Astm stp 809 1983

Introduction The traditional fuels for stationary gas turbines have been largely petroleum-based liquids and natural gas, and ASTM has long been involved in this aspect of fuel specifica

STATIONARY GAS

TURBINE

ALTERNATIVE FUELS

A symposium sponsored by ASTM Committee D-2

on Petroleum Products and Lubricants and ASTM Committee D-3

on Gaseous Fuels Phoenix, Ariz., 9-10 Dec 1981

ASTM SPECIAL TECHNICAL PUBLICATION 809

J S Clark, NASA-Lewis Research Center, and

S M DeCorso, Westinghouse Electric Corp

NOTE The Society is not responsible, as a body, for the statements and opinions advanced in this publication

Printed in Baltimore, Md (b) September 1983

This publication, Stationary Gas Turbine Alternative Fuels, contains

pa-pers presented at the symposium on Alternative Fuels and Future Fuels

Specifications for Stationary Gas Turbine Applications, which was held in

Phoenix, Ariz., on 9-10 Dec 1981 The symposium was sponsored by ASTM

Committee D-2 on Petroleum Products and Lubricants and ASTM

Commit-tee D-3 on Gaseous Fuels The symposium cochairmen were John S Clark,

NASA-Lewis Research Center, and S Mario DeCorso, Westinghouse

Elec-tric Corp., both of whom also served as editors of this publication

ASTM Publications

Distillate Fuel Stability and Cleanliness, STP 751 (1981), 04-751000-12

Analysis of Waters Associated with Alternative Fuel Production, STP 720

to Reviewers

The quality of the papers that appear in this publication reflects not only

the obvious efforts of the authors but also the unheralded, though essential,

work of the reviewers On behalf of ASTM we acknowledge with appreciation

their dedication to high professional standards and their sacrifice of time and

effort

ASTM Committee on Publications

Janet R Schroeder Kathleen A Greene Rosemary Horstman Helen M Hoersch Helen P Mahy Allan S Kleinberg Virginia M Barishek

Introduction

FUTURE FUEL TRENDS

Smrey of Gas Turbine Synthetic Dquid Fuels—ROBERT C AMERO,

S MARIO D E C O R S O , AND RICHARD L THOMAS 5

Literature Survey of the Properties of Synthetic Fuels Derived from

Coal—FRANCISCO J FLORES 2 2

Gas Turbine Fuel Processing Costs and On-Site Cleanup Options—

JOHN W DUNNING, JR 3 8

COMBUSTION AND FUEL CHARACTERISTICS

Fuel Property Effects on the Performance of a Small Industrial Gas

Turbine Engine—WILLIAM CAAN, JOHN M HAASIS, AND

RANDALL C WILLIAMS 6 3

Performance of SRC-II Fuels in Gas Turbine Combustors—

ERNEST H T O N G AND ARTHUR M MELLOR 79

Effect of Fuel Properties on ^nition and Combusion Limits in Gas

Turbine Combustms—JOHN ODGERS AND DETLEF KRETSCHMER 98

Future Distillate Fuel Trends in Canada and Some Preliminary Gas

Turbine Test Results an Tar Sand Products—ROBERT B vmvTE,

ROBERT G GRIMSEY, AND C A WILLIAM GLEW 1 1 5

Properties of Synthetic Fuels Evaluated for Combustion Turbines—

CARL W STREED, P RICHARD MULIK, MICHAEL J AMBROSE,

AND ARTHUR COHN 1 3 0

Effect of Sodium and Potassium on the Hot Corrosion of Gas

Turbines—ROGER W HASKELL, HARVEY VONE DOERING, AND

DANIEL F G R Z Y B O W S K I 156

TIMOTHY MICHELFELDER 1 8 0

Discussion 185

Syndietic Fuels for Statimiaiy Gas Turiiines: A Cafifmnia Pfer^wctire—

STEVEN J ANDERSON, MICHAEL D JACKSON, AND

KENNETH D SMITH 186

Distillate Fuels from Nonpetrolenm Sources—EDMUND W WHITE 212

ALTERNATIVE GASEOUS FUELS

Coal Gasification for Stationary Gas Turbine Applications—

ANIL GOYAL, DONALD K FLEMING, AND WILFORD G BAIR 2 3 3

A Projection of Coal Gas Properties Considered from the Viewpoint

of a Coal Gas Combined-Cycle Plant—JOHN H MARLOW,

JAMES PAVEL, AND EDWARD VIDT 2 5 5

Properties of Low-Btn Coal Gas and Its Combustion Products—

HARVEY VONE DOERING, SHIRO G KIMURA, AND DANIEL P SMITH 2 7 0

ANALYTICAL TECHNIQUES

Sulfur Measurement in Uquid and Gaseous Altematire Fuels—

CHARLES L KIMBELL 291

Characterization of Ash Residues from a Refuse-Derived Fuel/Oil

Combustion Study—FLOYD HASSELRIIS AND CARL R ROBBINS 300

Heating Values of Natural Gas and Its Components: Conversion of

Values to Measurement Bases and Calculation of Mixtures—

GEORGE T ARMSTRONG AND THOMAS L JOBE, JR 3 1 4

Measurement Techniques for Fuel Stability Characterization—

ARTHUR L CUMMINGS, PATRICK PEI, AND STEPHEN M HSU 3 3 5

SUMMARY Summary 353

Index 359

Introduction

The traditional fuels for stationary gas turbines have been largely

petroleum-based liquids and natural gas, and ASTM has long been involved in this aspect

of fuel specifications In 1964, a symposium on Gas Turbine Fuels was held by

ASTM Committee D-2 on Petroleum Products and Lubricants, Technical

Di-vision E on Burner, Diesel, and Gas Turbine Fuel Oils The ASTM

Specifica-tion for Gas Turbine Fuel Oils (D 2880), covering petroleum-based liquids,

was issued in 1970, and a revised Specification D 2880 was issued in 1976 The

properties of natural gas fuels are treated by ASTM Committee D-3 on Gaseous

Fuels

As a result of the oil embargo in 1973 and world events since that time, we

have come to realize that the supplies of traditional petroleum and natural gas

fuels are limited, and that it is necessary to plan for the use of alternative fuels

The speed with which alternative fuels will come into use is a subject of debate,

but not the proposition that alternative fuel use must eventually come into

be-ing Since a great deal of time and effort is necessary in order to arrive at a

con-sidered evaluation of the properties of and specifications for alternative fuels,

this symposium was especially timely Also, many processes for producing

al-ternative fuels are in the early development phases, and the processes and final

product slates will evolve as end uses (and hence specifications) are defined

The development of these processes and the end-use specifications must,

therefore, proceed in parallel

The purpose of the symposium was to assess the state of the art of alternative

liquid and gaseous fuels and to provide a technical data base of the properties

of alternative fuels for stationary gas turbines as a starting point for future

al-ternative fuels specifications development The topics addressed in this

sym-posium show that the alternative fuels choices are many and varied As

ex-pected, however, many of the papers point out the fact that fuel property data

do not exist for many of the possible fuels, and much more work is required

before intelligent trade-offs can be made It is appropriate that specifications

for these future fuel choices be started now and proceed with "all deliberate

speed" to provide the technical information needed so that the right fuel

choices for the future can be made

The ASTM committees and task groups working on this task, and the

spon-sorship of this symposium in particular, are key parts of the work that must be

done to plan and prepare for the eventual use of alternative fuels

S Mario DeCorso

Westinghouse Electric Corp., Concordville, Pa

19331; symposium cochainnan and editor

Survey of Gas Turbine Synthetic

Liquid Fuels

REFERENCE: Amero, R C , DeCorso, S M., and Thomas, R L., "Sunrey of Gas

Tur-bine Synthetic Liquid Fuels," Stationary Gas TurTur-bine Alternative Fuels ASTM STP 809,

J S Clark and S M DeCorso, Eds., American Society for Testing and Materials,

Phil-adelphia, 1983, pp 5-21

ABSTRACT: As the United States moves toward an alternative fuel economy, away from

petroleum fuels, gas turbines fueled by nonpetroleum sources are expected to supply an

increasing percentage of the total generation of power New technology and procurement

standards need to be developed for these alternative fuels to ensure an operable,

econom-ical turbine-fuel system

Recognizing this need, Subcommittee B133.7 on Gas Turbine Fuel Procurement

Stan-dards, a subcommittee of the American National Standards Institute (ANSI), carried out

a survey to establish a technical framework for interpreting the projected properties of

synthetic fuels for gas turbine applications The 55 responses received from synthetic

liq-uid fuel producen, equipment manufacturers, turbine users, and consultants, as well as

government and nongovernment agencies, showed that process developers, gas turbine

manufacturers, and users are actively involved in planning for future synthetic fuels

While the quality and properties of synthetic liquid fuels were not fully established, it is

clear that methanol and distillate fuels derived from shale, coal, and tar sands are being

seriously developed and will play a major role in future gas turbine operation

KEY WORDS: alternative fuels, gas turbines, synthetic fuels, liquid synthetic fuels

This paper presents the results of a synthetic fuels survey^ performed by

Subcommittee B133.7 of the American Society of Mechanical Engineers

(ASME)/American National Standards Institute (ANSI) Committee B133 on

Gas Turbine Procurement Standards Subcommittee B133.7 represents a

co-'Staff engineer Gulf Research and Development Co., Pittsburgh, Pa 15230

^Manager, Energy Development Program, Westinghouse Electric Co., Concordville, Pa 19331

^Engineer in residence, Engineering Societies' Commission on Energy, Inc., Washington, D.C.,

20024

''DeCorso, S M., "Survey of Synthetic Fuels," unpublished letter from Subcommittee B133.7

of the American National Standards Institute to processors of synthetic fuels, manufacturers of

combustion turbines, and users, consultants, and related organizations and agencies, 25 July

1979

operative effort among turbine manufacturers, fuel suppliers, turbine users,

and other interested groups to describe acceptable fuel systems for stationary

gas turbines

Since its inception in 1975, Subcommittee B133.7 has cooperated closely

with Technical Division E of ASTM Committee D-2 on Petroleum Products

and Lubricants and with the Committee on Combustion and Fuels of the

ASME Gas Turbine Division The ASTM Specification for Gas Turbine Fuel

Oils (D 2880-80) for petroleum-derived gas turbine fuels is based largely on

data reported in ASME meetings and is the recognized specification for

liq-uid fuels in ANSI Standard B133.7, "Gas Turbine Fuels" (1977) With the

publication of this standard, the subcommittee became inactive

In 1979, Subcommittee B133.7 reconvened to consider the question of

stan-dards for systems using nonpetroleum fuels in gas turbines At the same time,

the activities of ASTM Committee D-2, Technical Division E, were

expand-ing to consider the development of specifications for such fuels; the number

of ASME papers dealing with the performance of prototype nonpetroleum

fuels also was increasing

Table 1 indicates that a long lead time is required to develop ASTM gas

turbine fuel specifications This is not surprising because ASTM depends

on voluntary consensus among companies and agencies with divergent

inter-ests This slow pace emphasizes the need to continue work on specifications

for nonpetroleum fuels, even with the current adequate supply of petroleum

The ANSI questionnaire was initiated in 1979, and the results reported here

are intended to provide benchmark information on the properties of some

nonpetroleum fuels, the fuel qualities required by gas turbines, and possible

trends in properties and requirements

Since liquid hydrocarbon fuels derived from shale, coal, and tar sands

rep-resent new technologies, every effort was made to contact organizations in

the following categories related to liquid fuels:

(a) fuel processors,

(b) equipment manufacturers, users, and technical support organizations,

and

(c) regulatory agencies

While all the organizations contacted did not respond, the replies that were

received and summarized in this paper should provide a "snapshot" of

activi-ties in the area of synthetic liquid fuels Since the survey was carried out (in

the fourth quarter of 1979), the U.S Congress has passed synthetic fuels

leg-islation that will have a major impact on the quantities of synthetic liquid

fuels that will become available for gas turbine use For example, a goal of

160 000 to 240 000 m^/day (1.0 to 1.5 miUion bbl/day) by 1992 was set for

the newly formed Synthetic Fuels Corp

TABLE 1—Technical society activities and spec^ations for gas turbine liquid fuels."

New task force established Symposium on gas turbine fuels

Revised specification D 2880 issued

Need for synthetic fuel specification discussed Section E-m Panel on Ahemate Fuels formalized, expanded

Round table discussion of altemative fuel properties Symposium on altemative fuels for gas turbines

Questionnaire issued Replies tabulated

Replies summarized in technical paper

'ASME organizes a foram at three or more conferences per year concerning combustion,

emis-sions, and corrosion in gas turbines Before the Gas Turbine Dhrision was established in 1947,

many significant papers were sponsored by other ASME dnrisions

bfoimatfon bom Fuels Processms

Replies in this category were received from seven companies involved in the

development of various synthetic liquid fuel processes and products The

re-sponses identified distillates of the following types as potential synthetic or

altemative liquid fuels for gas turbines:

(a) liquid retorted from oil shale (four replies),

(6) extracts from tar sands (two replies), and

(c) liquefied coal (three replies)

While no specific replies were received on the subject of alcohol fuels, it is

as-sumed that alcohol fuels derived from coal represent an additional source of

turbine fuel, based on the proven nature of this technology In addition, the

replies for liquefied coal mcluded only direct Uquefaction processing and not

Fischer-Tropsch or other mdirect processuig

Fuel Grades and Availability

In regard to raw fuels, all seven replies indicated that it was not possible to

pinpoint grades at this time However, alcohols and some "raw" liquefied

coals will probably be available without treatment except for distillation Tar

sands and shale oil require refining (usually mcluding hydrogenation) to

achieve acceptable levels of purity and stability Direct liquefaction of coal

also requires hydrogenation, even to produce the raw liquid The distinction

between raw and upgraded coal-derived liquids is measured largely by the

quantity of hydrogen combined with the coal in the processing of the fuel

All seven replies indicated that coal liquids, shale oils, and tar-sand extracts

can be elevated in quality (and cost) by additional hydrogenation They also

can be distilled into fractions of different boiling ranges, the present trend

being toward production of four principal liquids:

(a) naphtha, boiling below about 177°C (350°F), for gasoline feedstock or

other nonfuel oil uses;

(b) middle distillate, in the approximate boiling range of (petroleum) No 2

fuel oil No 2 D diesel fuel, and No 2 GT gas turbine fuel;

(c) heavy distillate, boiling above 343°C (650°F)—for example,

corre-spondmg to (petroleum) No 3 GT gas turbine fuel or cat-cracker charge

stock; and

(d) liquid residuum or coke, which can be consumed in the refining process

or diverted to uses now satisfied by petroleum No 6 fuel oil, tar, or asphalt

The companies developing coal liquids indicated that raw or slightly

up-graded middle distillate from coal will probably be available for gas turbine

applications; the heavier coal distillates will go to industrial and utility boiler

fuel users In addition, blends of coal-derived liquids with petroleum also

may be possibilities While there could be some compatibility problems,

pre-liminary data indicate that the 177 to 343°C (350 to 650°F) cut can be blended

with petroleum fuels Quantities of coal-derived fuels could become available

for testing for a limited number of consumers as early as from 1983 to 1986,

but the fuels will not become widely available until after 1990

In regard to shale oil for gas turbine use, the responses indicated that

hy-drotreated No 2 fuel from shale oil will become available before coal-derived

liquids and will be adequate for use in stationary gas turbines It is possible

that the fuels from shale oil will be made initially from synthetic crude charged

to conventional petroleum refineries along with crude oil, and the products

will closely approach normal petroleum in quality The 315 to 482°C (600 to

900°F) fraction is likely to be used in cat crackers to make gasoline

compo-nents Shale oil will probably not be segregated from other fuels Full-scale

commercial production of shale oil is expected about nine years after the

per-mits are obtained

The outlook for extracts from tar sands is similar to that for shale oil in

terms of their use as conventional petroleum refinery feedstock Tar sand

ex-tracts are currently produced in modest commercial quantities, hydrogenated,

and mixed with petroleum crudes for conventional refining

Detailed Fuel Properties

The information from the survey regarding the properties of alternative

fuels is shown in Table 2 These properties came from pilot plant data and

are not specifications for large-scale production For example, the properties

of coal-derived liquids could be affected by the coal type, process design, or

process configuration Like petroleum distillates, the absence of ash-forming

contaminants is determined almost completely by the efficiency of distillation

and by proper handling of the finished product Although requested in the

survey, no specific replies were received regarding special properties such as

the ash melting temperature, water separation characteristics, or toxicity

Processing Methods and Costs

While no specific replies were received on the subject of alcohol fuels, it is

assumed that alcohol fuels will be produced in both new and existing

facili-ties The nitrogen content and incremental costs for upgrading, which are

concerns in the production of shale, coal, and tar sand derived fuels, are not

processing variables for alcohol fuels

All responses in regard to shale oil and tar sand indicated that new

refiner-ies are not required for processing liquid fuels derived from these sources

More than 16 000 m^ (100 000 bbl) of shale oil have been processed in

refin-eries m Utah, Colorado, and Ohio

The product fuels satisfied a majority of the military, federal, and

com-mercial specification requirements However, many of these fuels exhibited

storage and thermal instabilities, and their high levels of wax, particulate

mat-ter, and gum require additional treatment before satisfactory products can be

made (higher pressure hydrogenation or clay or acid treatment, or both

hy-drogenation and treatment) The processing work included full-scale refinery

tests with feedstock concentrations of 13 to 19% shale oil in crude petroleum

It was reported that the products from these tests remained within

specifica-tions and were used in blending the refinery's normal products [1].^

^ h e italic numbers in brackets refer to the list of references appended to this paper

In regard to tar sands, conventional processing technology is utilized,

al-though the existing commercial plants are new refineries The two existing

commercial tar sand production facilities in Canada involve production of

synthetic crude Commercial experience with tar sands and test work with

shale oil in existing refineries to meet current product specifications

demon-strate that fuel-bound nitrogen can be reduced to satisfactory levels

Commercialization plans are not final for coal liquid processing for

prod-uct demands It is conceivable that 82 to 177°C (180 to 350°F) naphtha from

H-Coal, solvent refined coal II (SRC-II), and Exxon donor solvent (EDS)

liq-uids could be upgraded to high octane reformate; raw 177 to 427°C (350 to

800°F) distillate has acceptable quality for industrial and utility boiler use

without upgrading Hydrotreating of higher boiling distillates might be

desir-able, primarily to remove nitrogen

To meet a different product slate, EDS, H-Coal, and SRC-II distillates

(177 to 427°C) would require upgrading in grass-roots units utilizing

conven-tional petroleum-based technology [2] The liquefaction processes would

probably not involve existing petroleum refineries The extent of upgradmg

has not been established, but the raw distillates would probably be suitable

for many uses without upgrading

No definitive replies were received concerning the incremental cost of

up-grading various properties such as hydrogen content, nitrogen content, and

ash content However, all responses related to shale oil and coal-derived

liq-uid indicated that hydrotreating can be used to meet a wide range of product

specifications In one U.S Department of Energy sponsored study [3,4], the

updated refining costs for converting raw shale oil into transportation fuels

were estimated at $78 to $116/m3 ($12.50 to $18.50/bbl) in first-quarter 1980

dollars The same study estimates the cost of upgrading raw SRC-II liquid to

be $63 to $104/m3 ($10 to $16.50/bbl) on a comparable basis The study also

assumes that refining H-Coal would be less costly than refining SRC-II

be-cause less hydrogen would be required A study by the Mobil Oil Co [5] shows

that the cost of upgrading H-Coal distillate to turbine fuels is in the range of

$25 to $50/m3 ($4 to $8/bbl), depending on the extent of processing and the

assumed economic basis

In contrast to this information, an analysis of published studies since 1975

[6] indicates that upgrading coal liquids to meet existing specifications of

ASTM Committee D-2 might cost $50 to $94/m3 ($8 to $15/bbl) more than

the cost of upgrading shale oil to the same level This report reflects the fact

that coal liquids require more hydrogen and greater hydrogenation than do

shale oils to reach a satisfactory cetane level The hydrogen content is a less

critical concern in fuel for stationary turbines The Fuel Quality Processing

Study developed by the National Aeronautics and Space Administration

(NASA) Lewis Research Center, soon to be released, will provide insight into

the various cost trade-offs between fuel upgrading and gas turbine

modifica-tions, and will define better the processing costs for turbine fuels [7,8]

The estimated cost of upgrading is greatly influenced by the volume of

liq-uid to be treated per day, the types of processes to be used, the relative

amounts of gasoline, jet fuel, and miđle distillate to be produced, the degree

of upgrading to be achieved, and other related factors The comparisons

among the total costs of different fuels will change when the costs of mining,

liquefaction, and retorting are ađed to these processing costs

Infonnation Received from Equipment Manufactoiers, Users, and

Technical Support Organizations

Replies regarding properties that are currently specified for liquid fuels

were received from 36 utilities and several gas turbine manufacturers The

specifications from the utilities generally reflected the specifications of the

manufacturers whose turbines they used Table 3 summarizes the principal

properties listed in the responses These are divided into three categories:

Nọ 2 fuel, Nọ 1 fuel, and fuels with higher boiling components (heavy

distil-late, crude oil, and residual fuels) The ranges of properties are shown where

enough replies were received

Developments in equipment that come from studies such as the NASA

Lewis Research Center's Low-NỘ Combustor Program may alter the

specifi-cations required for future fuels

The following comments are taken from the responses and indicate either

some of the less common specifications imposed on gas turbine fuels, or

man-ufacturer or user concerns that may not yet be specification requirements:

Water separation

Qualifications for water injection and inlet ambient air contaminants

Problems with zinc on the blading

Visibly clean fuel

Distillate recovery to 98,5% by volume minimum—ASTM Distillation

of Petroleum Products (D 86-78)

Filtration test cleanliness of 2.5 mg/3.785 L (1 gal) maximum—ASTM

Tests for Particulate Contaminant in Aviation Turbine Fuels [D 2276-73

(1978)]

Sodium-free water, 50 ppm maximum copper, and 0.2% sulfur by mass

0.3% sulfur by mass and 0.035% ash by mass for environmental

restric-tions

Concern about long-term storage stabilitỵ

Specification of ash melting temperature, toxicity, and water separation

characteristics

Coal liquid polynuclear species should be studied beforehand

Toxicity

Fuel should be lighter than water, contain no toxic substances, and not

require treatment with chemicals that may result in the discharge of

toxic substances

Aromaticity—The aromaticity of the fuel has a great influence on the

combustion process and flame radiation In current petroleum fuels, it

is controlled to some extent by limiting the specific gravity In coal

liq-uids, it may be desirable to specify tests more closely related to

aromati-city such as those for the hydrogen/carbon ratio or hydrogen content

Nitrogen content—Coal liquids in a given fuel grade have much more

fuel-bound nitrogen than the petroleum equivalents It is important that

the nitrogen content measuring techniques be accurate and

reproduc-ible Different techniques tend to give different values, and a

standard-ized technique is needed It would be desirable to report the standardstandard-ized

value of the nitrogen content since it is critical in meeting applicable

NO;c emission requirements

Stability—Very little has been reported on the storage stability of coal

liquids in comparison with petroleum fuels This is an area that should

be examined since some of the nitrogenous compounds could detract

from stability

Trace metal contaminants—If any trace metal elements are carried over

from the coal feedstock to the coal liquid product, the element mix

could differ from that of petroleum fuels; for example, potassium may

be more prevalent than sodium As refined, the light and medium

distil-lates should have very low trace metal levels Heavy fuels might or might

not have significant trace metal levels, depending on the processing

equipment and mode of operation The vanadium levels in coal liquids

should not be a problem

Demulsibility—Early heavy coal liquids had poor water demulsibility

properties, probably in part because of natural emulsifying agents in the

coal liquid This may not be a problem with the more recent all-distillate

liquids, but it is a possibility that should be checked

Fuel Compatibility—Heavy coal liquid fuels may not be compatible with

petroleum fuels or even with lighter grades of coal liquid fuels

Gas turbine manufacturers and users were queried about the possibility of

more relaxed fuel specifications for current and future gas turbines Changes

were not anticipated, but a few responses suggested that staged combustion,

cooled turbine blades, and other technological improvements would permit

an easing of fuel restrictions Details of the comments follow:

Current Specifications for Gas Turbine Fuels

No easement or no further easement (ten responses)

Easement will not be drastic (one response)

Easement of hydrogen and aromaticity (one response)

Specifications for Future Gas Turbine Fuels

No easement or no future easement (six responses)

An increase in sulfur (one response)

Expect easement in most of physical properties and in the aromaticity

and heating value; the sulfur limit will go to 0.1% by mass or lower (one

response)

Tighter control over fuel-bound nitrogen (one response)

Environmental agencies will have impact on easing standards (one

response)

Only manufacturers and regulatory agencies are qualified to comment

(one response)

Future easement in nitrogen, depending on the development of staged

combustor technology (one response)

Easement in corrodents if fully water cooled 538°C ( < 1000°F) turbines

are developed (one response)

Time Scale for Easement of Future Gas Turbine Fuel Specifications

Unknown, none, or no comment (four responses)

Burning No 6 fuel at present (one response)

Plan to use methanol, low- and intermediate-BTU coal-derived gases, and

light oils from coal, shale, or tar sands; no heavy oil use (one response)

No change for seven or eight years (one response)

Improved combustor technology: standard combustor, 1983 to 1985;

staged combustor, 1988 to 1991 (one response)

Infonnation Requested from Regnlatoiy Agencies in the United States

The questions posed and the answers received from the U.S

Environmen-tal Protection Agency (EPA) and the Occupational Safety and Health

Ad-ministration (OSHA) are contained in the Appendix The information

re-ceived, while incomplete, is believed to be representative of the regulatory

environment surrounding the manufacture, distribution, and use of synthetic

liquid fuels and the present status of regulatory actions For example,

regula-tions are just now being promulgated based on the Power Plant and

Indus-trial Fuel Use Act of 1978 Also, the EPA is presently carrying out a major

re-search effort to establish a data base for regulatory actions concerning the

impact of synthetic fuels on air and water quality and on solid wastes The

EPA target dates for completing this work range from 1983 to 1985 Similarly,

OSHA is now completing initial research evaluations of the potential impact

of synthetic fuel manufacture on occupational exposures and hazards It is

expected that the results of this research, in terms of promulgating OSHA

regulations in the synthetic fuels area, will be available by 1983 Consequently,

the survey results in this area do not identify specific regulatory requirements

relating to the use of synthetic liquid fuels for gas turbine applications

Summaiy

The results of the survey clearly indicate that process developers, gas

tur-bine manufacturers, and users are actively involved in planning for future

synthetic liquid fuels WhUe the quality of these fuels was not established

with certainty, it is clear that methanol and distillate fuels derived from shale,

coal, and tar sands are being developed and will play major roles as fuels for

gas turbines In particular, it appears that shale oil and tar sands are suitable

for co-refining with conventional petroleum fuels, and that the products should

be comparable in quality to fuels in use today However, coal-derived liquid

fuels have the potential for commercial use as raw or upgraded distillate

prod-ucts The economic, technical, and regulatory constraints on the use of coal

liquids as gas turbine fuels have yet to be fully determined

Acknowledgments

As now organized, ANSI Subcommittee B133.7 is divided into subgroups

responsible for evaluating continuing activities in the areas of conventional,

synthetic liquid, and synthetic gaseous fuels This survey was compiled by the

Subgroup on Synthetic Liquid Fuels from responses to the questions in the

report of the original survey on synthetic fuels'' performed by Subcommittee

B133.7 As subgroup leader, chairman, and secretary of Subcommittee

B133.7, the authors of this paper are presenting information prepared by the

subgroup and reviewed by the full membership of B133.7 The subgroup is

composed of the following members:

R C Amero Gulf Research and Development Cọ

J Ẹ Barry Missouri Public Service Cọ

J S Clark NASA Lewis Research Center

Ạ Cohn Electric Power Research Institute

P H Kyđ Hydrocarbon Research, Inc

J H Marlow Westinghouse Electric Corp

F Ẹ Salb Fuels and Lubricants Consultants

C Streed Mobil Research & Development Corp

W T Wotring The Standard Oil Company of Ohio

S Zaczepinski Exxon Research and Engineering Cọ

R L Thomas alternate member

APPENDIX

Questions (Q) submitted to United States regulatory agencies during this survey are

shown here along with the responses (R) that were received

Environmental Protection Agency (EPA)

(Q) Is it the intent of the EPA to apply current exhaust gas emissions standards to

stationary combustion turbines burning synthetic liquid fuels?

(R) Yes, the promulgated New Source Standard (NSPS) for stationary gas turbines

applies to gas turbines firing all types of fuels

(Q) Under what circumstances could emission standards be tailored to meet specific

properties of synthetic fuels?

(/?) The emission standards could be tailored to meet specific properties of synthetic

fuels if—after careful study of the economic, environmental, and energy impacts

of tailoring the standards in such a manner—all of these impacts were deemed to

be reasonable and all criteria for an NSPS as set forth by Section 111 of the Clean

Air Act were met

(Q) What consideration will be given to modifying the total allowable NỘ emissions

to account for the higher fuel-bound nitrogen content of synthetic fuels (for

ex-ample, coal-derived liquid fuels, typically 0.8% by weight)?

(/?) The promulgated NSPS for gas turbines includes a fuel-bound nitrogen allowance

which allows the NÔ emission limit to be adjusted upward as fuel-bound

nitro-gen increases The baseline NỘ emission limit, however, may be adjusted

up-ward by a maximum of 50 ppm due to fuel-bound nitrogen

(Q) Is any consideration being given to extending the coverage of current regulations

for stationary gas turbines below 10 000 hp in size or to include limits for

particu-lates, hydrocarbons, or carbon monoxide in the futurẻ

(R) The Clean Air Act of 1977 requires the EPA to review all NSPS at least every four

years During this review, all aspects of the standard will be reviewed, including

the possible inclusion of emission limits for particulates, hydrocarbons, and

car-bon monoxidẹ

(R) The NSPS already applies to all gas turbines greater than 1000 hp, although those

between 1000 and 10 000 hp are exempt from the NÔ^ emission limit until 3 Oct

1982

(Q) In ađition to existing regulated pollutants, what other pollutants are under

reg-ulatory consideration in terms of meeting national primary and secondary air

quality standards?

(R) Other than the existing regulated pollutants, there are no ađitional pollutants

under regulatory consideration in terms of meeting national primary and

second-ary air quality standards

(Q) What is the present status of the final emission standards for stationary gas

tur-bines? List the exhaust gas emission standards expected to be published for

var-ious gas turbine configurations Also, what are the bases on which the emission

limitations are to be averaged, if any (for instance, daily, weekly, monthly, etc.)

for each of the regulated pollutants?

(R) The NSPS for gas turbines was promulgated in the Federal Register on 10 Sept

1979 Gas turbines between 1000 and 10 000 hp are required to meet a NỘ

emis-sion limit of 75 ppm beginning 3 Oct 1977, except for gas turbines used for oil or

gas transportation and production that are not located in metropolitan statistical

areas, which are required to meet a NÔ emission limit of 150 ppm All gas

tur-bines greater than 1000 hp must either fire a fuel with less than 0.8% sulfur or

have less than 150 ppm sulfur dioxide in the exhaust gas of the turbinẹ

(Q) To what extent are these considerations modified by the type of application, for

instance, peaking, intermediate load, or base load?

(R) An efficiency correction factor has been included in the NSPS for gas turbines

This allows turbines with thermal efficiencies greater than 25% to adjust the NO;^

emission limit upward as the efficiency of the turbine increases This correction

factor, however, may only be applied to the turbine itself and not to the turbine

plus any other ancillary equipment The efficiency correction is applied in this

manner to ensure the use of the best system of continuous emission reduction on

the turbine, as required by Section 111 of the Clean Air Act

(Q) What effluent regulations apply to stationary combustion turbine installations

where fuel-related sources of wastewater, such as those from residual fuel

treat-ment, water injection for NOj^ control, and power turbine water wash systems, are

present?

(R) No reply received

Economic Regulatory Administration (ERA)

The following questions were posed to the ERA, but no replies have been received:

(Q) The Power Plant and Industrial Fuel Use Act of 1978 encourages the use of

coal-derived liquid fuels in combustion turbines, both in a simple cycle and in

com-bined cycles with fired and unfired heat-recovery boilers What restrictions, if

any, will be imposed on users of this equipment with regard to backup or

second-ary fuel supplies?

(Q) What specific types of backup fuels (for instance, natural petroleum liquids or

natural gas or both) will be allowed for combustion turbine equipment designed

with synthetic liquid primary fuel capabilitỷ

(Q) Expressed as a percentage of the net annual generation and design unit heat rate

in Btu/kWh, how much backup fuel may be burned annually? (Also, please state

any other restrictions on the quantities of backup or secondary fuel which might

be envisioned)

(Q) Are blends of coal-derived liquids and natural petroleum liquids permissible for

combustion turbine installations not otherwise exempted under the provision of

the Fuel Use Act?

(Q) If blends of coal-derived liquids and natural petroleum liquids are permitted,

please state the proposed ratios by weight and any other applicable restrictions

(Q) The present regulations pertaining to the Fuel Use Act permit a five-year

tempo-rary exemption (with an additional five-year extension allowed, for a maximum of

ten years) to oil and gas fuel prohibitions if the user can guarantee that he will

bum synthetic (that is, coal-derived liquid) fuel at the end of the exemption

pe-riod In view of the developmental nature of coal-derived liquid fuel use in

com-bustion turbines, how much additional time will be granted the users to phase in

this new fuel with their existing plants, bearing in mind the load demand and

re-quirements for reliability of service?

(Q) To what extent are these considerations modified by the type of application, that

is, peaking, intermediate load, or base load?

Occupational Safety and Health Administration (OSHAj

The following questions were posed to OSHA, but no replies have been received:

(Q) What regulations are applicable to fuel-handling systems for stationary

combus-tion turbines?

(Q) Is it to be expected that these regulations will be modified for the use of synthetic

fuels for gas turbine use? What areas would be of primary concern (for example,

flash point, aromaticity, trace metals, flammability limits)?

References

\1\ Sullivan, R F., Stangeland, B E., Frumkin, H A., and Samuel C W., "Refining Shale

Oil," Proceedings of the American Petroleum Institute, Vol 57, pp 199-215 (43rd Midyear

Meeting, Toronto, Canada, 8-11 May 1978)

[2] "EDS Product Quality," Interim Report E-2893-68, Exxon Research and Engineering Co.,

Florham Park, N.J., March 1981

[3\ Sullivan, R F., O'Rear, D J., Stangeland, B £., and Fnimkin, H A., "Refining of

Syn-crudes," Preprint No 41-80, 45th Midyear Refining Meeting of the American Petroleum

In-stitute, Houston, Tex., 15 May 1980

[4\ Sullivan, R F and Frumkin, H A., "Refining and Upgrading of Synfuels from Coal and

Oil Shales by Advanced Catalytic Processes: Third Interim Report, Processing of SRC-II

Syncrude," (DOE Contract No EF76-C-01-2315) U.S Department of Energy, Washington,

D.C., March 1980

[5] Dakowski, M J., "Economic Screening Evaluation of Upgrading Coal Liquids to Turbine

Fuels," EPRI AF-710, Electric Power Research Institute, Palo Alto, Calif., March 1978

[6] Thomas R L., "Alternate Fuels for Industrial Combustion Engines," Report No FE

2468-77, Engineering Societies' Commission on Energy, Inc., Washington, D.C., June 1980

[7] Jones, G C , Jr., "Fuel Quality/Processing Study," Final Report, DOE/NASA/0175-1

Gulf Research and Development Co., Pittsburgh, Pa., May 1982

m O'Hara, J B., Bela, A., Jentz, N E., Syverson, H T., Klumpe, H W., Kessler, R E., Kot

zot, H T., and Loran, B I., "Fuel Quality/Processing Study," Final Report, DOE/NASA

0183-1, Ralph M Parsons Co., Pasadena, Calif., April 1981

Literature Survey of the Properties of

Synthetic Fuels Derived from Coal

REFERENCE: Flores, F 1., "Literataie Surey of the Properties of Synthetic Faeb Derived

from Coal," Stationary Gas Turbine Alternative Fuels ASTM STP 809, J S Clark and

S M DeCorso, Eds., American Society for Testing and Materials, Philadelphia, 1983,

pp 22-37

ABSTRACT: This report describes and summarizes a literature survey of the properties of

synthetic fuels for ground-based turbine applications, compiled up to October 1980 The

major processes for coal liquefaction (solvent extraction, catalytic liquefaction, pyrolysis,

and indirect liquefaction) and coal gasification (fixed bed, fluidized bed, entrained flow,

and underground gasification) are described Processes for upgrading coal-derived liquids

are discussed, and some property data for some coal-derived liquid and gaseous fuels are

presented

KEY WORDS; alternative fuels, synthetic fuels, coal, gas turbines, fuels

Natural gas and No 2 fuel oil are presently the most widely used fuels in

in-dustrial and utility turbine applications However, these fuels are becoming

more expensive and may not be available for future ground-based power and

steam generation Viable future fuels for ground-based gas turbines are heavy

petroleum fuel oils in the near future and possibly synthetic fuels derived from

coal and oil shale Adapting gas turbine technology for the use of synthetic fuels

requires the development of key capabilities

To address this need the National Aeronautics and Space Administration

and the Energy Research and Development Administration (ERDA) [later to

become the Office of Fossil Energy of the U.S Department of Energy (DOE)]

created the Critical Research and Advanced Technology Support (CRT)

pro-ject The CRT project was established to provide a gas turbine technical data

base for the DOE Integrated Coal Conversion and Utilization Systems

Pro-gram This program was aimed at developing utility power-conversion systems

^Aerospace engineer, NASA Lewis Research Center, Cleveland, Ohio 44135

that use coal and coal-derived fuels The scope of the CRT project included

emissions, materials, combustion, and fuels research

The literature survey, which is the subject of this report, was conducted as

part of the combustion and fuels portion of the CRT project The results of the

survey mclude information on coal-derived fuels that was available in the

lit-erature up to October 1980 The detailed data obtained from the survey are

presented in Ref 1,^ which updates and replaces a previously published

liter-ature survey [2] The physical and chemical properties of liquid and gaseous

fuels being produced in DOE pilot plants and upgrading programs are

pre-sented The report also describes coal liquefaction and upgrading and

gasifi-cation processes that are close to commercialization The fuels that were

investigated include low- and medium-Btu gases, heavy and light distillates,

and residual liquids

Discusdon of Fuel Properties

Table 1 [3] shows some suggested specifications for several types of liquid

fuels for advanced gas turbine industrial engines Table 2 [3] shows some

typi-cal ranges of properties for liquid fuels currently used in industrial gas turbine

systems The importance of these specifications is examined here For a more

detailed discussion, see Ref 3

Physical property data, such as the pour point, viscosity, and distillation

range, are important in determining the pumping, heating, and atomization

characteristics of the fuel The thermal stability, which is the tendency of the

fuel to form deposits or sediments in fuel systems, is a most important

prop-erty for the higher viscosity residual fuels These fuels may requhre heating to

meet viscosity requirements The heating required for these fuels may lead to

deposit formation

Chemical properties such as the elemental composition (carbon, hydrogen,

nitrogen, sulfur, and oxygen) are important in determining the combustion,

emissions, and corrosion characteristics of the fuel The hydrogen content is a

critical factor in controlling the smoke emission levels and the radiation

prop-erties of the gases in the combustor The higher the hydrogen content of the

fuel, the less tendency it has to smoke and the less tendency it has to radiate

heat to the combustor walls Fuel-bound nitrogen will contribute to the

nitro-gen oxides (NOx) pollutant emissions, since varying amounts of fuel-bound

nitrogen are converted to NO^ during the combustion process The nitrogen

content is also related to thermal stability Most nitrogen compounds tend to

make the fuel less, stable Sulfur in fuel produces sulfur oxides during

combustion that are pollutant emissions The ash and trace metal

con-taminants, which are likely to be concentrated in the higher boiling fractions

during processing, can lead to turbine corrosion and deposits

^The italic numbers in brackets refer to the list of references appended to this paper

B 3C

h Si (U E

4 J CD I-H O i

• H

Pu

d

^

d

1 H

Coal Liquefaction Processes

Four major processes have been developed for converting coal to liquid

fuels (Fig 1): pyrolysis and hydrocarbonization, solvent extraction, catalytic

liquefaction, and indirect liquefaction Each process is discussed briefly here,

and the most important facilities that use each process are listed The

technol-ogy for coal liquefaction is reviewed in detail in Refs 4, 5, and 6

Pyrolysis, or carbonization, takes place when coal is heated in the absence

of air or oxygen to obtain heavy oil, light liquids, gases, and char When

py-rolysis is carried out in the presence of hydrogen, it is called

hydrocarboniza-tion Pyrolytic processes typically convert about 50% of the coal to char,

which at present does not have a ready market Using short residence times or

pyrolyzing coal in a fluidized bed at high pressures in the presence of

hydro-gen improves liquid yields but may require additional processing to reduce the

sulfur in the products Pyrolytic processes include the Lurgi-Ruhrgas, char oil

energy development (COED), U.S Steel clean coke, Coalcon, and flash

hy-dropyrolysis processes

In solvent extraction processes, pulverized coal is mixed with a solvent

con-tainmg phenols, naphthene, benzene, and naphthalene compounds These

compounds can transfer hydrogen atoms to the coal in a reactor at high

tem-peratures and pressures The recycle solvent, usually a process-derived liquid,

is continuously recovered and recycled to the extraction vessel The ash in the

extraction vessel can act as a catalyst for the solvation process Solvent

extrac-tion processes include the Consol synthetic fuel (CSF), solvent-refined coal

(SRC), co-steam, and Exxon donor solvent (EDS) processes

Catalytic liquefaction includes those hydrogenation processes in which

catalysts other than the mineral matter naturally occurring in ash, are used to

promote hydrogenation of the donor solvent The catalysts usually used are

Lewis acids such as iron oxide (FeO), molybdenum oxide (MoO), zinc

chloride (ZnCla), and nickel chloride (NiCl2) Two main methods are

em-ployed in catalytic liquefaction processes In the first one, the catalyst and the

coal are in direct contact in the reactor, hydrogen gas is introduced, and rapid

hydrogenation is achieved Examples of these processes are the Schroeder and

liquid-phase zinc chloride processes In the second method, the coal and the

catalyst are not in direct contact, but the suspended pelletized catalyst

pro-motes hydrogenation of the carrier solvent, which in turn hydrogenates the

coal Examples of these processes are the H-Coal, Synthoil, and clean fuel

from coal processes

Indu-ect liquefaction involves gasification of coal to prodiice a synthesis gas

(hydrogen plus carbon monoxide), followed by a water gas shift and catalytic

conversion to produce liquid hydrocarbons and oxygenated compounds

Indi-rect liquefaction processes include the Fischer-Tropsch, methanol synthesis,

and methanol to gasoline conversion processes

Upgrading of Coal Liquids

Existing technologies for upgrading coal liquids come largely from

petro-leum refining Upgrading of coal liquids includes the removal of oxygen,

ni-trogen, and sulfur by catalytic hydrotreating, and boiling range conversion by

fluid catalytic cracking (FCC) and hydrocracking Coal liquids are highly

aro-matic and most of the contaminants (oxygen, nitrogen, and sulfur) are

con-tained in these aromatic structures, making their removal more difficult than

removing them from petroleum [7\ The concentration of heavy metals (which

deactivate the catalysts) may also be higher in coal liquids than in petroleum

Studies of catalytic hydrotreating have been performed using mainly

liq-uids derived from the Synthoil, SRC, and H-Coal processes [8-12]

Hydro-treating was performed on the whole crude and on fractions such as naphtha

and middle distillates using fixed-bed and expanded-bed reactors Very little

work has been done on boiling range conversion processes Gulf Research and

Development Corp., under contract to DOE, performed a study on the

process-ing of coal liquid residuals by cokprocess-ing followed by fluid catalytic crackprocess-ing [13]

Data on Dqoid Fuels Properties

The main objective of the literature survey was to obtain property data on

coal-derived fuels, including density, boiling range, freezing point (or pour

point), flash point, viscosity, ash content, heat of combustion, trace metal

content, thermal stability, hydrocarbon type, elemental analysis, and various

other properties Values for these properties were not always available in the

literature However, the existing data found in the literature have been

com-piled and are presented in detail in Ref / These data are summarized in

Table 3 The fuels were classified according to the process from which they

were derived Within any process, the characteristics were tabulated for

dif-ferent boiling range fractions as well as for the total crude Property data from

some hydroprocessed coal-derived liquids are also included The various

distil-lation cuts are put into three general categories: light distillates (naphtha, light

oil, and so forth), middle distillates (diesel fuels), and heavy distillates (heavy

oils and residual fuels)

The literature survey emphasized those processes that are the most

ad-vanced in terms of development and were still being developed at the time of

the survey This criterion could probably have restricted the search to the

li-quefaction processes of H-Coal, Synthoil, SRC, EDS, and COED However,

it was felt that including data on some of the newer processes Hke the clean

cool liquid (CCL) and the liquid phase zinc chloride processes, could also be

useful

Some of these data are plotted in Figs 2 through 4 Although different

boil-ing ranges are included, all the data available for each fuel are plotted,

re-gardless of the type of process or the type of distillate cut

TABLE 3—Summary of the properties of coal-derived liquid fuels

BoUIng

ranget

°F

Gnvltjr API Specific

Elemental oompoeltloD, wt %

Viscosity, cP

at 100° F

at 210° F

Heat of combustion, Btu/lb H-Coal process

- 7 5 -16.5 -17.7 19.8 32.3 13.0 17.0 37.4 6.6 6.4 38.6

14.0 -2.3

15.0 4.4 26.8

0.81 77 80 22 047 0044 0083 1.3 1.11 1.30 44 42 446 683 212 871 81 19 42 1.01 77 39 1.30 1 1 1 1 68 1.05 64

.42 13

0.47 15 23 16 26 17 17 48 1.43 66 21 13 29 27 06 35 22 24 18 22 42 19 95 1 1 3 1 19 43 16 11 13 25 26 12 09 24

178

272 2.47

2.4 1.08 3.87 6.1 96 14.9

155 4.45

7 2 8.8 99

(465 cP)

2.7

36 318.3

Figure 2 shows the general trend of increasmg weight percent of hydrogen

with increasing gravity [indicated by American Petroleum Institute (API)

des-ignations] of the product, regardless of the process by which it was produced

Data for only one fuel (an H-Coal derived fuel) were significantly different

from the general trend

Figure 3 shows how the nitrogen content varies with the percentage of

hy-drogen As hydrogenation severity is increased in the fuel production process,

the fuel-bound nitrogen is decreased, as would be expected, because some

fuel-bound nitrogen is converted to ammonia The data for the zinc chloride

at 210° F

Heat of combustion

- 6 19.7 11.4

- 3 9 3.9

- 4 3 15.9 9.4

- 2 9 4.0

1.125 1.1055 1.1124 1.0035 1.081 936 950 1.109

1.10

7.72 7.58 7.42 9.77

7.72

7.97

1.190 1.46 1.31 377 786 423 724 1.187 1.205 79 1.22 32 47 97 81

1.021 55 56 02 42 20 30 44 1.057 22 31 14 12 43 21

450 2.27 9.56

673 7.23 35.9

2509 143.5

43.65 34.25 56.20

359.1 1.85 3.91 28.6 16 891

17 245 SRC process

- 5 8 2.5 9.6 22.6 4.69 12.3 20.0 35.6 5.64 5.48 5.48 5.3

.9182 1.039 984 934 847 1.0318 1.0333 1.0333

6.56 6.12 5.62 S.4S 7.9 11.5 6.90 8.76 9.98 7.56 8.6 10.1 11.33 7.65 7.43 8.78 7.43

1.87 1.89 1.91 1.95 2.0 9 4 1.28 548 23 59 6 6 30 59 62 50 62

1.07 88 1.10 1.09 8 3 2 72 02 40 32 2 3 60 41 37

35 37

7 3

1900

1.441 5.88 2.75 794 5.56 5.79 10.44 5.79

20.45 32.69 647 1.464

1.45 1.48 2.25 1.48

hydrocracking process [14], not plotted in Fig 3, showed nitrogen levels

sig-nificantly lower then those of any other process-derived fuel at comparable

hy-drogen levels In the hydrocracking process, the bonds between carbon and

other atoms (oxygen, nitrogen, sulfur) are usually broken, resulting in higher

conversion to ammonia and a lower nitrogen content in the product fuel

Ni-trogen levels for the zinc-chloride-derived fuels were from 0.0018 to 0.0019%

by weight for hydrogen levels of 8.3 to 9.65% by weight

Figure 4 shows how the heat of combustion for liquid fuels varies with the

weight percent of hydrogen for those few fuels for which such data were

re-ported Again, the trend is independent of the processing type

Elemeatal compoeltloii, wt %

S Vlaoosl^, cP

at 100° F

at 210° F

Heat of combustion

Btu/lb SRC process (Concluded)

175 - 857

180 - 818

172 - 814

13.0 14.5 23.4

10.32 10.99

0.44 U 02

0.06 01 01

3.43 2.20 2.00

1.10 93 90

17 728

18 572

18 903 COED process

4 0 4 18.8 10.1

20

22 18.4

22 S

11.2 41.9 22.5 19.0 22.3

11.5 13.0 11.2 10.7

11.0 10.9

11.97 12.13

0.125 056 16 09 226 190 248 294 2 3

.193 143 25 0388

0.013 0049 0055 0090 08 05 04 01 1 1 16 004 07

« 0 1 05 18 0271

5.1 89 4.51

5 8.1 3.9 94 6.82

0.51 50 31 40 82

.04 04 17 Exxon Qonor Solvent process

1.01

10.90 12.90 7.70

0.21 06 66 24

0.47 005 41 04

18 300

19 300

17 100

18 100

Coal Gasification Processes

The primary purpose of gasification processes is to provide clean fuels in

gaseous form that, when burned, will meet existing emission standards

Gasi-fication processes are based on thermal decomposition of coal and

gasifica-tion or combusgasifica-tion of the resulting char The products of gasificagasifica-tion are

clas-sified as low- and intermediate-Btu gases Low-Btu gas [with a heating value

below ~ 7000 Btu/m^ (200 Btu/standard ft^)] is made by gasifying coal with

air and steam To produce medium-Btu gases, oxygen-blown gasifiers (which

will eliminate the nitrogen in the product gas) can be used, or methanation of

the synthesis gas can be incorporated into the process Four major methods

TABLE 3—Continued

Bolllhg

range

Gravity API StMClflC

Elemental compoeltkm, wt %

Vlaeaeltr c P

at IOO"F

i t

i i o ' r

Beat of oombuatloa, Blu/lb

0.0023 0018 0025 0060 0020 0023 0194

«

.02 02 03 02

0 01 Co-Steam proceaa

7 1 6.8 6.6

1.1 1.1 1.1

0.13 10 12

17 0»«

16 886

16 906 Flaah Pyrolysls proceca

406 - >620

411 - 7 4 5

6 IS 6.18 1.13 1.43 0.56 54 Sea Coal praceM

FIG 2—Variation of the hydrogen content of coal-derived fuels with the API gravity

for coal gasification have been developed: fixed bed, fluidized bed, entrained

flow, and underground gasification The technology for coal gasification is

re-viewed in detail in Ref 15 A brief summary is presented in this section

In fixed-bed gasifiers, coal is fed into the top of the gasifier and moves slowly

downward in a bed through which air or oxygen flows upward The

counter-current contact permits both the coal and the gaseous reactants to be

14

FIG 4—Variation of the heat of combustion of coal-derived fuels with the hydrogen content

heated before gasification, thus increasing the overall thermal efficiency The

relatively long residence time of the fuel in the reaction vessel permits high

carbon conversion The long residence time reduces gasification rates, but

be-cause of the higher carbon conversions, thermal efficiencies are high The

dis-advantage is that the softening, thickening, and swelling behavior of certain