec. 3

for oxygen. Additionally, the 2- and 24-hour calibration specifications of Rule 218, and 40 CFR Part 60, Appendix

F need to be adhered to. Those documents can be found at:

http://www.aqmd.gov/rules/reg/reg02/r218.pdf

http://www.deq.state.or.us/aq/forms/sourcetest/appendix_f.pdf

In terms of the capabilities of the CEMS itself, it is required to have data gathering and retrieval capability that

meets the reporting requirements given in 40 CFR part 60.7(c), 60.7(d), and 60.13. Online resources for these

sections are found at:




http://www.gpo.gov/fdsys/pkg/CFR-2011-title40-vol6/pdf/CFR-2011-title40-vol6-sec60-7.pdf

http://www.gpo.gov/fdsys/pkg/CFR-2010-title40-vol6/pdf/CFR-2010-title40-vol6-sec60-13.pdf

This system shall include equipment that measures and records the following: (a) the flow rate of liquids or gases,

and, the ratio of water or steam to fuel added to the combustion chamber or to the exhaust for the reduction of

NOx emissions, and (b) the elapsed time of operation.

With regard to requirements for source testing, each facility must provide source test information that includes the

gas turbine unit’s exhaust gas NOx concentration, and the demonstrated percent efficiency (EFF). If the

demonstrated EFF cannot be obtained, the manufacturer’s rated EFF could be provided but only if the Executive

Officer of CARB determines that it is representative of the unit’s EFF. The gas turbine unit’s exhaust gas carbon

monoxide concentration must also be tested and recorded. The NOx and carbon monoxide concentration values

need to be reported in ppm by volume (ppmV), and corrected to 15% oxygen on a dry basis. The frequency of

source testing depends on the quantity of emissions for the unit being tested. If a turbine emits more than 25 US

tons of NOx per calendar year, source testing for that unit must be carried out at least once every 12 months. For

all other existing turbine units, source tests are required within 90 days after every 8,400 hours of the unit’s

operation.

3.3.6 European Union

EU Member states are required to take the necessary measures to ensure the monitoring of emissions from the

combustion plants covered by this Directive and of all other values required for the implementation of this

Directive. Member States may require that such monitoring shall be carried out at the operator's expense.

Member states need to take appropriate measures to ensure that the operator informs the competent authorities

within reasonable time limits about the results of the continuous measurements, the checking of the measuring

equipment, the individual measurements and all other measurements carried out in order to assess compliance

with this Directive

For new plants, the emission limit values shall be regarded, for operating hours within a calendar year, as

complied with if: (1) no validated daily average value exceeds the relevant figures set out in part B of Annexes III

to VII, and (2) 95% of all the validated hourly average values over the year do not exceed 200% of the relevant

figures set out in part B of Annexes III to VII. The ‘validated average values’ are determined as set out in point A.6

of Annex VIII, which is available at:




http://eur-lex.europa.eu/LexUriServ/LexUriServ.do?uri=OJ:L:2001:309:0001:0021:EN:PDF

Competent authorities shall require continuous measurements of concentrations of SO2, NOx, and particulate

matter (referred to as dust within the European context) from waste gases from each combustion plant with a

rated thermal input of 100 MW or more. There are certain cases where a CEMS is not required (such cases are

outlined in Annex VIII A(2)).

Continuous measurements shall include the relevant process operation parameters of oxygen content,

temperature, pressure and water vapour content. The continuous measurement of the water vapour content of the

exhaust gases shall not be necessary, provided that the sampled exhaust gas is dried before the emissions are

analyzed.




4 SCENARIO ANALYSIS

4.1 Description of Scenarios

Natural gas is used globally as clean fuel for power generation, home and restaurant cooking, feedstock for

petrochemicals and agricultural chemicals. In countries where there is an abundance source, natural gas is

generally delivered to the users using pipelines as limited by economic and physical limitations. In locations where

access to natural gas is constrained by terrain, waterways or ocean, natural gas can be liquefied to enable

delivery by conventional transportation methods via trucks, rails, or ships.

When chilled to –162°C at 1 atmosphere pressure, natural gas is in a form of liquid taking up 600 times less

space than the corresponding gas. There are many industrial processes for the liquefaction of natural gas

developed by companies such as Axens Liquefin, Black & Veatch, Conoco Philips, Foster Wheeler, Shell, and

Statoil/Linde. All of the processes require the natural gas be initially conditioned by removing the impurities prior

to liquefaction by refrigerant cooling, accomplished using compressors and expanders. There are many LNG

plants in the world with capacities vary from a few to 50 million tonnes per year (mtpa), located in Africa, Saudi

Arabia and various islands north of Australia. The total capacity of a large plant consists of many small trains of

LNG units, each operating independently. Common LNG train sizes vary from 1–8 mtpa as determined by the

compressor and driver capacities.

Based on publicly available information, a 20 mtpa LNG plant could be representative of several proposed plants.

If the LNG plant capacity is assumed to be 20 mtpa, it would most likely consist of 4 × 5 mtpa train-units or other

configurations and each train would use electric motors or CT drivers to power the compressors. The economic

and technical evaluations of driver selection are extremely complex with numerous process and technical

variables that are beyond the scope of this report. Thus, this section of the report discusses only the potential

differential NOx emission discharges from a 20 mtpa LNG plant resulting from using electric motors or CT drivers

to power the compressors. For the comparison, due to high demand at the LNG plant, it is assumed that the

electric power is not available from the grid and will have to be generated from a dedicated power plant in the

vicinity to avoid any significant impact on the existing transmission lines.




4.2 Comparison of NOx Emissions from Electric and CT Drives

As natural gas is considered to be a clean fuel, a combined cycle combustion turbine (CCCT) power plant of

common configuration has been selected in this analysis to supply the electric power to power the compressors in

the LNG plant. This CCCT would consist of 2 GE-7FA CTs x 2-HRSGs x 1 steam turbine generator with net plant

thermal efficiency of 58.5% and net output of 647.8 MW as published in Gas Turbine World – 2012 for

performance at ISO ambient conditions. During periods of one (1) CT on maintenance, the plant can be operated

at 50% load to drive half of the LNG trains. There are numerous CCCT plants in the US that utilize the GE-7FA

CTs as the prime movers. In Canada, CCCT plants with this CT include Becancour, Brighton Beach, Portlands

Energy Centre, Goreway and St. Clair Energy Center.

Based on the article “Reducing LNG Costs by Better Capital Utilization” (Nan Liu et al.), for an LNG train size of

3–3.5 mtpa, the specific power consumption is in the range of 235–310 kWh electricity per tonne of LNG.

Similarly, a report entitled “All electric LNG plants” by ABB suggests that power consumption is estimated to be 32

MW per 1 mtpa of LNG capacity, which translates to 264 kWh per tonne of LNG with the plant operating at 94%

availability. For sake of simplicity, a round number (270) near the mid-range of specific power consumption was

used for the calculation.

For CCCT power plants to generate greater than 550 MW net output, CTs with capacity range from 180–300 MW

are generally selected as prime movers. These CTs are equipped with dry low NOx combustors capable of

meeting 47.0 mg/m3 of NOx, with some achieving a limit of 28.2 (mg NOx)/m3. For this comparison, the calculation

of NOx emission is based on 28.2 mg/m3 from the CT with no SCR implementation and 4.7 mg/m3 with SCR. It is

envisaged that for a power plant installation where the air quality inside the airshed exceeds the ambient quality

guidelines, an SCR implementation would be required. Based on the present capability of CT drivers, NOx

emission of 28.2 mg/m3 is assumed.

Support for a 20 mpta LNG plant could consist of 4 trains with each of 5 mpta capacity. There are various

configurations of LNG process trains, with different requirements for driver sizes and quantities. A typical

configuration could be one driver per compressor, required for each of the three heat exchanger sections

(methane, ethylene, and propane). Another configuration might utilize a twin 60%-line to form one train, which

would require six compressors and associated drivers. There are also configurations that would use one large

driver to drive multiple compressors. For a specific LNG project, the final configuration will be selected based on

the company’s proprietary process, energy usage and optimization, air pollutant emission limits, the required plant

production, and the plant availability/reliability. A feasibility study would constitute a substantial effort, costing




many millions of dollars and thus not part of this report. Instead, a simplified generic methodology based on a

single driver/compressor section is used to conduct the evaluation. For this NOx emission comparison, the power

plant’s net thermal efficiency is assumed to be 58.5% with net output of 647.8 MW, based on a typical CCCT

configuration with 2 × GE-7FA.005 with 1 × GE-STG. For the CT drivers, one GE-7EA (frame machine) and one

GE-LM6000PF (aeroderivative machine) are selected to represent typical types of industrial CT drivers. For the

NOx emission comparison, which is conducted on a per kWh basis, only one CT driver/compressor section is

considered noting that a calculation using multiple identical drivers for the other remaining sections would yield

similar results. The assumptions and results are shown in Tables 6 and 7, respectively

Table 6: Summary of Assumptions Used for the Scenario Analysis

Item No. Description of Item Value Units Comments

1 Specific power consumption at driver shaft

270 kWh/tonne LNG

Round number near mid data range, basis for calculation

2 CCCT power plant thermal efficiency

58.5% LHV basis, data from Gas Turbine World 2012 GTW Handbook

3 CT driver thermal efficiency, typical 33.0% GE-7EA, suitable for a 5 mtpa LNG train, no SCR, no heat recovery

4 CT driver thermal efficiency, high 41.7% GE LM6000PF, for efficiency comparison purpose only, no SCR, no heat recovery

5 Efficiency from generator terminal to shaft

95.6% 4.4% losses from transformer, cabling, inverter, motor, drive coupling

6 Efficiency from CT-drive to shaft 99.0% 99.0%

GE-7EA LM6000PF

7 Total LNG production 20 mtpa




Table 7: Summary of Results from the Scenario Analysis


1 Specific NOx emission rate – CCCT, no SCR

0.167 g/kWh 28.2 mg/m3, kW includes 4.4% losses

2 Specific NOx emission rate – CCCT, with SCR

0.028 g/kWh 47.0 mg/m3 + 90% NOx reduction by SCR, kW includes 4.4% losses

3 Specific NOx emission rate GE-7EA GE-LM6000PD

0.281 0.225

g/kWh g/kWh

28.2 mg/m3 NOx emission. Based on net power output at CT-shaft, no SCR, kW includes 1% loss.

4 CCCT NOx unit emission rate, no SCR

45.18 g/t-LNG 28.2 mg/m3 NOx emission, based on unit LNG product

5 CCCT NOx unit emission rate, with SCR

7.54 g/t-LNG 4.7 mg/m3 NOx emission, based on unit LNG product

6 GE-7EA NOx unit emission rate GE-LM6000PF

75.93 60.79

g/t-LNG g/t-LNG

Based on unit LNG product

7 Total CCCT NOx emission, no SCR 904 t/y 28.2 mg/m3 NOx emission

8 Total CCCT NOx emission, with SCR

151 t/y 47.0 mg/m3 NOx emission

9 Total NOx emission – GE-7EA GE-LM6000PF

1,519 1,216

t/y t/y

10 Diff. NOx emission – CCCT GE-7EA GE-LM6000

0 615 312

t/y t/y t/y

Emission from CCCT plant (no SCR) is used as the reference base.

11 Diff. NOx emission – CCCT GE-7EA GE-LM6000

0 1,368 1,065

t/y t/y t/y

Emission from CCCT plant (with SCR) is used as the reference base.

As shown on Table 7, for a 20 mtpa LNG plant, the differential NOx emissions from using CT drivers would be

>300 t/y when compared to those of electric motor drives with electricity provided by a CCCT without SCR

implementation. If the electricity is supplied by a CCCT plant with SCR implementation, the differential NOx

emissions from the CT drivers could exceed 1,000 t/y. However, if heat recovery is implemented in the CT driver

system to generate electricity or for process use to offset the auxiliary loads, the specific NOx emission per unit




LNG would be similar to that from a CCCT power plant without SCR implementation. If SCR is also implemented

in the CT driver heat recovery system, depending on the configuration and utilization, the NOx emission could be

similar to that from the CCCT power plant.




5 LIFE CYCLE ASSESSMENT AND ENERGY EFFICIENCY BETWEEN

SCENARIOS

Emissions, energy consumption, and costs for the operation of an LNG facility until 2035 were modelled based on

the same LNG plant process for each scenario. Figure 3 provides an overview of typical flow diagram for an LNG

plant. Refrigerant compressors in the LNG plants are generally driven by CTs but many companies are evaluating

the use of electrical motors as the prime driver. When selecting the drive systems, there are numerous factors to

consider, such as technical risks, plant availability / reliability, efficiency, equipment delivery and costs. Many of

these factors are site specific and extremely complex to evaluate. This section of the report compares only

evaluated differential costs and emissions of the two driver systems, based on typical available data. The

estimated cost of natural gas is provided in Section 5.1 and the evaluation of differential costs of the two driver

systems is provided in Section 5.2.

Figure 3: Typical Process Flows for a Liquefied Natural Gas (LNG) Facility

Natural Gasfrom Pipeline

InletFacility

Acid GasRemoval Flare System

Dehydration Mercury Removal and Filtration

NGL ExtractionFractionation Fuel Gas &

BOG System

Liquefaction

Refrigeration

C5+ LPG toStorage or Fuel

RefrigerantMake Up

N2 Rejectionand End Flash

LNG Storage & Offloading




5.1 Projected Energy Costs

The National Energy Board has published a report entitled “Canada’s Energy Future: Energy Supply and Demand

Projections to 2035”. It provides model scenarios for a variety of energy sector parameters until the year 2035.

Data within the report are used for calculation of operating costs of the compressor drivers. Figure 4 provides a

graph of projected natural gas fuel costs until the year of 2035.

Figure 4: Projected Costs of Natural Gas until 2035

5.2 Evaluated Life Cycle Differential Costs

For the LNG plant, many different CT drivers can be configured to drive the refrigerant compressors. For this life

cycle analysis, the larger GE-7EA (low efficiency) and smaller GE LM6000PF (higher efficiency) are evaluated. In

addition, an electric motor system is also evaluated, which is complete with voltage conditioning and adjustable

speed drives required for starting and controlling of the compressor systems. Section 4.2 provides the rationale

for the parameters chosen for a 20 mtpa LNG plant consisting of 4 trains with each of 5 mtpa capacity. As also

discussed in Section 4.2, the electrical supply to the motor drivers is assumed to be generated by a CCGT power

plant. Capital costs are based on typical data as published in Gas Turbine World – 2012, with no consideration for

electrical transmission lines or site specific requirements. The effect of plant availability and reliability has not

been considered due to complexity and dependence on the actual specific equipment and plant operation. CCCT

and CT driver efficiencies are provided in Table 6 of Section 4.2 and assumptions for the analyses are given in

Table 8. Based on these assumptions, life cycle analyses were conducted for comparison of the utilizing the CT

and electric motor drivers to power the refrigerant compressors. Results are provided in Table 9.

US$/MMBtu

Year

0

2

4

6

8

10

12

2010 2015 2020 2025 2030 2035




Table 8: Summary of Assumptions Used for the Life Cycle Analysis


1 Unit cost of CT combined cycle power plant 1,200 $ / kWnet

installed Based on in-house data, adjusted for year 2013.

2 Total cost of CT combined cycle power plant 790 $ million Based on plant size

3 Cost of CT (GE-7EA) drivers 48 $ million Gas Turbine World - 2012, adjusted to include installation

4 Cost of CT (LM6000PF) drivers 27 $ million Gas Turbine World - 2012, adjusted to include installation

5 Maintenance costs, CCCT plant 2.5 pct % of total installed cost

6 Maintenance costs, CT drivers 2.0 pct % of total installed cost

7 Maintenance cost, electric drivers 0.5 pct % of total installed cost

8 Natural gas fuel costs Data obtained from the graph of Figure 4.

9 Plant life 20 years

10 Interest rate 5.5 pct

11 Discounted rate 5.5 pct Same as interest rate




Table 9: Life Cycle Analysis Results

Item No. Description of Item GE-7EA

Driver LM6000PF Driver

Electric Motor Driver Units

1 Estimated cost of CT combined cycle power plant

N/A N/A 790 $million

2 Power output of driver 85 43 85 + 3.4% loss MW

3 Estimated cost of driver 48 28 38 $million

4 Estimated total specific cost, applied at compressor shaft

0.054 0.048 0.039 + 0.003 = 0.042

$ / kWh

5 Capital cost portion 6.1 8.4 19.2 %

6 Fuel cost portion 91.9 88.9 73.1 %

7 O&M cost portion 2 2.7 7.7 %

8 Estimated differential total specific cost, applied at compressor shaft

0.012 0.006 0 $ / kWh

9 Estimated differential total specific cost, applied at compressor shaft, based on 270 kWh / tonne LNG

3.24 1.62 0 $ / tonne LNG

10 Estimated differential total cost, applied at compressor shaft, based on 270 kWh / tonne LNG and 20 mtpa

64.8 32.4 0 $M / year

As shown on Table 9, the electric motor driver option has the lowest total specific cost, even though it requires a

CCGT power plant to supply the electrical power. As a significant portion of the total specific cost is applicable to

fuel consumption, the driver efficiency has a significant impact on the final specific cost. As the analysis is based

on typical costs and that the differential costs are not extremely significant, the evaluated cost could be dependent

the specific project and the driver configurations. If a mechanical driver system is configured with heat recovery,

the evaluated differential cost could change significantly.

5.3 Evaluated GHG Emissions

An evaluation was conducted to determine the amount of CO2 generated per kWh for three different scenarios:




" using an electric motor (GE-7FA.005)

" using a CT with typical efficiency (GE-7EA)

" using a CT with high efficiency (GE-LM6000PF)

This evaluation used data from GT World 2012. Table 10 provides a summary of the data used and the results of

the CO2 estimates. The calculation is conducted on a specific energy basis (per kWh) to avoid the requirement to

compare all the compressor drivers at the same capacity rating. From the analysis, the electric motor option yields

the lowest amount of CO2 (367 g/kWh versus 480 g/kWh for the high efficiency CT and 597 g/kWh for the typical

efficiency CT). From these specific CO2 emission results, the total CO2 emission rates are calculated based on

driver energy consumption of 270 kWh / tonne LNG and 20 mtpa production. The relative emission ratios are

calculated using the emission rate of the electrical motor driver system as the base. As shown on Item 17 of Table

10, the ratios of CO2 generation from a GE-7EA driver (average efficiency, frame machine) and a GE-LM6000PF

driver (high efficiency, aeroderivative machine) are 1.6 and 1.3, respectively, indicating that there would be

significantly higher CO2 generation when using mechanical drivers. However these ratios can be reduced

significantly depending on implementation of heat recovery systems on the CT-drivers, which would contribute

towards overall LNG plant efficiency, thus displacing CO2 generation from other processes.

Table 10: Summary of Data Used for the Determination of CO2 Emissions for Three Different CT Scenarios

Item No. Description of Item Units

Value

GE-7FA.005 (Electric Motor)

GE-7EA (Gas Turbine)

GE-LM6000PF (Gas Turbine)

1 Gross power output (per CT) kW 215,769 88,718 43,068

2 Simple cycle efficiency pct 38.6% 33.5% 41.7%

3 Simple cycle heat rate kJ/kWh 9,326 10,746 8,633

4 Heat input to CT kJ/h LHV 2,012,353,368 953,387,463 371,810,072

5 Exhaust gas flow kg/h 1,869,388 1,051,429 448,653

6 Number of CTs used 2 1a 1a

7 Total heat input to all CTs kJ/h LHV 4,024,706,736 953,387,463 371,810,072




Item No. Description of Item Units

Value

GE-7FA.005 (Electric Motor)

GE-7EA (Gas Turbine)

GE-LM6000PF (Gas Turbine)

8 Total exhaust gas flow kg/h 3,738,776 1,051,429 448,653

9 Combined cycle efficiency (LHV basis) pct 58.5% 100.0% 100.0%

10 Combined cycle heat rate kJ/kWh 6,152 10,746 8,633

11 Total electrical power output kW 654,211 88,718 43,068

12 Total CO2 generated kg/h 221,709 52,466 20,459

g/kWh 339 591 475

13 Adjustment factor for energy losses 0.922 0.990 0.990

14 Total specific CO2 generated at the equipment shaft g/kWh 367 597 480

15 Total specific CO2 generated at the equipment shaft, at 270 kWh / tonne LNG

kg / tonne LNG 99.1 161.2 129.6

16 Total CO2 generated at the equipment shaft, at 270 kWh / tonne LNG and 20 mtpa

M tonne / year 1.98 3.22 2.59

17 Ratio of CO2 generated 1.0 (base) 1.6 1.3

a As stated in Section 4.2, only one driver/compressor section is considered for calculation as the results are based on per unit energy (kWh).




6 RECOMMENDATIONS

In terms of what emissions limit could be realistically set for NOx, the permitted facilities in California serve as

potential models since their approvals were subject to a more stringent review processes than other jurisdictions

with regard to the choice and application of BACT. As part of the California BACT process, all new combined

cycle turbine facilities must not exceed an emissions limit of 3.8 mg/m3 (2 ppm), and, for simple cycle, the limit is

4.7 mg/m3 (2.5 ppm). Thus, emissions limits in California are more stringent than the other jurisdictions reviewed.

By contrast, the EU regulations limit NOx for new natural gas fuelled turbines in the size range of 50–500 MWh at

the 301 mg/m3 level, which is a substantially higher limit than most of those imposed for existing facilities in

California, which are in the 17–79 mg/m3 range. With the use of SCR or SCONOx emissions controls, the

achievable NOx emissions from most turbines (depending on turbine size) would be less than 5.6 mg/m3 (since

uncontrolled emissions of commonly 47.0 mg/m3 for many turbines will be reduced by 90% or more). The use of

SCONOx technology allows for a large reduction in NOx, CO, and VOC levels (with an additional 30% reduction in

fine particulate matter), and no possibility for ammonia slip as in SCR, but with a significant cost penalty.

Upon reviewing the permitted facilities in the state of California (Table 5), combined cycle emission limits for NOx

are typically in the range of 2.8–4.7 mg/m3 for >50 MW facilities and 3.8–16.9 mg/m3 for <50 MW facilities. For

simple cycle emission limits, all of the facilities listed in Table 5 have emissions limits NOx in the range of 4.7–9.4

mg/m3.

As the California facilities consistently have emissions limits that are very low, emissions regulations from one of

the more stringent California air quality management districts could ideally be adapted for use in British Columbia

to become a leading jurisdiction in this regard. While stringent, the attainment of such emissions limits is

increasingly common across several US states for new natural gas turbine installations. As is common, emissions

limits should be applied differently to turbines of varying output levels.

6.1 Basis for Emissions Limits for New Turbines

Rule 1134 for the South Coast Air Quality Management District of California (largely consisting of Los Angeles

County) provides a model for applying emissions levels based on the demonstrated efficiency (denoted as ‘EFF’)

of the turbine. The rule was first adopted on August 4, 1989 and amended three times since then (December 7,

1995; April 11, 1997; and August 8, 1997). While the emissions limits for this district are stringent, we feel that the

rules regarding the turbine efficiency (which essentially provide slightly higher emissions limits for more efficient




turbines) are complex and likely unnecessary since modern turbine technology is both efficient and many models

ship with DLN/DLE. These regulations were initially drafted when turbines were significantly less efficient than

they are currently (i.e., few of the turbines presently available from vendors have less than 25% efficiency).

Therefore, the use of an equation to determine emissions limits in a particular MW group will not be

recommended. We instead recommend that a simple table of emissions limits based on (1) the size of the turbine,

and (2) whether SCR/SCONOx is to be applied.

6.2 Divisions of the Turbine MW Rating Classes

The divisions of the turbine MW rating classes are recommended to be:

(1) 1 to less than 4 MW

(2) 4 MW to less than 50 MW

(3) Greater than or equal to 50 MW.

The greater than 50 MW class coordinates with the environmental assessment trigger under the BC

Environmental Assessment Act for power generation. The emissions limits should apply on a per-turbine (i.e., not

facility) basis. Table 11 compares the divisions in the MW rating classes from the current regulations drafted in

1992 and these proposed divisions.

Table 11: Comparison of the Current and Proposed Divisions in the Turbine MW Classes for Emissions Limits

In Current (1992) Emissions Standard In Proposed Standard

— 1 MW to <4 MW (per turbine)

>3 to ≤25 MW (per facility) 4 MW to <50 MW (per turbine)

>3 to ≤25 MW (per facility), >25 MW (per facility)

4 MW to <50 MW (per turbine)

>25 MW (per facility) ≥50 MW (per turbine)

6.3 Requirements for Implementation of SCR/SCONOx

When considering whether emissions controls (generally SCR or SCONOx) are mandatory for new turbines,

reviews on proposed installations on a case-by-case basis will likely work best. However, the following two key




considerations could serve to address the issue of whether to require the use post-combustion emission controls

for a new turbine:

(1) Is the location of the proposed gas turbine within a compromised airshed region of British Columbia?

(2) Will the proposed gas turbine impact the local air quality of nearby populations?

To address the first criterion, a separate process must occur for determining and formalizing the boundaries of the

compromised airsheds. For the second consideration, the logic is such that a turbine very close to a large

population will likely adversely affect the air quality for those nearby areas, especially if the proposed turbine is to

have a large output. The recommended process for determining the air quality impacts for nearby populations is

through dispersion modelling analyses with the expected emissions activity and stack parameters.

6.4 Proposed NOx Emissions Limits for New Turbines

The proposed NOx emissions limits for new turbines are summarized in Table 12.

Table 12: Current and Proposed NOx Emissions Standards for New Natural Gas Fuelled Turbines

Size of Turbine Unit

Current Emissions Standard

Controlled Emissions after Application of SCR/SCONOx (Proposed)

Uncontrolled Emissions Without Application of SCR/SCONOx (Proposed)

1 MW to <4 MW

no standard High Stringency: 5 mg/m3 NOx

Lesser Stringency: 10 mg/m3 NOx High Stringency : 30 mg/m3

Lesser Stringency : 50 mg/m3 NOx

4 MW to <50 MW

80 mg/m3 (for >3 to ≤25 MW facilities), 17 mg/m3 (>25 MW facilities), 48 mg/m3 (>25 MW facilities,

no SCR)



≥50 MW no standard



If the new turbine is required to be controlled by SCR/SCONOx, most implementations of SCR and SCONOx are

very effective at reducing NOx to levels that are 90–95% lower than without that control measure in place. This

should result in emissions that are below 5 mg/m3 NOx for turbines that emit uncontrolled NOx at either 28.2

mg/m3 (15 ppmv) or 47.0 mg/m3 (25 ppmv). This is provided as a ‘high stringency’ recommendation. Should a




lesser stringency limit be necessary, we have recommended that the limit be raised to 10 mg/m3 NOx. These

limits for the SCR case apply to all size classes of new turbines.

In the case that the facility owner is not required to operate turbines with SCR/SCONOx, we recommend two sets

of emissions limits (‘high stringency’ and ‘lesser stringency’ recommendations). These limits are based on the

manufacturer-stated emissions limits for modern turbines (i.e., running ‘uncontrolled’ with DLN), which are either

28.2 mg/m3 (15 ppmv) or 47.0 mg/m3 (25 ppmv) regardless of the size of the turbine unit. In the technology review

portion of this report, it was evident that most modern turbine technology had either of the two emissions limits so

long as DLN was implemented. However, only a limited number of available turbines can meet the high stringency

NOx emissions limit of 30 mg/m3. Some examples of turbines emitting <28.2 mg/m3 are those from GE (MS6001

(B) and MS7001 (EA) direct drive; LM2500PJ, LM6000PF, and LM6000PF SPRINT simple cycle), Mitsubishi

(M501DA and M501 simple cycle; MPCP1 and MPCP2 combined cycle), and Siemens (SGT6-5000F simple

cycle; SCC6-5000F combined cycle). The lesser stringency recommendation of 47 mg/m3 would presently allow

the use of almost all of the turbines reviewed in the technology section of this report (i.e., those turbines with

DLN).

As a separate consideration, if the facility owner is not required to use SCR/SCONOx (e.g., the proposed turbine

will reside in a remote region) but cannot meet the emissions guidelines with the proposed turbine technology, the

owner can either (1) use a different turbine that has a demonstrated efficiency and uncontrolled emissions level of

NOx that meets the uncontrolled emissions limit for the size of turbine, or (2) use the originally proposed turbine in

conjunction with an emissions control technology such as SCR or SCONOx and adhere to those emissions

guidelines specific to SCR/SCONOx use. It is envisaged in this case that the selection of the turbine technology

will drive adoption of turbines that emit lower amounts of NOx without additional emissions controls. Emission

limits here would thus be more technology than rule (as above) driven. However, if the high stringency limits for

the non-SCR/SCONOx condition were to be applied, it would either:

(1) drive turbine users to use the available turbine technology with emissions limits of 28.2 mg/m3 (15 ppmv)

(2) drive manufacturers to ship 28.2 mg/m3 (15 ppmv) implementations of more of their turbines (across more

sizes and classes of turbines)

(3) drive the use of SCR/SCONOx in non-compromised airshed regions

The first scenario is most likely for many applications, however, turbines used for compressor stations along

natural gas pipelines will likely emit NOx greater than 28.2 mg/m3 (15 ppmv). Given that the bulk of compressor




stations are located in remote areas (i.e., not within compromised airsheds), these turbines should be treated

independently.

If SCR/SCONOx is determined to be required, the allowable ammonia slip from the SCR should be limited to 3.5

mg/m3, which is achievable for many SCR applications. The required SCR efficiency should be based on

reasonably achievable level when operating within the maximum allowable ammonia slip. In compromised airshed

regions where any additional emissions of NOx, CO, VOC, SO2, NH3, or PM10 could have adverse effect on air

quality, the use of SCONOx should be evaluated.

The emissions limit for carbon monoxide should be set to 57 mg/m3 regardless of the location and of the size of

the turbine. Many new turbines can meet this emissions limit. While this could potentially be set lower, the use of

emission control technologies such as SCONOx and catalytic oxidation (while available and able to reduce CO

levels below this limit) still carry significantly high costs.

Many jurisdictions do not impose an SO2 standard on natural-gas fuelled turbine emissions. This is

understandable because natural gas contains an extremely small amount of organically bound sulphur. Hence,

we do not recommend that an emissions regulation for SO2 be formally implemented.

6.5 Review of Existing Turbines

Existing turbines are generally subject to a permit review process process after a specified interval of time or a

major equipment change. Since turbine technology is advancing at a steady pace, it is recommended that a

formal review of the availability and feasibility of retrofitting options be carried out by the facility owner as part of

the permitting review process. Retrofits bring about the immediate advantage of increased emissions reductions,

and the retrofitting process also allows for older turbines to be brought more in line with the lower emissions

afforded by modern turbine technology. We recommend that the review process be mandatory for every 5 years.

Furthermore, a major change in turbine equipment should trigger the review process in the intervening period. It is

important that BCE provide clear definitions as to what equipment changes would bring about such a review and

potential upgrade, and the circumstances where the new criteria may supercede existing permit levels. For

instance, a turbine exchange should likely not trigger such a review, but a major permit amendment could. Some

analysis of operator behaviour needs to be undertaken so that such reviews trigger only when appropriate.

This recommendation is similar in concept to the US EPA RACT and California ARB BARCT processes. As in the

case with BARCT, it is important to first determine whether the existing turbine resides in a compromised airshed




region, or, if its emissions have a significant impact on local air quality. The determination as whether air quality

impacts are significant is best determined through dispersion modelling analyses.

The existing fleet of compressor stations in BC in the oil and gas sector is of considerable size, thus the potential

investment this might represent to industry needs to be better defined to create a clearer risk vs. benefit

understanding. Such an analysis was not part of the scope of this work. Additionally, different permits have

different review periods and review triggers. Prior to implementing a retrofitting requirement, it is recommended

that BC develop a structured risk analysis approach whereby proponents are made aware of what operational

changes trigger such a review, and having entered a facility review, are then not immediately faced with a

significant investment without a clear rationale to justify the requirement.

6.6 Monitoring Requirements

Facilities with turbine output greater than 25 MW and residing in a compromised airshed region should have an

implementation of continuous emission monitoring systems (CEMS) for standard effluent parameters and NOx. In

compromised airshed regions, turbines with output less than 25 MW are only recommended to implement a

predictive emissions monitoring system (PEMS). PEMS technology is more affordable and easier to implement

but, by its nature (model versus measurement), is perceived as less sensitive to reporting some emission upsets.

The requirement for initiation of CEMS and PEMS should extend to existing turbines that are to be re-permitted,

but this need during retrofitting should be assessed by the structure risk benefit assessment discussed above.

Table 13 provides recommendations on whether facilities are required to CEMS, PEMS, or neither based on the

size of the turbine unit.

Table 13: Recommended Monitoring Requirements for Turbines Based on Size Class and Location

Size of Turbine Unit Monitoring Requirement for Turbine Residing in a Compromised Airshed Region

Monitoring Requirement for Turbine Outside of Any Compromised Airshed Region

1 MW to <4 MW

Not Required Not Required

4 MW to <50 MW

PEMS for turbines up to 25 MW, CEMS for turbines up in 25–50 MW range

CEMS for turbines up in 25–50 MW range

≥50 MW CEMS CEMS




With regard to the management of CEMS and PEMS data, all facilities should maintain all raw data from these

monitoring systems. The increased use of PEMS creates an additional data management requirement of both the

operator and regulatory staff. However, we understand that the Ministry of the Environment reserves the right to

request and inspect the data, and, enlist the cooperation of the facility staff to carry out the inspection process

therefore for ‘low risk’ facilities, such information can be collected and maintained in a form and frequency, as

dictated by the Ministry, by the operator pending inquiry by ministry staff or available for facility audit.

6.7 Further Studies

Should there be an inclination to divide emissions limits by SCR/no-SCR according to whether the turbine resides

in a sensitive airshed, consideration should be given toward formalizing the boundaries of the regional airsheds.

The demarcation of such boundaries (if not recently established, even informally) will perhaps be a large

undertaking and will have some bearing on other air quality initiatives. However, this is important for determining

an important aspect of the BARCT process.

Another area for study deals with creating a rule framework. There needs to be some focus on the development

of a decision framework for application of appropriate control technologies and the trigger process for such

considerations at both new and existing facilities.

The incorporation of an emissions trading scheme could involve a separate study that investigates the practices

and outcomes of such a system. There may be a large administrative cost to creating and maintaining such an

entity, and the advantages/disadvantages of such a program to both BC air quality and the industrial sector are

currently unclear.

Finally, the development and management of consistent PEMS output (versus standard comparisons) for the

purpose of reporting (specific to for natural gas turbines) and maintaining auditable information would serve as a

useful study.




Appendix+A+Table A-1: Comparison of Vendor-Supplied Parameters for Mechanical Drive Turbines

Combustion Turbine Vendor/Model

Emis. Model

Emissions Control Method (BACT)

Emissions (Corrected to 15% O2), Units of ppmV and kg/hr Engine Specifics

Water Inj.

Steam Inj. DLN NOx CO PM UHCs

Power at 100% MCR, MW

Eff. At 100% MCR

RPM Min.

Cont. Load

Eff. At Min. Cont. Load

GE

MS6001 (B) 9, — 25, — — — 43.5 33.3% 5111 — —

MS7001 (EA) 9, — 25, — — — 86.2 33.0% 3600 — —

MS9001 (E) 9/25, —

25/25, — — — 130 34.6% 3600 — —

P & W

FT8-3 / 60 MW × × 25, – 60, – — — 61.0 37.0% 3600 9.15 —

FT8-3 / 30 MW × × 25, – 60, – — — 30.5 37.0% 3600 7.63 —

Rolls-Royce a

RB211-G62 Std. 222, 107

25.9, 7.6 TBC TBC 29.1 36.7% 4800 N/A N/A

RB211-G62 DLE DLE × 25,

9.48 20.5, 5.87 TBC TBC 27.9 36.2% 4800 12.3 25.0

RB211-GT62 Std. 222, 107

25.5, 7.82 TBC TBC 30.2 37.4% 4800 N/A N/A

RB211-GT62 DLE DLE × 25,

9.89 16.5, 5.03 TBC TBC 30.6 37.2% 4800 13.5 26.4

RB211-GT61 Std. 261, 137

24.1, 7.7 TBC TBC 33.7 39.2% 4850 13.5 26.4


9.88 14.5, 4.53 TBC TBC 32.1 38.9% 4850 14.5 27.7

RB211-H63 Std. TBC TBC TBC TBC 37.9 39.0% 6000 TBC TBC





Emis. Model



Water Inj.



Eff. At 100% MCR

RPM Min.

Cont. Load


RB211-H63 WLE Std. × TBC TBC TBC TBC 44 40.0% 6000 TBC TBC

Trent 60 DLE DLE × 25, 1.86

7.0, 3,3

6.1b, 2.27

1.4, 1.0b 52.5 42.2% 3400 25.8 30.7

Trent 60 DLE ISI DLE × 25,

20.6 7.3, 3.8

5.5b, 2.27

1.5, 1.0b 58 42.7% 3400 25.9 30.8

Trent 60 WLE Std. × 25, 22.3

38.8, 21

5.2b, 2.27

15.5, 11.1b 59 41.7% 3400 42.3 39.7

Trent 60 WLE ISI Std. × 25,

24 45.8, 26.8

4.8b, 2.27

18.3, 13.1b 64 42.0% 3400 34.0 36.4

Solar

Saturn 20 100, 3.3 50, 1 0.018,

0.15 25, 0.3 1.2 24.3% 22300 0.9 23.3%

Centaur 40 × 25, 2.1

50, 2.6

0.018, 0.4

25, 0.7 3.5 27.9% 15500 1.7 19.8%

Centaur 50 × 25, 2.6

50, 3.2

0.018, 0.5

25, 0.9 4.6 29.9% 16500 2.3 21.7%

Taurus 60 × 25, 3.1

50, 3.7

0.018, 0.6

25, 1.0 5.7 31.9% 13951 2.9 22.0%

Taurus 70 × 25, 3.3

50, 4.8

0.018, 0.7

25, 1.4 8.1 35.2% 11692 4.1 24.9%

Mars 90 × 25, 5.0

50, 6.2

0.018, 0.9

25, 1.8 9.9 33.2% 8779 4.9 23.2%

Mars 100 × 25, 5.8

50, 7.1

0.018, 1.0

25, 2.1 11.5 33.3% 9131 5.9 23.5%

Titan 130 × 25, 7.1

50, 8.7

0.018, 1.3

25, 2.5 14.8 35.1% 8403 7.7 24.5%

Titan 250 × 25, 9.5

50, 11.6

0.018, 1.7

25, 3.3 22.4 40.0% 6300 9.0 25.9%

a Rolls-Royce notes: (1) TBC (to be confirmed) refers to information that can only be provided on a case-by-case basis, (2) efficiency at minimum continuous load means while not exceeding NOx of 25 ppmv and CO of 50 ppmv.

b In units of mg/Nm3.




Table A-2: Comparison of Vendor-Supplied Parameters for Simple Cycle Drive Turbines


Emis. Model



Water Inj.



Eff. At 100% MCR

RPM Min.

Cont. Load


GE a

LM1800e DLE × 25, – 25, – –, 1.4 15 18.1 35% 3600 8 —

LM2000PS SAC × 25, – 64, – –, 1.4 15 18.4 34.6% 3600 8 —

LM2000PJ DLE × 25, – 25, – –, 1.4 15 17.7 35.1% 3600 8 —

LM2500PE SAC × 25, – 95, – –, 1.4 15 24.1 35.1% 3600 8 —

LM2500PJ DLE × 15, – 25, – –, 1.4 15 22.7 36.5% 3600 8 —

LM2500PK SAC × 25, – 95, – –, 1.4 15 31.0 36.7% 3600 2 —

LM2500PR DLE × 25, – 25, – –, 1.4 15 30.5 38.5% 3600 2 —

LM2500+RC SAC × 25, – 95, – –, 1.4 15 36.3 37.2% 3600 2 —

LM2500+RD DLE × 25, – 25, – –, 1.4 15 33.2 38.9% 3600 2 —

LM6000PC SAC × 25, – 59, – –, 1.8 35 43.8 40.1% 3600 2 —

LM6000PC SPRINTb SAC × 25, – 59, – –, 1.8 35 50.5 40.3% 3600 2 —

LM6000PD DLE × 25, – 25, – –, 1.8 15 43.1 41.7% 3600 2 —

LM6000PD SPRINTb DLE × 25, – 25, – –, 1.8 15 47.4 41.8% 3600 2 —

LM6000PF DLE × 15, – 25, – –, 1.8 15 43.1 41.7% 3600 2 —

LM6000PF SPRINTb DLE × 15/25,

– 25, – –, 1.8 15 48.1 41.9% 3600 2 —

LM6000PG SAC × 25, – 94, – –, 2.2 56 53.5 39.8% 3600 2 —

LM6000PH DLE × 25, – 67, – –, 2.2 40 48.9 41.1% 3600 2 —





Emis. Model



Water Inj.



Eff. At 100% MCR

RPM Min.

Cont. Load


LMS100PA SAC × 25, – 95, – –, 3.0 57 103.5 43.6% 3600 3 —

LMS100PB DLE × 25, – TBD –, 3.0 TBD 99.4 44.3% 3600 3 —

GE 7EA × 9, 14.4

25, 23.2 7, 4 83.2 33.1% 3600 — —

MS7001EA × 9, — 25, — 85.4 32.7% 3600 — —

Hitachi

H-15 × 25, 7.7 25, 4.7 1, 0.2 15,

1.6 16.9 34.3% 9710 11.8 30.7%

H-25 × 25, 14.4 25, 8.8 1, 0.3 15,

3.0 32.0 34.8% 7280 22.4 31.9%

H-80 × 25, 40.8

25, 24.8 1, 0.8 15,

8.5 99.3 37.5% 4580 69.5 35.0%

Mitsubishi c

M501 DA DLN × 9, 22.26

10, 15.05 –, 1.17 2,

1.72 122.7 33.7% 3600 85.5 31.7%

M501 GAC DLN × 15, 71.15

10, 28.87 –, 2.62 10,

16.5 272.3 39.3% 3600 136.1 31.3%

M501 JAC DLN × 25, 124.94

10, 30.42 –, 1.75 5,

8.69 305.9 41.8% 3600 152.9 33.2%

P & W

SwiftPac 25 DLN × 25, – 25, – 10, – TBD 26.2 37.3% 3600 6.55 —

SwiftPac 50 DLN × 25, – 25, – 10, – TBD 50.2 37.3% 3600 12.5 —

SwiftPac 30 × 25, – 60, – 10, – TBD 30.5 37.0% 3600 7.63 —

SwiftPac 60 × 25, – 60, – 10, – TBD 61.1 37.0% 3600 9.16 —





Emis. Model



Water Inj.



Eff. At 100% MCR

RPM Min.

Cont. Load


FT4000 × 25, – 70, – 10, – TBD 123.0 41.0% 3600 18.5 —

Rolls-Royce d

501-KB5 TBC TBC TBC TBC TBC TBC TBC TBC TBC

501-KB7S TBC TBC TBC TBC TBC TBC TBC TBC TBC

501-KH5 × TBC TBC TBC TBC TBC TBC TBC TBC TBC

RB211-G62 DLE DLE × 25,

9.88 20.5, 5.87 TBC TBC 27.2 36.4% 4800 12.2 25.3%


9.89 16.5, 5.03 TBC TBC 29.8 37.5% 4800 13.4 26.8%


9.88 14.5, 4.53 TBC TBC 32.1 39.3% 4850 14.5 28.4%

RB211-H63 WLE Std. × TBC TBC TBC TBC 42.5 39.3% 6000 TBC TBC

Trent 60 DLE DLE × 25, 18.8 7, 3.3 6.0e,

2.27 1.4, 1.0e 51.7 41.9% 3600 25.8 30.7%

Trent 60 DLE ISI DLE × 25,

20.9 7, 3.7 5.4e, 2.27

1.4, 1.0e 58.0 42.7% 3600 25.9 30.9%

Trent 60 WLE Std. × 25, 23.1

35.8, 20.1

5.0e, 2.27

14.3, 10.3e 61.2 41.0% 3600 34.5 36.0%

Trent 60 WLE ISI Std. × 25,

24.2 45.6, 26.9

4.8e, 2.27

18.2, 13.1e 64.0 41.6% 3600 34.0 36.7%

Siemens

SGT6-5000F × 9, 35.4

4, 9.53

2.8e, 4.54

1, 1.36 229.3 36.3% 3600 137.5 32.9%

SGT6-8000H × 25, 106.2

10, 25.9

2.8e, 4.54

1, 1.36 274.7 40.1% 3600 192.2 36.3%





Emis. Model



Water Inj.



Eff. At 100% MCR

RPM Min.

Cont. Load


Solar

Saturn 20 × 42, 1.3

50, 1.0

0.018, 0.15

25, 0.3 1.2 23.7% — 0.96 22.5%

Centaur 40 × 25, 2 50, 2.4

0.018, 0.4

25, 0.7 3.5 27.9% — 1.8 21.6%

Centaur 50 × 25, 2.4

50, 3.0

0.018, 0.5

25, 0.9 4.6 29.3% — 2.3 22.1%

Mercury 50 × 25, 0.4

50, 0.4

0.018, 0.4

25, 0.3 4.6 38.5% — 2.3 31.9%

Taurus 60 × 25, 2.8

50, 3.4

0.018, 0.6

25, 1.0 5.7 31.5% — 2.8 23.8%

Taurus 65 × 25, 3 50, 3.6

0.018, 0.7

25, 1.0 6.3 32.9% — 3.2 25.4%

Taurus 70 × 25, 3.6

50, 4.4

0.018, 0.9

25, 1.3 7.9 34.3% — 3.9 26.1%

Mars 100 × 25, 5.3

50, 6.5

0.018, 1.0

25, 1.9 11.3 32.9% — 5.7 22.2%

Titan 130 × 25, 6.6

50, 8.0

0.018, 1.3

25, 2.3 15.0 35.2% — 7.5 26.6%

Titan 250 × 25, 8.6

50, 10.5

0.018, 1.7

25, 3.0 21.7 38.9% — 8.8 23.5%

a GE notes: (1) particulate emissions are not measured on a dry basis like NOx and CO—typically particulate are measured on a mass emission rate (kg/hr) and expressed in the same manner; (2) with wet controls, CO and UHC emissions are uncontrolled (data provided are estimated maximums); (3) for DLE (dry low emissions), NOx, CO, and UHC emissions are controlled, so levels presented are maximum values; (4) emissions numbers given here are at full load, ISO conditions, using pipeline NG as fuel; (5) minimum continuous load is limited by generator requirements, so, emissions guarantees do not apply at these levels.

b SPRINT refers to use of atomized water spray injection into the compressor. c Mitsubishi notes: (1) all performance data are based on New & Clean conditions; (2) all supplied values are estimations and

not guaranteed; (3) a tolerance of 0.75% on Power and 1.0% on Heat Rate shall apply to the aforementioned values; (4) fuel characteristics and heating value are based on MPSA assumed fuel analysis—the aforementioned values should be corrected based on project specific fuel analysis; (5) 0 gr/100scf of sulphur and 0% fuel bound nitrogen (FBN) are considered in the fuel; (6) fuel must be in compliance with MPSA's fuel specification; (7) the stated gross power output is at the generator terminals minus excitation losses; (8) assumed 134.6 mm H2O exhaust duct loss at ISO conditions; (9) GT efficiency is based on LHV; (10) since this data is based on estimated and/or assumed values, the customer shall confer with MPSA prior to including in any air permit application or contract guarantees; (11) emissions shall be tested in accordance




with the following EPA methods: NOx: 20, CO: 10, UHC: 25, PM10: non-condensibles using Method 201 or 201A and condensibles using Method 202; (12) data included in any air permit application or environmental impact study is strictly the customer's responsibility; (13) emission values are net emissions generated from MPSA's equipment, unless otherwise stated; (14) values given are as measured at the GT exhaust flange (prior to any downstream emission control equipment).

d Rolls-Royce notes: (1) TBC (to be confirmed) refers to information that can only be provided on a case-by-case basis, (2) efficiency at minimum continuous load means while not exceeding NOx of 25 ppmv and CO of 50 ppmv.

e In units of mg/Nm3.




Table A-3: Comparison of Vendor-Supplied Parameters for Combined Cycle Drive Turbines


Emis. Model



Water Inj.



Eff. At 100% MCR

RPM Min.

Cont. Load


GE

LM2500+G4 RD × –, 12 –,

7.53 — –, 2.55 30.1 38.0% 3600 — —

LM6000PF × –, 9 –, 9.0 — –,

3.09 38.7 40.7% 3600 — —

LM6000PF Sprint × –, 10 –,

9.7 — –, 3.31 41.2 40.5% 3600 — —

LM6000PH × –, 10 –, 39.5 — –,

22.2 41.0 39.4% 3900 — —

Mitsubishi a

MPCP1 (M501GAC) DLN × 15,

71.2 10,

28.9 –, 2.62 10, 16.5 272300 39.3% 3600 1361

00 31.3%

MPCP2 (M501GAC)

DLN ×2 × 15,

142.3 10,

57.7 –, 5.24 10, 32 544600 39.3% 3600 2722

00 31.3%

MPCP1 (M501J) DLN × 25,

125.0 10,

30.4 –, 1.75 5, 8.7 305900 41.8% 3600 1529

00 31.2%

MPCP2 (M501J)

DLN ×2 × 25,

250.0 10,

60.8 –, 3.5 5, 17.4 611800 41.8% 3600 3058

00 31.2%

Rolls-Royce b

RB211-G62 DLE × 25,

9.88 20.5, 5.87 TBC TBC 37.7 50.2% 4800 12.2 25.3%

RB211-GT62 DLE × 25,

9.88 16.5, 5.03 TBC TBC 39.8 41.4% 4800 13.4 26.8%

RB211-GT61 DLE × 25,

9.88 14.5, 4.53 TBC TBC 42.5 52.8% 4850 14.5 28.4%

RB211-H63 WLE × TBC TBC TBC TBC 54.0 50.8% 6000 TBC TBC

Trent 60 DLE × 25, 18.8 7, 3.3 6.0c,

2.27 1.4, 10c 64.6 52.5% 3600 25.8 30.7%





Emis. Model



Water Inj.



Eff. At 100% MCR

RPM Min.

Cont. Load


Trent 60 DLE ISI × 25,

20.9 7, 3.7 5.4c, 2.27

1.4, 10c 72.9 53.1% 3600 25.9 30.9%

Trent 60 WLE × 25, 23.1

35.8, 20.1

5.0c, 2.27

14.3, 10.3c 75.3 51.0% 3600 34.5 36.0%

Trent 60 WLE ISI × 25,

24.2 45.6, 26.9

4.8c, 2.27

18.3, 13.1c 77.2 50.5% 3600 34.0 36.7%

Siemens

SCC6-5000F × 9,

35.4 4,

9.53 –, 4.54 1, 1.36 229.3 36.3% 3600 137.5 32.9%

SCC6-8000H × 25, 106.2

10, 25.9 –, 4.54 1,

1.36 274.7 40.1% 3600 192.2 36.3%

a Mitsubishi notes: (1) all performance data are based on New & Clean conditions; (2) all supplied values are estimations and not guaranteed; (3) a tolerance of 0.75% on Power and 1.0% on Heat Rate shall apply to the aforementioned values; (4) fuel characteristics and heating value are based on MPSA assumed fuel analysis—the aforementioned values should be corrected based on project specific fuel analysis; (5) 0 gr/100scf of sulphur and 0% fuel bound nitrogen (FBN) are considered in the fuel; (6) fuel must be in compliance with MPSA's fuel specification; (7) the stated gross power output is at the generator terminals minus excitation losses; (8) assumed 134.6 mm H2O exhaust duct loss at ISO conditions; (9) GT efficiency is based on LHV; (10) since this data is based on estimated and/or assumed values, the customer shall confer with MPSA prior to including in any air permit application or contract guarantees; (11) emissions shall be tested in accordance with the following EPA methods: NOx: 20, CO: 10, UHC: 25, PM10: non-condensibles using Method 201 or 201A and condensibles using Method 202; (12) data included in any air permit application or environmental impact study is strictly the customer's responsibility; (13) emission values are net emissions generated from MPSA's equipment, unless otherwise stated; (14) values given are as measured at the GT exhaust flange (prior to any downstream emission control equipment).

b Rolls-Royce notes: (1) TBC (to be confirmed) refers to information that can only be provided on a case-by-case basis, (2) efficiency at minimum continuous load means while not exceeding NOx of 25 ppmv and CO of 50 ppmv.

c In units of mg/Nm3.




Appendix+B+Emissions regulations for natural gas fuelled turbines in British Columbia.

bc moe - final report€¦ · a review of current turbine technologies has been carried out. this...

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