EPA-660/2-75-011
MAY 1975
Environmental Protection Technology Series
Process and Environmental Technology
for Pfodiicing SNG and Liquid Fuels
National Environmental Research Center
Office of Research and Development
U.S. Environmental Protection Agency
Corvaliis, Oregon 97330
-------
RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development,
U.S. Environmental Protection Agency, have been grouped into
five series. These five broad categories were established to
facilitate further development and application of environmental
technology. Elimination of traditional grouping was consciously
planned to foster technology transfer and a maximum interface
in related fields. The five series are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
This report has been assigned to the ENVIRONMENTAL PROTECTION
TECHNOLOGY STUDIES series. This series describes research performed
to develop and demonstrate instrumentation, equipment and methodology
to repair or prevent environmental degradation from point and
non-point sources of pollution. This work provides the new or
improved technology required for the control and treatment of
pollution sources to meet environmental quality standards.
EPA REVIEW NOTICE
This report has been reviewed by the Office of Research and
Development, U.S. Environmental Protection Agency, and approved
for publication. Approval does not signify that the contents
necessarily reflect the views and policies of the U.S. Environmental
Protection Agency, nor does mention of trade names or commerical
products constitute endorsement or recommendation for use.
-------
EPA-660/2-75-Oil
MAY 1975
PROCESS AND ENVIRONMENTAL TECHNOLOGY
FOR PRODUCING SNG AND LIQUID FUELS
By
Milton R. Beychok
Contract No. 68-03-2136
Program Element 1BB036
ROAP/Task No. 21 AZP/044
Project Officer
Mr. Fred M. Pfeffer
Robert S. Kerr Environmental Research Laboratory
National Environmental Research Center
Ada, Oklahoma 74820
NATIONAL ENVIRONMENTAL RESEARCH CENTER
OFFICE OF RESEARCH AND DEVELOPMENT
U.S. ENVIRONMENTAL PROTECTION AGENCY
CORVALLIS, OREGON. 97330.
For sale by the Superintendent of Documents, U.S. Government Printing Office
Washington D.C. 20402 - Stock No. 055-001-01017
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ABSTRACT
This report presents the process technology and environmental
factors involved in the emerging industries for providing new
supplemental energy supplies from non-conventional sources. It
includes: (1) the production of substitute natural gas (SNG)
from coal, crude oil and naphtha, (2) importing overseas gas
supplies in the form of liquefied natural gas (LNG) and as
liquid methanol, (3) the regasification of LNG, (4) the pro-
duction of liquid fuels from oil shale, and (5) the liquefac-
tion of coal to produce clean fuels. The report also includes
introductory chapters to familiarize the reader with the
technology of oil and gas processing, heat balances, fuel
combustion and stack gases, thermal efficiencies, and water
balances.
In most cases, the report identifies and quantifies the envir-
onmental emissions and effluents from each technology by
specific examples from actual designs. It also presents a
brief description of the process technology involved. Each of
the sections on the individual technologies includes a recom-
mended list of additional reading.
The report is oriented more towards providing environmental
data rather than providing detailed process design factors.
Insofar as possible, the report was written for a broad range
of general readers instead of experienced process engineers.
The data provided is inter-disciplinary in nature since it
covers air emissions, water disposition and effluent treatment,
thermal balances, noise factors, solid wastes, and some of the
socio-economic factors.
This report was written and submitted in fulfillment of Contract
Number 68-03-2136, by Milton R. Beychok, Consulting Engineer,
under the sponsorship of the Environmental Protection Agency.
Work was completed as of December 1974.
11
-------
CONTENTS
Sections
I Background 1
II Introduction 3
III Heat Balances, Combustion Gases and
Overall Water Balances 14
IV SNG from LPG and/or Naphtha 23
V SNG from Coal 34
VI SNG from Crude Oil 54
VII LNG -- Liquefaction at Source 66
VIII LNG -- Regasification at Market 74
IX Methanol Fuel 82
X Natural Gas Pipelines 95
XI Liquid Fuels from Oil Shale 105
XII Coal Liquefaction 127
XIII Glossary 141
111
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FIGURES
No. Page
1 Process Flow Diagram - SNG from Naphtha 26
2 Process Flow Diagram - SNG from Coal 36
3 Coal Gasification Plant - Water Reuse Systems 44
4 Process Flow Diagram - SNG from Crude Oil 56
5 Process Flow Diagram - LNG Liquefaction 68
6 Process Flow Diagram - LNG Regasification 75
7 Process Flow Diagram - Methanol Fuel 88
8 Process Flow Diagram - Gas Pipeline System 96
9 Oil Shale Distribution in the Green River
Formation 107
10 Process Flow Diagram - Shale Oil Production 111
11 Process Flow Diagram - Tosco II Retorting 112
12 Process Flow Diagram - Coal Liquefaction
(COED Process) 132
13 Process Flow Diagram - Coal Liquefaction
(Garrett Process) ' 133
14 Process Flow Diagram - Coal Liquefaction
(H Coal Process) 135
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TABLES
No. Pages
1 Fuel Heating Values 8,9
2 English-to-Metric Unit Conversions 13
3 Flue Gas Rates 19,20
4 Thermal Efficiency of SNG Production
from Naphtha 24,25
5 Sulfur Balance for SNG Production from
Naphtha 28,29
6 Water Balance for SNG Production from
Naphtha 30
7 Water Requirements and Disposition
(Coal Gasification) 45
8 Stack Gases from Coal Gasification 47,48
9 Stack Gases from SNG Refinery 62,63
10 Tanker Requirements (Methanol Vs LNG) 84,85
11 Gas Pipeline Costs 98,99
12 Some Gas Pipeline Statistics 100,101
13 Stack Gases from Shale Oil Production 117,118
14 Water Requirements and Disposition
(Shale Oil Production) 120
15 Coal Liquefaction Processes 129
16 Developmental Status of Coal Liquefaction 130
v
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SECTION I
BACKGROUND
Based on current trends in the supply and demand of energy, the
world faces a very serious shortage of petroleum crude oil. Middle
Eastern politics have compounded the oil shortage for the indust-
rialized nations of the world. But regardless of the ultimate
resolution of the Middle East situation, the shortage between
supply and demand will still exist and the energy 'crisis' will be
with us for a long time to come. Unless we develop alternative
energy supplies, we face a tremendous economic drain of our capital
resources from the high cost of imported crude oil.
In the United States, the shortage of domestic crude oil is further
compounded by an equally serious dwindling of natural gas supplies.
Although we could supply most of our energy needs for hundreds of
years by utilizing our vast reserves of coal, public concern with
the environmental effects of coal mining and coal burning has
worked against the direct use of coal for heat and power generation.
As a result of this situation, the U.S. government has initiated
Project Independence to develop supplemental domestic energy sources
and supplies. The nation's energy-supplying industries have under-
taken a dramatic acceleration in the search for alternative methods
of producing clean-burning gas and liquid fuels from a wide variety
o£ domestic resources such as coal, oil shale and even municipal
refuse. At the same time, these industries have intensified their
search for overseas gas supplies which can be imported into the
i
United States.
./.
The purpose of this report is to explain in relatively simple terms
the processes and technology currently available for: (1) producing
substitute natural gas (SNG), (2) importing overseas gas supplies
in the form of liquefied natural gas (LNG) or as liquid methanol,
(3) the conversion of coal into low-sulfur oil and (4) the production
of low-sulfur oil from oil shale. In the next few years, Federal and
1
-------
State environmental agencies will undoubtedly become involved in
regulating the air emissions, water effluents and solid wastes
from these new •emerging industries'.
This report is intended for use as a reference 'primer' by those
environmental agency personnel who will be concerned with the
environmental regulations for these new industries producing and
transporting alternative energy supplies. Therefore, the report
is oriented more towards the environmental factors of the various
process technologies than towards detailed technical design
factors. The report was not written for the engineer who is already
expert in the technologies involved, but rather for those who need
a broad overview and a generalized understanding in order to better
evaluate the environmental factors involved in these new industries.
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SECTION II
INTRODUCTION
Some knowledge of the composition of natural gas and crude oil
is required to become familiar with the technology of producing
alternative energy supplies. An understanding of the terminology,
or technical 'jargon1 used in the oil and gas industries is also
needed. This section is intended to provide that basic introductory
knowledge with a narrative discussion, followed by a glossary of
terms and definitions.
The traditional English engineering units of measure-
ments and special 'trade* units are deeply ingrained
into the terminology of the oil and gas industries.
Those traditional units are retained throughout the
narrative text of this report so that the reader may
learn to understand the language of the oil and gas
industries. However, all of the tables in the report
are separately presented in English units and in the
SI metric system (for example, Table IE is in English
units and Table 1M presents the same data in the SI
metric system). In addition, a conversion table is
included at the end of this section so that the reader
may convert terms and units appearing in the text into
metric units if desired.
HYDROCARBONS AND WHAT THEY ARE
Both raw natural gas and petroleum crude oil are mixtures of
'hydrocarbons', which are chemical molecules composed of hydrogen
and carbon atoms. These molecules may be quite simple or quite
complex in their structural arrangement (or 'linkage') of atoms.
The carbon atoms may be linked together in short or long straight
chains, or they may be linked in complex rings or cyclic arrange-
ments. The usual simple hydrocarbons found in natural gas are
called 'normal paraffins' or 'saturated hydrocarbons' because each
carbon atom is linked to a maximum number of hydrogen atoms in
accordance with the generic formula of C H2n+2* ^or examPle» a
saturated hydrocarbon with 3 carbon atoms would contain 8 hydrogen
atoms.
-------
Hydrocarbons with only a few carbon atoms (from 1 to 6) are
referred to as 'light' hydrocarbons and those with more carbon
atoms are 'heavy* hydrocarbons. The very light hydrocarbons
(1 to 4 carbon atoms) are gases under natural conditions, although
they can be liquefied by refrigeration or by a combination of
compression and cooling. Each hydrocarbon has a specific formula
and chemical name, but in common usage they are also frequently
referred to by the number of carbon atoms they contain. The
following list of hydrocarbons and their symbols is not by any
means complete, because there are many molecular structural arrange-
ments other than the normal, or saturated, hydrocarbons:
Chemical Carbon Atoms Common Usage
Name Per Molecule Symbol
Methane 1 C--
Ethane 2 C2
Propane 3 C^
Butane 4 C.
Pentane 5 C,-
Hexane 6 Cc
b
Heptane 7 C?
Octane 8 CQ
NATURAL GAS
Raw natural gas, as it occurs in nature, is predominantly methane
but it almost always contains some of the other very light hydro-
carbons (ethane, propane, and butane) and it may also contain
some pentane, hexane and even heavier hydrocarbons. A raw natural
gas which contains significant amounts of C3> C4, C,_» Cfi and
heavier is called a 'wet gas', and one which contains mostly methane
and some ethane (C- and some C~) is called a 'dry gas1. The terms
'wet' and 'dry' denote in a very relative manner whether or not the
gas contains hydrocarbons heavier than ethane.
The C,, and C\ (propane and butane) in a raw natural gas can be
removed and recovered as liquids by relatively simple processing.
-------
Those liquids are called LPG (liquefied petroleum gas) and are
subcategorized as C3 LPG and C4 LPG, or Propane LPG and Butane LPG.
When contained under pressure, LPG can be stored and shipped as a
liquid for end-use as fuel.
The Cg, Cg, Cj and heavier molecules in a raw natural gas can be
very readily removed and condensed into a liquid commonly referred
to as 'condensate' or as 'natural gasoline1 because it can be used
as a component of gasoline.
The C~ (ethane) in a raw natural gas can also be removed and
recovered, but it requires relatively complex processing. Whereas
LPG and condensate are almost always removed and recovered from
raw natural gas, the removal and recovery of ethane depends on how
much is present and the economic viability of that recovery. Among
other uses, ethane is used as a petrochemical feedstock in producing
polyethylene plastics.
Raw natural gas usually contains other non-hydrocarbon gases,
such as water vapor and the so-called 'acid-gases' which are
hydrogen sulfide (H2S) and carbon dioxide (C02)• A natural gas
with a relatively high H~S content is called a 'sour* gas, while
one with a low H«S level is called a 'sweet' gas. In order to meet
pipeline and end-use specifications, a raw natural gas must be
processed, or 'treated1, for removal of H2S and C02 down to very
low levels. LPG and condensate are usually removed and recovered
because it is economically advantageous to do so, and because the
end-use natural gas specification on heating value may require
their removal. Water vapor must also be removed to meet pipeline
gas specifications.
Treated gas specifications will vary from one project to another.
However, as a broad generality, treated gas specifications will
-------
fall within the following ranges:
Methane 85 - 99+ vol %
Ethane and heavier 0-15 vol %
Inert gases 0-3 vol % *
H2S 0.20 - 0.50 grains/100 SCF **
C02 0-2 vol %
Water vapor As required by dewpoint specifications
Heating value 950 - 1150 BTU/SCF (HHV)
We can thus conclude that raw natural gas is not precisely
definable in terms of composition and that it may contain a range
of hydrocarbons, inert or non-combustible gases, acid gases and
water vapor. Before being shipped to the end-use market, the raw
gas is usually processed, treated and dehydrated for: (1) recovery
of LPG, condensate (natural gasoline), and perhaps for ethane and
(2) removal of the acid gases (H2S and C02) and water vapor. The
plants which process the raw natural gas into a treated end-use gas
are variously called 'field gas plants', 'gas treating* plants or
•gas recovery1 plants. The liquids recovered include C3 LPG,
C4 LPG and condensate. Sometimes all of these are collectively
called NGL (natural gas liquids). When the processed or partially
processed natural gas is liquefied for overseas shipment it is
called LNG (liquefied natural gas).
After all that processing, it is really a contradiction in terms
to call the end-use product a 'natural' gas — about all we can say
is that it is predominantly methane.
CRUDE OIL
Crude oil as pumped from underground wells is a very broad mixture
of hydrocarbons, ranging from about 5 carbon atom molecules to
* Typical inert gases that may be present are nitrogen, helium,
argon, etc. Occasionally, some oxygen may be present.
** 0.00068 - 0.00169 wt % HS.
-------
20 or more carbon atom molecules (C5 to C2Q ).
Both natural gas and crude oil occurring in nature may be found
alone or in combination. A raw natural gas may contain a good
bit of GC> C&, and C_ as well as methane, ethane, propane and
butane; on the other hand, raw crude oil may contain some 'dry'
gas (C.. and C2) as well as C3 and C.. When the oil well produces
large amounts of raw natural gas as well as crude oil, the two are
usually separated at or near the well-head, and the separated raw
natural gas is called 'associated gas1 (as distinguished from non-
associated gas produced from a gas well). When the crude oil contains
only nominal amounts of light gas, it is generally shipped "as is"
to an oil refining plant, where the gas is ultimately separated from
the oil and used as refinery fuel.
Since crude oil is such a broad hydrocarbon mixture, and since the
light hydrocarbons have lower boiling points than the heavy hydro-
carbons (see Table 1), the first step in refining crude oil is to
simply 'distill' or boil off the light hydrocarbons. The light
gases (C.. through C.) distill off first since they have the lowest
boiling points. They are processed in a gas recovery and treating
plant within the refinery to produce fuel gas (C., and C-) and LPG
(C3 and C.). The next material which boils off is naphtha or
gasoline, a mixture of liquid hydrocarbons boiling over the range of
100°F to about 400°F and containing hydrocarbons ranging from Cg
to C. (see Table 1). The next hydrocarbon mixture to boil off is
diesel oil containing C-Q "to C-n and boiling over the range of
350°F to 550°F. Following that, a light fuel oil, or 'distillate
oil', is boiled off.
At this point, the remaining residual crude oil would begin to
suffer degradation to coke if the boiling were continued at too
high a temperature. So the residual crude oil from the 'atmospheric
distillation' unit is next distilled under vacuum to produce heavy
fuel oil. The light and heavy fuel oils contain hydrocarbons in
-------
TABLE IE - FUEL HEATING VALUES - ENGLISH UNITS
CO
Carbon
Atoms
Per
Hydrocarbon Molecule
Methane
Ethane
Propane
Butane
Pentane
Naphtha 5
Diesel Oil 10
Fuel Oil 16
Others
Hydrogen -
Petroleum Coke -
Coal (New Mex. )
As mined -
Dry & Ash- free
1
2
3
4
5
to 11
to 15
plus
_
-
_
Weight %
Carbon
75
80
82
83
83.4
85
87
88
0
96
51
77
Hydrogen
25
20
18
17
16.6
15
- 13/c,
11(5)
100
2<6)
/ T \
4(7)
6(8)
Heating Value
Net
Btu/lb
21,500
20,400
19,900
19,700
19,500
19,200
18,300
17,600
__
—
"
Gross
Btu/lb
23,900
22,300
21,700
21,300
21,100
20,700
19,500
18,700
61,100
15,200
8,800
13,200
Gross
Btu/SCF (1)
1010
1765
2520
3260
—
—
—
—
320
— M
— _
Boiling Point
@ Atm. Pressure
OF
-259
-128
- 44
31
97
100 to 400
350 to 550
650 plus
-423
__
— —
(2)
(3)
(4)
(1) Standard cubic feet (SCF) of gas, measured at 60°F and atmospheric pressure
(2) Initiates boiling at lOQOF and ends boiling at 400QF
(3) Initiates boiling at 350°F and ends boiling at 550°F
(4) Initiates boiling at about 650°F and ends boiling much higher
(5) The remaining 1% is primarily sulfur and nitrogen, with traces of heavy metals
(6) The remaining 2% is primarily sulfur, nitrogen and ash, with traces of heavy metals
(7) The remaining 45% is mostly moisture, ash, sulfur, nitrogen, bound oxygen and traces
of many other elements
(8) The remaining 17% is mostly sulfur, nitrogen, bound oxygen and traces of other elements
-------
TABLE 1M - FUEL HEATING VALUES - METRIC UNITS
<£>
Carbon
Atoms
"Da>-
Jk \_--J_
Hydrocarbon Molecule
Methane
Ethane
Propane
Butane
Pentane
Naphtha
Diesel Oil
Fuel Oil
Others
Hydrogen
Petrpleum Coke
Coal (New Mex. )
As mined
Dry & Ash- free
1
2
3
4
5
5 to 11
10 to 15
16 plus
__
—
—
Weight %
Carbon Hydrogen
75
80
82
83
83.4
85
87
88
0
96
51
77
25
20
18
17
16.6
15
13
11
100
2(6)
/ __ \
4(7)
6(8)
Heating Value
TVL_
,-.4-
INC i~
Kcal/kg
11
11
11
10
10
10
10
9
,955
,340
,065
,955
,840
,675
,175
,785
—
. e? c5
/"» »-^-vO O
Boiling PC
la) a-t-m _ TSirof
>int
3011t*0
Kcal/kg Kcal/nm3 (l) °C
13,
12,
12,
11,
11,
11,
10,
10,
33,
8,
4,
7,
290
400
065
845
730
510
840
395
970
450
890
340
9,500
16,600
23,700
30,665
—
—
—
— —
3,010
—
__
-162
- 89
- 42
- 0.6
36
38 to 204
177 to 288
343 plus
-217
—
__
(2)
(3)
(4)
(1) Normal cubic metre (nrrr^) of gas, measured at 0°c and atmospheric pressure
(2) Initiates boiling at 38°C and ends boiling at 204°C
(3) Initiates boiling at 177°C and ends boiling at 288°C
(4) Initiates boiling at about 343°C and ends boiling much higher
(5) The remaining 1% is primarily sulfur and nitrogen, with traces of heavy metals
(6) The remaining 2% is primarily sulfur, nitrogen and ash, with traces of heavy metals
(7) The remaining 45% is mostly moisture, ash, sulfur, nitrogen, bound oxygen and traces
of many other elements
(8) The remaining 17% is mostly sulfur, nitrogen, bound oxygen and traces of other elements
-------
the range of C-Q and heavier and boil at temperatures of 650°F
and higher (see Table 1).
All of the materials boiled off in the atmospheric distillation
unit (or 'crude unit1) and in the vacuum unit are referred to as
'virgin' — virgin naphtha, virgin diesel, virgin fuel oils, etc.
The final residual material is called 'vacuum residuum' or 'vacuum
bottoms' or simply 'resid'.
Almost all of the virgin materials are then processed through a
host of other steps, which can be combined into hundreds of different
'refinery configurations' to produce any desired 'slate' or end-
products. The typical product slate for a 'motor fuels refinery'
may include:
1. Two or three grades of gasoline (regular, premium,
low lead, etc.)
2. C3 and C4 LPG
3. Diesel oil and/or jet fuel, which are quite similar
4. A range of industrial heating fuel oils (No. 2 distillate
oil, No. 6 fuel oil, etc.)
5. By-product sulfur
6. Asphalt, tar and/or petroleum coke
Other slates would be produced by 'lube oil refineries',
'SNG refineries', 'fuel oil refineries', etc. It is beyond the
scope of this basic handbook to attempt an explanation of all the
available refining processes or of the numerous possible combina-
tions of those processes into different refinery configurations.
Returning to gas wells and oil wells 5 most of the naturally
occurring C. and C~ are obtained from gas wells, while most of the
naphtha and heavier distillate oils are derived from crude oil wells.
C3 and C4 LPG may come from either gas or oil wells. ' Light naphtha
(GET, Cf- and CT) may also come from either source, but by far the
-J Q /
largest part of the total naphtha production comes from crude oil.
So, if there is any typical breakpoint between the composition of
10
-------
raw natural gas and raw crude oil, it is between butane (C.) and
pentane (C,-). However, as mentioned earlier, either raw natural gas
or raw crude oil may contain hydrocarbons normally found in the other,
Summarizing some of the commonly used terms mentioned in the preceding
discussion:
Symbol
1
and
and
C - C
C - C
3,
C -
c5-c
CO
Physical
Form
gas
liquid
gases
l-iquids
gases
liquid
liquid
liquids
liquid
liquid
liquid
gases
Common Usage Names
Methane (primary constituent of
natural gas)
Liquefied natural gas (LNG)
Dry gas
Liquefied petroleum gas (LPG)
Light hydrocarbons, or 'light ends'
(in a refinery)
Condensate or natural gasoline
(when derived from raw natural gas)
Light naphtha or light gasoline
(when derived from crude oil)
Natural gas liquids (NGL) as a
collective term (when derived from
natural gas)
Naphtha or gasoline (or full-range
naphtha and full-range gasoline)
Diesel oil, jet fuel, light distillate
oil, light furnace oil
Fuel oil, heavy fuel oil, heavy
distillate oil, heavy furnace oil,
bunker oil, resid
Acid gases
SUBSTITUTE NATURAL GAS
Substitute natural gas (SNG) is a methane-rich gas manufactured from
coal, LPG, naphtha, crude oil or other materials containing carbon.
The carbon in the feedstock material is chemically combined with
hydrogen to yield methane (CH.). The hydrogen is usually derived
from steam and may be augmented by hydrogen already present in the
11
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feedstock (as in the case of LPG, naphtha or other hydrocarbons).
In other words, the chemical addition of hydrogen to a heavy hydrocarbon
changes it to a lighter hydrocarbon and, if sufficient hydrogen is
added, we obtain methane — the lightest of the hydrocarbons.
Various names have been used to describe manufactured methane, such
as:
Substitute natural gas (SNG)
Synthetic natural gas (SNG)
Substitute pipeline gas (SPG)
Synthetic pipeline gas (SPG)
Supplemental pipeline gas (SPG)
In any event, they are all meant to describe a manufactured gas
containing about 97% methane, having a higher heating value (HHV) of
about 1000 Btu/SCF, and meeting the same end-use specifications as
pipelined natural gas.
In the United States, gas distribution systems and gas-burning
appliances have been designed to handle natural gas which has an HHV
of about 1000 Btu/SCF (a gas of about that heating value is referred
to as 'high Btu gas1) and a plant producing SNG for pipeline distribu-
tion must therefore manufacture a gas meeting that specification.
If the gas were to be used at the point of manufacture, as a fuel
source in electrical power generation for example, then it could be
a 'low-Btu gas' with an HHV of about 350 Btu/SCF or even less. A
low-Btu gas may contain varying amounts of carbon monoxide, carbon
dioxide and hydrogen, as well as varying amounts of methane. Both
carbon monoxide and hydrogen have HHVs of about 320 Btu/SCF and
carbon dioxide has no heating value at all, so varying the amounts
of the different components can produce any heating value desired
below that of methane.
It is obviously less costly to produce a low-Btu gas than a high-Btu
gas, and this may make it attractive for some industries to use a
manufactured low-Btu gas.
12
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TABLE 2 — ENGLISH-TO-METRIC UNIT CONVERSIONS
Multiply
This •
Ibs
short tons
short tons
inches
feet
statute miles
gallons
barrels
Btu
SCF
Btu/lb
Btu/CF
Btu/SCF
109 Btu/day
106 Btu/day
MM Btu/hr
SCFD
MM SCFD
SCF/MM Btu
Ibs/MM Btu
Ibs/CF
psi
gpm
acre-ft/year
horsepower
nautical miles
knot
By
This
0.4536
0.9072
907.2
2.54
0.3048
1.609
3.785
0.1590
0.252
0.02679
0.5556
8.899
9.406
252
252
252
0.02679
0.02679
0.1063
1.8
16.02
0.07031
0.227
0.1408
745.7
1.852
1.852
To Obtain
This
kg
metric tons
kg
cm
m
km
1
m3
kcal
ran
kcal/kg
kcal/m3
3
kcal/nm
Gcal/day
Meal/day
Mcal/hr
3
nm /day
10 nm /day
(Mnm3/day)
3
nm /Gcal
kg/Gcal
kg/m3
2
kg/cm
m3/hr
m3/hr
W
km
km/hr
kilograms
metric tons (1000 kg)
kilograms
centimetres
metres
kilometres
litres (1000 litres = 1 m )
cubic metres
kilocalories
normal cubic metres
kilocalories/kilogram
kilocalories/cubic metre
kilocalories/normal cubic metre
gigacalories/day
megacalories/day
megacalories/hour
normal cubic metres/day
million normal cubic metres/day
(mega normal cubic metres/day)
normal cubic metres/gigacalorie
kilograms/gigacalorie
kilograms/cubic metre
kilograms/square centimetre
cubic metres/hour
cubic metres/hour
watts
kilometres
kilometres/hour
(a) A SCF of gas is measured at 60°F and atmospheric pressure, and a
nm^ of gas is measured at 0°C and atmospheric pressure.
(b) Exponential
ir.3
English
SI Metric
10'
10
10
12
M or thousand
MM or million
billion (U.S.)
billion (U.K.)
k or kilo
M or mega
G or giga
T or tera
13
-------
SECTION III
HEAT BALANCES, COMBUSTION GASES
AND OVERALL WATER BALANCES
HEAT BALANCES
Most hydrocarbon processing plants require the extensive use of
fuel-fired process heaters and furnaces to supply reaction and distil-
lation heat. In general, they also require fuel-fired auxiliary steam
generators to provide steam for reaction, distillation and heating,
and for energy to drive compressors and pumps.
The intermediate process streams within a hydrocarbon processing plant
often need cooling before entering a subsequent process step. Usually,
intermediate and final products and byproducts must also be cooled
before storage or shipment.
These demands for both heating and cooling within the process plant
afford many opportunities for 'heat recovery1 by exchange of heat
between process streams. A well-designed plant will take every advan-
tage of such opportunities to recover heat. For example, the crude
oil entering a refinery atmospheric distillation tower (the 'crude unit1)
must be heated to about 700-750°F and, in a well-designed crude unit,
about 60% of that heat will be obtained by exchange with the hot
products distilled from the crude oil (this exchange also provides much
of the cooling required for those hot products).
Many hydrocarbon processing plants will also recover heat from high-
temperature process streams by heat exchanging those streams with water
to generate steam; such a heat exchanger is usually called a 'waste
heat boiler1 (WHB).
Steam for driver energy, distillation and heating can often be utilized
at various temperature and pressure levels. Again, this affords many
opportunities to 'reuse' the steam so as to extract the maximum
14
-------
available energy from it. For example, most large refineries,
petrochemical and gas treating plants will generate relatively high-
pressure steam (600-900 psig) for use in turbines to drive large
compressors and pumps. Whenever possible, these turbines will exhaust
their steam at back-pressures of about 50-150 psig (rather than under
vacuum, as is done in large power plants). The exhaust steam from
these 'back-pressure turbines' is then reused as distillation and
heating steam in the process units, wherein the latent heat of the
steam is extracted by condensation.
By talcing maximum advantage of the heat exchange opportunities, and
by using back-pressure turbines to supply driver energy plus distil-
lation steam, a well-designed oil refinery achieves a 90% overall
thermal efficiency*. Contrast this with a large fuel-fired electric
power generating plant, which exhausts steam from its turbo-generators
under vacuum to derive as much turbine-driving energy as possible.
The power plant has no place to utilize the vacuum exhaust steam and
must condense it either with cooling water or air. The result is
that the steam's latent heat (about 900 Btu Ib of steam) is lost
and this explains why a fuel-fired power plant has an overall thermal
efficiency of only 32-42%.
Why this discussion of process heat recovery and steam reuse?
Because it is important for those who undertake the environmental
analysis of a process plant to understand that:
— Both a detailed and an overall heat balance are needed.
These balances provide the basis for an independent judgement
of how well the plant design takes advantage of heat exchange
opportunities.
— A plant steam balance is also needed to provide an independent
judgement of heat conservation within the plant design.
* Defined as the percentage of the total input heating value (of
the feedstocks plus the plant fuel) that is recovered as product
and by-product heating value, or equivalent energy.
15
-------
— The plant's overall thermal efficiency is a key environ-
mental consideration when comparing the plant with its
alternatives.
— The degree of process heat recovery affects the overall
thermal efficiency and the overall demand for cooling water
and boiler feedwater. The demand for fresh water supply
is an important environmental consideration in itself and
relates almost directly to the amount of plant effluent
water to be handled and disposed.
HEATING VALUES
The analysis of a project's heat balance and its overall thermal
efficiency requires knowledge of the heating values of the typical
hydrocarbons involved in a project. Table 1 lists the HHVs (higher
heating values) for the typical fuels, feedstocks and products that
will be encountered. It is interesting to note that:
— As the hydrocarbons progress from light to heavy, both their
hydrogen content and their Btu/lb heating values decrease.
Obviously, heating value is a function of the carbon-to-
hydrogen ratio.
— Although hydrogen is considered a 'low-Btu* gas on a volume
basis (320 Btu/SCF), it is a very high-Btu fuel on the more
meaningful weight basis (61,100 Btu/lb). The same inverse
relationship between Btu/SCF and Btu/lb applies to the hydro-
carbons as well. Lighter fuels have lower gas densities
(i.e. less pounds per standard cubic foot) and hence their
heating values are relatively higher on a weight basis than
on a volume basis.
— The very low boiling temperature of the light C, to C4
hydrocarbons explains why refrigeration (or compression and
cooling) is required to liquify them in producing LNG and
LPG. The boiling temperatures of the pentanes and heavier
(100°F and above) also explains why these are usually liquids.
16
-------
The term 'higher heating value1 (HHV) is synonymous with 'gross
heating value1 and represents the total heat released when a fuel
is burned. The end products of fuel combustion include carbon
dioxide (C02> formed from the carbon in the fuel, and water (H20)
formed from the hydrogen. The water is vaporized by the heat
release, using up some of the fuel's gross heating value and leaving
a net heating value as the effective amount available for use. This
net heating value is referred to as the 'lower heating value' (LHV).
The difference between the higher and lower heating values of a
fuel represents the heat 'lost' when the fuel is burned (by vapor-
ization of the combustion product water) and which therefore cannot
be recovered for heating use.
Quantitatively, the HHV is 5-10% higher than the LHV of a given fuel.
It is not really necessary to discuss when or why it is more correct
to use HHV or LHV, but it is pertinent to realize that heat balances
or thermal efficiencies should be consistent in using one value or
the other. The inconsistent use of heating values will result in
significant errors.
COMBUSTION STACK GASES
When a fuel burns in air (which is essentially a mixture of oxygen
and nitrogen), the carbon and hydrogen in the fuel combine with
atmospheric oxygen to form carbon dioxide and water vapor. The
combustion stack; gases (or 'flue gas') are therefore composed mainly
of carbon dioxide, water vapor and the residual atmospheric nitrogen.
Since complete combustion requires some .excess air, the stack gases
also contain some oxygen and its additional co-mingled nitrogen.
The stack, gases will also contain some sulfur dioxide (S02) derived
from sulfur in the fuel, some nitrogen oxides (NO ) derived from
Jt
nitrogen in the fuel and from atmospheric nitrogen, and some particu-
lates derived from 'ash' in the fuel.
Determination of the amount of stack gas that results from the
burning of fuel is needed in order to estimate S00, NO and
£ X
17
-------
particulate emission concentrations. Table 3 provides a quick
and accurate estimate of the flue gas rates resulting from burning
the indicated fuels and it is based on the fuel carbon-hydrogen
ratios and heating values given in Table 1. In using Table 3, it
should be noted that:
— The terms 'excess air- and '02 in the flue gas1 are not
synonymous, as shown by their significant differences in
the table. The difference between them is very often over-
looked. (When an emission concentration regulation refers
to 3% excess 02, it probably means 02 in the flue gas rather
than the amount of excess air, but this should be carefully
confirmed in each case).
— The amount of excess combustion air used in process heaters
and steam generators will be in the range of 5-20%, while
gas turbine combustors will use from 200-300%. Emission
concentration values should always be corrected to the %
excess air or to the % 02 in the flue gas specified by the
applicable emission regulations. Some emission regulations
are expressed in Ibs/MM Btu (or 10 Btu) which completely
eliminates the problem of defining the flue gas basis.
Ideally, all emission regulations should use Ibs/MM Btu.
— Many emission concentration regulations fail to specify a
'wet' or 'dry' flue gas basis (i.e. one includes the combus-
tion product water vapor, and one does not). Table 3 illus-
trates the significant difference between the two values.
— Coals from various geographic areas will vary widely in
chemical composition and in heating value. Hence, the coal
data in Table 3 are applicable only for the specified ultimate
analysis and heating value.
OVERALL WATER BALANCES
An overall water balance is an accounting of the raw water supply to
a project and the ultimate use or disposition of that water. An
overall balance need not include the intermediate details of water
flows within the plant, but such a water-flow diagram can be very
18
-------
TABLE 3E — FLUE GAS RATES - "ENGLISH UNITS
5% excess
@ 15% excess
§1 5% excess
@ 15% excess
@ 5% excess
@ 15% excess
@ 5% excess
@ 15% excess
(§ 5% excess
i>15% excess
air
air
air
air
air
air
air
air
air
air
mined, and based on
51 wt%
4 wt%
9 wt%
1.2 wt%
23 wt%
1 wt%
100 wt%
23,900
23,900
21,700
21,700
20,700
20,700
18,700
18,700
8,800
8,800
this ultimate
10,890 0.9 9.1
11,830 2.5 8.4
10,715 0.9 11.1
11,660 2.6 10.2
10,600 0.9 12.2
11,540 2.6 11.2
10,795 0.9 13.8
11,770 2.6 12.6
11,590 0.9 15.8
12,615 2.6 14.5
analysis:
Dry Flue Gas (DFG)
Rate, vol .%
SCF/MM Btu Oo CO?
8,910 1.1 11.1
9,850 3.0 10.1
9,130 1.1 13.0
10,075 3.0 11.8
9,225 1.1 14.1
10,170 2.9 12.8
9,690 1.1 15.3
10,655 2.9 13.9
10,440 1.0 17.5
11,465 2.8 16.0
-------
TABLE 3M — FLUE GAS RATES -METRIC UNITS
Wet Flue Gas (WFG)
Dry Flue Gas (DFG)
Methane
Propane
Naphtha
Fuel Oil
Coal'1'
i> 5% excess
@ 15% excess
©> 5% excess
€> 15% excess
@ 5% excess
i> 15% excess
@ 5% excess
@ 15% excess
i> 5% excess
@ 15% excess
air
air
air
air
air
air
air
air
air
air
(1) As mined, and based on
C = 51 wt %
H =
0 -
H20 =
Ash =
S =
4 wt %
9 wt %
12 wt %
23 wt %
1 wt %
HHV
Real/kg
13,290
13,290
12,
12,
11,
11,
10,
10,
4,
4,
065
065
510
510
395
395
890
890
this ultimate
Rate,
run /Gcal*
1
1
1
1
1
1
1
1
1
1
,158
,258
,139
,239
,127
,227
,148
,251
,232
,341
vol %
o2 co0
0.9
2.5
0.9
2.6
0.9
2.6
0.9
2.6
0.9
2.6
£.
9.1
8.4
11.1
10.2
12.2
11.2
13.8
12.6
15.8
14.5
analysis t
Rate,
nm /Gee
947
1,047
971
1,071
981
1,081
1,030
1,133
1,110
1,219
Gcal
vol %
.,* 0 CO,
1.1
3.0
1.1
3.0
1.1
2.9
1.1
2.9
1.0
2.8
/,~
11.1
10.1
13.0
11.8
14.1
12.8
15.3
13.9
17.5
16.0
Q
=10 calories
100 wt %
-------
useful in lending credibility to the overall balance.
In most hydrocarbon processing plants, the overall water balance
discloses that very little of the supply water is "destroyed" or
disposed of irretrievably. In fact, most of the water is evaporated
and returned to the regional atmosphere to eventually return as
rainwater. Even water used to supply hydrogen (derived from steam)
for producing methane SNG will return to the atmosphere as combustion
product water vapor wherever that methane is burned.
For example, consider this water balance for a coal gasification
plant design:
gpm %
Process consumption (supplying hydrogen) 520 10.2
Return to atmosphere via:
Evaporation 3,310 64.9
Scrubbers and steam vents 240 4.7 ,
3,550 69.6
Disposal in mine reclamation 430 8.4
Other uses 600 11.8
5,100 100.0
In this case, about 80% of the total water supply will return to
the atmosphere from evaporation, venting and combustion of the
product SNG. Also, this project was designed to have no discharge
of wastewater.
As another example, this is the overall water balance for a project
producing SNG from naphtha (with the total cooling needs provided
by air-cooling):
gpm %
Process conversion (supplying hydrogen) 300 78.9
Vented with (X>2 17 4.5
Demineralizer and boiler blowdowns 50 13.2
Treated wastewater discharge 12 3.2
On by-product sulfur
1 0.2
380 100.0
21
-------
Here, about 83% of the water supply will return to the atmosphere
via venting and from the burning of the SNG.
As exemplified in the two cases above, an overall water balance
helps to put the project in proper perspective. As noted earlier,
very little of the water supplied to a hydrocarbon processing plant
is destroyed, since most of it eventually returns to the atmosphere
as water vapor. The key environmental consideration is not how
much water 'passes through1, but rather how much is discharged as
blowdown and wastewater, and what contaminants those discharges will
contain.
22
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SECTION IV
SNG FROM LPG AND/OR NAPHTHA
Substitute natural gas (SNG) can be produced from light hydrocarbons
such as LPG, condensate or naphtha. Currently, there are at least
three process technologies available for such plantst Lurgi's
Gasynthan process; the British Gas Council's CRG process; and the
Japanese MRG process. These processes can have an overall thermal
efficiency as high as 97-98% (see Table 4). The three processes are
quite similar, differing mainly in proprietary details and catalysts.
A fairly typical design, using the Lurgi process, will be described
in this section as illustrative of the technology.
The Lurgi process is quite simple. In brief, the end-product methane
SNG is produced by a series of chemical reactions which combine the
feedstock hydrocarbon with hydrogen to produce methane. Figure 1
typifies the reaction steps in a Lurgi design, when feeding naphtha:
— Catalytic desulfurization (or 'hydr©treating') to remove
sulfur from the naphtha by converting it to gaseous H_S.
— Gasification wherein naphtha, steam and hydrogen combine to
form methane, carbon monoxide and carbon dioxide.
— Methanation wherein carbon monoxide and hydrogen react to
form additional methane.
— Removal of C0~ and water from the product SNG.
— Sulfur recovery to convert gaseous H?S into a salable by-
product sulfur.
— Hydrogen production from a portion of the crude SNG.
— A boiler plant to generate steam, as well as other auxiliary
utility services.
The plant as shown schematically in Figure 1, and described herein,
feeds 20,700 barrels a day of feedstock and fuel naphtha to produce
100 MM SCFD of SNG with a heating value of 1000 Btu/SCF (HHV).
This description of a naphtha SNG plant is based on a
specific design and is not universally applicable. It
is intended merely to illustrate the process involved.
23
-------
TABLE 4E — THERMAL EFFICIENCY OF SNG PRODUCTION FROM NAPHTHA -
ENGLISH UNITS
OVERALL THERMAL EFFICIENCY
Naphtha Feedstock, Ibs/hr
, (barrels/day)
Naphtha Fuel, Ibs/hr
, (barrels/day)
TOTAL INPUT
SNG Product, SCFD
FLOW RATE 10 Btu/Day
205,000
(18,950)
19,100
(1,765)
100 x 10
93,480
8,710
U)
(1)
102,190
100,000
(2)
Thermal Efficiency = (100,000/102,190)(100)
= 97.8%
FUEL REQUIREMENTS
10U Btu/hr
HEAT RELEASE
Ibs/hour
NAPHTHA FUEL
Catalytic desulfurizer
Hydrogen production
Steam generation*^)
Supplied by process fuel
GROSS TOTAL
gas'4'
NET TOTAL
40
58
338
436
-73
363
22,947
-3,847
19,100
(1) Naphtha heating value is 19,000 Btu/lb (HHV)
(2) SNG heating value is 1000 Btu/SCF (HHV)
(3) Includes superheating of steam
(4) By-product fuel gas produced and used in-plant
24
-------
TABLE 4M — THERMAL EFFICIENCY OF SNG PRODUCTION FROM NAPHTHA
METRIC UNITS
OVERALL THERMAL EFFICIENCY
FLOW RATE
Goal/Day
Naphtha Feedstock, kg/hr
, (m3/day)
Naphtha Fuel, kg/hr
, (m3/day)
SNG Product, run /day
TOTAL INPUT
92,988
(3,013)
8,664
(281)
2.679 x
23,557
2,195
(1)
(1)
25,752
25,200
(2)
Thermal Efficiency = (25,200/25,752)(100)
= 97.8%
FUEL REQUIREMENTS
Catalytic desulfurizer
Hydrogen production
Steam generation^ 3)
Supplied by process fuel
•
Gcal/hr
HEAT RELEASE
10.1
14.6
85.2
GROSS TOTAL 109.9
gas(4) -18.4
NET TOTAL 91.5
kg/hr
NAPHTHA FUEL
10,409
-1,745
8,664
(1) Naphtha heating value is 10,556 kcal/kg (HHV)
(2) SNG heating value is 9,406 kcal/nm3 (HHV)
(3) Includes superheating of steam
(4) By-product fuel gas produced and used in-plant
25
-------
Sour Gas
Naphtha CATALYTIC
T
/ t !
/Heat j
L 1
Hydrogen
SULFUR
RECOVERY *"
Cr
S
s Steam
HYDROGEN
PRODUCTION **
Byproduct
o T.C i ^ CO Vent
Sulfur ^ 2
ude
NG METHANATION,
DRYING
Product
SNG
r
AUXILIARY
/
/Heat
Fuel
SERVICES
BOILER
PLANT
1
1
1
1
1
1
Steam
I
I
Naphtha is used as feedstock, and as
process heater and boiler fuel
Figure 1
Process Flow Diagram
SNG FROM NAPHTHA
-------
FUEL REQUIREMENTS AND STACK GASES
Table 4 presents the fuel requirements as well as the overall thermal
efficiency of the plant.
The total heat release required in the plant is 436 MM Btu/hr.
We- can estimate the unit stack gas rate, when burning naphtha, as
about 11,000 SCF of WFG/MM Btu (see Table 3E). Therefore, the total
stack gases issuing from the plant will be about 4,800,000 SCF/hr.
SULFUR BALANCE AND S02 EMISSIONS
20,700 barrels/day of feedstock plus fuel naphtha (with a sulfur content
of 0.1 wt %) will contain 5,378 Ibs/day of sulfur. Of this, 91.5% is
recovered as by-product sulfur plus a small amount of waste zinc
sulfide.
The remaining 8.5%, or 459 Ibs/day, of sulfur leaves the plant as S02
in the stack gases from burning of the fuel naphtha in the process
heaters and steam generator. Thus, the S02 emissions in the stack
gases will be 918. Ibs/day. This amounts to only 0.09 Ibs S02/MM Btu
of heat release, which easily meets the EPA limit of 0.8 Ibs/MM Btu
for firing liquid fuels.
The sulfur balance specifics are presented in Table 5.
WATER BALANCE
The water balance, shown in Table 6, is based on a design utilizing
air-coolers for supplying all of the plant's cooling needs. The total
supply water demand is 380 gpm for boiler feedwater. About 79% of
this is converted to hydrogen for producing methane since steam is
the source of hydrogen required for SNG production. Another 4.5% is
vented with the C09 removed from the product SNG. The remaining 16.5%
^
is discharged as effluent waters.
27
-------
TABLE 5E — SULFUR BALANCE FOR SNG PRODUCTION FROM NAPHTHA -
ENGISH UNITS
sulfur S02 emissions
Ibs/day Ibs/day
Feedstock Naphtha i> 0.1 wt % S 4920
Fuel Naphtha @ 0.1 wt % S 458
5378
By-product sulfur 4870
(2)
Desulfurizer heater stack: gas 51 102
(2)
Hydrogen plant heater stack gas 73 146
Steam generation 335 670
Waste zinc sulfide^ 49 -
5378 918
Overall sulfur emissions = (51 + 73 + 335)(lOO)/5378
= 8.5% of input sulfur
Overall fuel heat release (Table 4)
= 436 x 106 Btu/hr
Overall S02 emissions = (9l8/24)/436
=0.09 Ibs S09/MM Btu (HHV)
£*
EPA SO2 limit for firing liquid fuels
=0.80 Ibs S02/MM Btu (HHV)
(l) From use of zinc oxide to absorb final sulfur traces from
feedstock naphtha after catalytic desulfurization
(2) One pound of sulfur is equivalent to two pounds of S02
28
-------
TABLE 5M — SULFUR BALANCE FOR SNG PRODUCTION FROM NAPHTHA -
METRIC UNITS
Sulfur
kg/day
S02 emissions
kg/day
Feedstock Naphtha <§ 0.1 wt % S
Fuel Naphtha @ 0.1 wt % S
2232
208
2440
By-product sulfur
Desulfurizer heater stack gas
Hydrogen plant heater stack gas
Steam generation
Waste zinc sulfide
2209
23
33
152
22
2439
46
66
304
(2)
(2)
(2)
416
Overall sulfur emissions = (23 + 33 + 152)(100)/2439
= 8.5% of input sulfur
Overall fuel heat release (Table 4)
= 109.9 Gcal/hr
Overall S0_ emissions = (416/24)/109.9
£t
= 0.16 kg S02/Gcal (HHV)
EPA SO« limit for firing liquid fuels
= 1.44 kg S02/Gcal (HHV)
(1) From use of zinc oxide to absorb final traces of sulfur from
feedstock naphtha after catalytic desulfurization
(2) One kilogram of sulfur is equivalent to two kilograms of S02
29
-------
TABLE 6 — WATER BALANCE FOR SNG PRODUCTION FROM NAPHTHA
3
qpm m /hr %
INPUTS
Boiler feedwater supply^ 380 86.2
OUTPUTS
Conversion to methane 300 68.1
Vented with C02 17 3.9
Demineralizer blowdown 38 8.6
Boiler blowdown 12 2.7
(2)
Treated wastewater discharge 12 2.7
On by-product sulfur 1 0.2
380 86.2
Total eventually returned to atmosphere = 78.9 + 4.5
= 83.4%
(1) This plant was designed for total air-cooling, and hence
no cooling water system makeup is needed
(2) This small amount could be vaporized in boiler fire-box
and be rejected as water vapor in the boiler stack gases
30
-------
As noted in Table 6, some of the effluent discharge could be
vaporized in the boiler firebox if the situation required it.
SUMMARY OF MAJOR ENVIRONMENTAL FACTORS
Total naphtha (feed plus fuel)
SNG product (@ 1000 Btu/SCF)
Overall Thermal Efficiency
Sulfur by-product
Total combustion heat release
Total combustion stack gases
Total SO2 in stack gases
SO? per MM Btu's of heat release
Total raw water intake
Total effluent water discharge
CO,, vent gases: C0?
H20
20,700 barrels/day
224,100 Ibs/hr
100MM SCFD
97-98% (approx.)
4900 Ibs/day (approx.)
2.5 tons/day (approx.)
436 MM Btu/hr
4.8 MM SCF/hr
918 Ibs/day
0.09 Ibs/MM Btu
380 gpm
62 gpm
175,800 Ibs/hr (approx.)
8,500 Ibs/hr
The major emissions and effluent discharges listed above are:
(a) Combustion stack gases
(b) CO2 vent gases
(c) Effluent water discharges (blowdowns and wastewater)
OVERALL PROCESS MATERIAL BALANCE
The overall process inputs are:
Naphtha feedstock
Water (converted to SNG hydrogen
and CO2 oxygen)
The overall process outputs are:
Product SNG
Vent C02
By-product sulfur
Process fuel gas
lbs/hr_
205,000
150,000 (300 gpm)
355,000
176,000 (100 x 106 SCFD)
175,800
200
3,000
355,000
-------
This balance excludes the fuel naphtha which merely exits as stack
gas, and the water supply which exits as effluent discharges or with
the vent C0«. There would be no purpose served in showing these
non-process inputs and their disposition.
OTHER FACTORS
The combustion stack gases will contain nitrogen oxides (NO ) as
X
well as S00, but, with a naphtha or lighter fuel, the NO emissions
^ A.
should easily meet the Federal limit of 0.3 Ibs/MM Btu for firing
liquid fuels. There should be essentially no emission of particulates
from a naphtha or lighter fuel.
Some nominal amount of electric power will most probably be purchased
for lighting, instruments, and small motor drivers for air-cooler
fans and pumps.
Feedstock and fuel storage tanks will be required to permit continuous
operation in the event of a temporary transportation interruption.
There will be no unusual noise problems, and a realistic limit of
50-60 dBA at the plant property line should be attainable during
normal operation.
Periodically, minor amounts of solid wastes will require disposal
(zinc oxide spent to zinc sulfide, and spent catalysts). The zinc
sulfide disposal may occur once a month or so, and the spent catalyst
may occur once each 12-24 months.
;•
A relatively large emergency flare stack (24-inch diameter by 200 ft.
high) will be needed. When flaring at the maximum emergency rate,
the flame may extend 250 ft. above the flare stack and may create
noise levels of about 80-90 dBA at a distance of 1000 ft.
32
-------
OTHER PLANT CONFIGURATIONS
While the above description serves to present a general picture of
an SNG plant, other designs may vary quite widely from the one given
here. For example:
--An LPG feedstock would very probably not require desulfurizing,
This would decrease the plant heat and stack gas releases,
and drastically change the sulfur balance. A sulfur recovery
unit would probably not be included.
-- A naphtha with a different sulfur content would also change
the sulfur balance and SO- emissions.
-- The use of water-cooling rather than air-cooling would change
the plant water balance significantly.
-- The use of the CRG or MRG process rather than Lurgi's process
might also alter some of the environmental factors.
ADDITIONAL READING
Anderson, D. I. First Large-Scale SNG Plant Yields Tips on Best
Operation. Oil and Gas Journal 72:3 74-76, January 1974.
Anon., NG/LNG/SNG Handbook. Hydrocarbon Processing 52:4 87-132,
April 1973.
Conway, H. L., B. H. Thompson. Hydrogenation of Hydrocarbons for
SNG. Chemical Engineering Progress 69:6 110-112, June 1973.
Jockel, H., B. E. Triebskorn. Gasynthan Process for SNG. Hydrocarbon
Processing 51:1 93-99, January 1973.
Wett, T. SNG Plans Shift to Coal. Oil and Gas Journal 7.2:34 93-102,
August 1974.
33
-------
SECTION V
SNG FROM COAL
Coal is the United States' most abundant energy source, with enough
proven reserves to meet our energy needs for hundreds of years.
Faced with crude oil shortages and dwindling supplies of natural gas,
we must utilize our vast coal energy reserves.
The energy in coal can be utilized in three ways:
— Direct burning for residential and industrial heating
The transporting and distributing of coal to the end-use
residential and industrial market would be very costly, as
would the modification or replacement of home heating furnaces
to handle coal. The environmental impact in terms of air
pollution would be extremely high. Although widely practiced
decades ago, the direct burning of coal to supply heat can
no longer be considered an acceptable alternative.
— The burning of coal to generate electrical power
This is a viable alternative, assuming power generation plants
are provided with electrostatic precipitators and stack gas
scrubbers to remove particulates (fly ash) and SO,,. However,
the thermal efficiency of generating electricity from any
fossil fuel is quite low, ranging from 35-42% for the best
of designs. And even with 85% removal of SO- (via stack gas
scrubbing), a large power plant will release to the air over
100 tons/day of SO-. Nonetheless, our need for electrical
power will mandate the use of coal to generate power until
nuclear power or other alternatives are developed and accepted.
— The conversion of coal into clean-burning SNG for residential
and industrial heating
Coal gasification is about 70% thermally efficient, or twice
as efficient as the direct burning of coal to produce electri-
city. Gasification permits the recovery and removal of most
of the coal sulfur content at 99+% efficiencies. A coal
34
-------
gasification plant is therefore much more environmentally
desirable than a coal-fired power plant (even when trans-
mission and end use efficiencies are also considered).
The commercial gasification of coal has been practiced for at least
50 years. The low-pressure Winkler coal gasifiers and others date
back to the 1920s. Most of the early gasification processes were
concerned with producing low-Btu 'towns gas' for residential use, or
synthesis gas for producing hydrogen, methanol and ammonia. More
recently the Lurgi high-pressure gasification process (developed in
Germany) has been used extensively on a large-scale commercial basis
in 14 plants around the world. Altogether, Lurgi gasifiers have
successfully handled 59 grades of coal — including coke, anthracite,
semi-anthracite and sub-bituminous coals.
There are many coal gasification research programs currently underway
in the U.S. to develop more advanced gasifiers. All of these are still
in laboratory or pilot plant development, and none will be available
for commercial application within the next 2-5 years.
Many major gas utility companies in the U.S. have decided that the
Lurgi gasification process is technically feasible and fully proven
for commercial production of pipeline quality, high-Btu SNG. There are
at least 9 major gasification projects underway in the United States,
and only one of these is seriously considering a process other than
Lurgi's process. Most of these will involve the strip-mining of
relatively low-sulfur Western coals.
THE LURGI COAL GASIFICATION PROCESS
Figure 2 is a schematic flow diagram for a coal gasification plant
utilizing Lurgi technology to produce high-Btu SNG from strip-mined
coal in New Mexico.
This description, of a coal gasification plant is based on a
specific coal supply, a specific site, and a specific design,
and is not universally applicable. It is intended merely to
illustrate the processes involved.
35
-------
Steam
•
Coal
»i G\SIFIEPS
A",h m ft
Si Nit
& i V
rS A
O 1
1
Air OXYGEN
^ PLANT
l~ AUXILIARY
SERVICES
Coal BOILER
^ PLANT
Reclaimed COOLING
Water * TOWER
| ^
GLAUS Tail Gag
•fr, "^TTT^FTIP ._-««. .««_•<
RECOVERY to treater
to
rrt ___________
u | Byproduct
TX Ol i T -Fl i V"
A.) OU.JLtU.JT
-H
rj
«, • »- C02 VcnL
RECTISOL
O "LIT TTT1 P'Z.Q AOTT^r^A^s O AT/"*
ij rl_L J7 i ^J_rVO -TiV.* J- JL/ VJf-Tlk— ' _^ 1\!\_3
*^^ *^r^T*T7T^nTMr*i _^ i-*--.— .— > -. -^^ _„_„__„ _^_ •-'j.i-^
*" s^KUt!£i-1-^u »• CONVERSION * COOLING "*" REMOVAL, *" to
SNG DRYING compression
1 1 •
i ^, T'TI T*C* f r\n T cr 1 -^ O i T c*
••-— ^_P* Iclio o? OJ__Lo ' jP1 VJl-Lo
rogen , , fc Nanhtha
ent Phenolic Waters
*" & Water
PHENOSOLVAN
EXTRACTION Byproduct METHANATION
. ., ___________ Plnpnol R
Reclaimed Water _ , ' TT ,
(to cooling towers) Byproduct Water
~j (to boilers)
1
1 Steam
1 A
1 t
l
1
i Figure 2
j *• 1 Cooling WdLei Process Flow Diagram
i . System
SNG FROM COAL
J
-------
The plant will produce 250 MM SCFD of SNG, as well as by-product
fuels, from 25,600 tons/day of coal (about 9.4 MM tons of coal per
year):
Tons/day 10 SCFD 10 Btu/day
Gasification coal 21,860
Boiler plant coal 3,760 - -
25,620 442
Product SNG - 250 250
By-product fuels - - 60
310
Coal gasification involves a series of chemical reactions in which
carbon from the coal is combined with hydrogen from steam to form
methane, which constitutes 97 vol % of the product SNG. The heat
required by the process is supplied by partial oxidation of the
gasification coal with pure oxygen. Much of the heat is subsequently
recovered by in-process generation of steam which is then reused as
reaction steam and to supply equipment-driving energy (augmented by
additional steam generated in auxiliary coal-fired boilers).
Very briefly, the reaction and conversion steps in Figure 2 include:
Pressure Gasification — coal, steam and oxygen are reacted under
controlled conditions of temperature and pressure to produce a
crude gas containing methane, hydrogen, carbon monoxide, carbon
dioxide, excess steam and various by-products and impurities.
Only some 40% of the plant's end-product methane (SNG) is
produced in the gasifiers. The remainder of the methane is
produced in subsequent reaction steps.
Gas Scrubbing — the crude gas is scrubbed and cooled with water,
which removes tar and oil by-products and phenolic waters. The
phenolic waters are subsequently processed for recovery of
by-product phenols.
Shift Conversion — excess carbon monoxide in the crude gas is
•shifted' (converted) to carbon monoxide to provide the 3-to-l
ratio of hydrogen-to-carbon monoxide needed for the subsequent
synthesis of additional methane.
37
-------
Gas Cooling — the shifted gas is cooled again to remove additional
hydrocarbon oil by-products and residual phenolic water.
Rectisol — low temperature methanol is used to selectively absorb
and remove H~S and C0~ from the cooled gas. Pre-cooling at the
Rectisol unit entry also recovers by-product naphtha.
Methanation — carbon monoxide and hydrogen are catalytically com-
bined to produce methane and by-product water. About 60% of
the end-product methane is produced in the methanation step.
Compression — the dry, purified SNG is compressed and delivered
to the pipeline with a heating value of 980-1000 Btu/SCF.
Phenosolvan — a selective solvent (isopropyl ether) extracts by-
product phenols from phenolic waters. The reclaimed water is
stripped of H_S and NH-,, and is further processed for complete
reuse within the plant.
Glaus Unit — H_S is catalytically converted to by-product sulfur
and any residual gaseous sulfur compounds are incinerated to
SO9 and removed in a subsequent 'tail gas* treating unit.
^
Oxygen Plant — pure oxygen is cryogenically extracted from atmos-
pheric air.
Auxiliary Services — these include coal-fired steam boilers with
electrostatic precipitators to remove fly ash and stack gas
scrubbers to remove SO..,. A closed loop, evaporative cooling
water system as well as extensive air cooling is provided.
Extensive wastewater treating and reuse is also provided.
OVERALL THERMAL EFFICIENCY
g
As tabulated earlier herein, the plant produces 310 x 10 Btu/day
9
of SNG and by-product fuels from 442 x 10 Btu/day of gasification
and boiler coal. This amounts to a 70% overall thermal efficiency.
We could rationalize an even higher efficiency since some of the by-
products (such as naphtha and phenols) will be sold for more than
their mere heating value. We could thus argue that their contribu-
tion to overall energy recovery (thermal efficiency) should be
higher since the income generated by their sales could be used to
purchase more Btu's than they contain as heating value.
38
-------
The only auxiliary fuel input required by the plant is that required
to generate the auxiliary steam. Since the Lurgi pressure gasifiers
must be fed coal of a certain size (ranging from about 3/16" minimum
to lV maximum), the 'as-mined' coal must be crushed and screened to
size. This produces a reject of smaller sized coal, referred to as
'coal fines'. The amount of fines produced fortuitously coincides
(in this specific design) with the amount required for steam generation,
so the design was based on burning coal fines to produce steam.
OVERALL PROCESS MATERIAL BALANCE
The overall material balance (not including the auxiliary steam boilers)
for the gasification process producing 250 MM SCFD of SNG can be summar-
ized as follows:
Tons/day wt %
INPUTS:
Gasification coal 21,860 41.48
Steam and water 25,160 47.74
Oxygen 5,680 10.78
TOTAL 52,700 100.00
OUTPUTS:
Product SNG 5,440 10.32
By-product phenols 105 0.20
By-product sulfur 175 0.33
Glaus unit tail gas^ 617 1.17
Ammonia plus water 800 1.52
By-product and reclaimed water 21,581 40.95
By-product hydrocarbon fuels 1,475 2.80
C0~ vent gas 16,631 31.56
Gasification ash 5,876 11.15
TOTAL 52,700 100.00
(1) Does not include air used to incinerate the tail gas, and the
material balance excludes the subsequent tail gas treating
inputs and outputs.
»
The amount, of coal in the above material balance for producing
250 MM SCFD of SNG is very specific to the particular coal being used.
39
-------
For other coals, the amount may range from 18,000 to 36,000 tons
per day. The steam and oxygen requirements may also vary over a
wide range.
SULFUR BALANCE AND S09 EMISSIONS
<£
The coal fed to the gasifiers has about 0.91 wt % sulfur and, there-
fore, the total sulfur contained in 21,860 tons/day of gasification
coal is about 200 tons/day. Of that, about 16 tons/day will be
retained in the naphtha and oil by-products and in the gasifier ash.
The remaining 184 tons/day, in the form of gaseous H2S, is processed
in the Glaus unit where about 175 tons/day is recovered as by-product
sulfur. The last 9 tons/day of sulfur is incinerated to S02> of which
85% is removed as calcium sulfate solids in the tail gas treater.
Finally, this leaves about 1.4 tons/day of sulfur released to the
atmosphere in the form of S02, which is only 0.7% of the original
200 tons/day of sulfur in the gasification coal.
Tons/day
as Sulfur Actual Form
INPUT:
Sulfur in gasification coal 200 sulfur compounds
OUTPUTS:
Sulfur in ash 10.0 sulfur compounds
Sulfur in tars, oils, naphtha 5.8 organic sulfur
Sulfur in CO- vent 0.5 carbonyl sulfide
By-product sulfur 174.5 sulfur
Calcium sulfate solids 7.'8 CaSO. (gypsum)
S0~ emissions to air from
Zt , i -' , ,
tail gas treater
The coal fines, which are burned to generate steam, contain about
0.87 wt % sulfur after being washed to remove pyritic sulfur. The
total sulfur contained in the 3,760 tons/day of coal required by the
boilers is about 33 tons/day. Of that, about 5% remains in the boiler
ash. The other 31+ tons/day becomes S02 in the boiler stack gases,
40
-------
where the stack gas scrubbers remove about 85% as calcium sulfate
solids. Finally, this leaves about 4.7 tons/day of sulfur released
to the atmosphere from the boiler plant in the form of SO„.
The steam generated in the coal-fired boilers will be superheated
in a separately fired unit using by-product oil containing about
0.9 tons/day of sulfur, all of which will be released as SO- to the
atmosphere in the superheater stack gases.
BOILER PLANT INPUTS!
Sulfur in coal fines
Sulfur in by-product oil fuel
OUTPUTS:
Sulfur in ash
Calcium sulfate solids
SOO emissions to air:
£+
From boiler stack gas
scrubbers
From superheater
Tons/day
as Sulfur
32.7
0.9
33.6
1.6
26.4
4.7
0.9
Actual Form
sulfur compounds
organic sulfur
sulfur compounds
CaSO, (gypsum)
so2
SO-
In summary, the total emissions to the atmosphere from the gasifica-
tion plant and the boiler plant will be 14 tons/day of SO,, (the
equivalent of 1.4 + 4.7 + 0.9 = 7.0 tons/day of sulfur) plus 0.5 tons/
day of gaseous carbonyl sulfide contained in the C02 vent gas. Thus,
only about 3% of the total 233.6 tons/day of sulfur entering the
overall plant (gasification process plus boilers) is released to the
atmosphere.
COMPARISON TO AN EQUIVALENT COAL-FIRED ELECTRIC POWER PLANT
As noted earlier in this section, the thermal efficiency of gasifying
coal is twice as high as burning coal to generate electrical power
(i.e. 70% versus about 35%). A power plant producing the same
q
310 x 10 Btu/day energy output as the gasification plant under
41
-------
discussion here would be generating 3780 MW and would have to use
twice as much coal as the gasification plant, or about 51,000 tons/day.
Assuming the power plant burns the same 0.91 wt % sulfur coal, its
stack gases would contain about 920 tons/day of S02. Further assuming
that the power plant included stack gas scrubbers to remove 85% of
the S02, it would still release about 138 tons/day of S02 to the
atmosphere, which is about 10 times greater than the 14 tons/day
released by the equivalent coal gasification plant. The power plant
is at a serious disadvantage in such a comparison because:
— The power plant uses twice as much coal-
— The gasification plant removes the large bulk of process
sulfur at 99+% efficiency and its boiler stack gas sulfur
at 85% efficiency
— The power plant sulfur all issues from its boiler stacks and
must all be recovered at the lower efficiency of 85%.
Direct burning is the most efficient way to produce electricity from
coal. The above comparison is meant to illustrate the relative
efficiency of producing energy via electricity generation versus via
coal gasification — for those residential and commercial uses where
electricity and gas are in competition such as space heating, cooking,
laundries, etc. In other words, coal can supply residential and
commercial heating more efficiently via gasification than via electri-
city. As a corollary, the. above comparison is not valid if the coal
SNG is subsequently sold for use in generating electricity at 35%
efficiency.
WATER BALANCE
Coal gasification requires large amounts of water as a source of
hydrogen for producing methane SNG, for process cooling, and for
generating steam energy. The gasification design under discussion
will require about 5,100 gpm of raw water intake (8,200 acre-ft/year)
to produce 250 MM SCFD of SNG. This amounts to 1.2 pounds of
42
-------
water intake per pound of coal, including the boiler plant coal
and including water used by the strip-mining operation (to be
described later).
Figure 3 presents a schematic water flow diagram for the gasifica-
tion plant, and Table 7 shows the overall disposition of the total
raw water supplied to the plant.
Here again, as shown in Table 7, very little of the raw water intake
is destroyed. In fact, about 80% of the water will be returned to
the atmosphere, when we include the combustion water that will be
returned wherever the product SNG is burned.
But the data in Figure 3 and Table 7 alone do not tell the full story
of how much this design conserves water usage and maximizes the reuse
of water. Some of the major features used to achieve those objectives
are:
— Steam turbines (driving process compressors) of about 250,000
horsepower will have air-cooled condensers as shown in Figure 3.
If cooling water had been used instead, the additional evaporative
loss alone would have totaled 4,000 gpm, almost doubling the plant
water needs. As a point of interest, the air-cooled condensers
provide about 2 billion Btu/hr of heat removal.
— Much of the reaction steam supplied to the Lurgi gasifiers re-appears
as phenolic wastewater (about 2500 gpm). By-product phenols are
extracted from this water, dissolved gases are distilled out, and
residual phenolics are biologically destroyed. The reclaimed
water then supplies 100% of the cooling tower makeup needs. Finally,
the cooling tower blowdown is again reused to quench the hot ashes
from the Lurgi gasifiers.
* This water requirement is very dependent on the particular
coal involved and upon the specific plant design. It might
range as high as 2 to 2.5 pounds per pound of coal.
43
-------
River Water
5100 gpm*
(1158 m3/hr)
Evaporation
from ponds
RAW WATER
TREATING
Sludge
I
STEAM
GENERATION
Rinses
Utility water,
Domestic water,
SOscrubbers
Blow-
down
PROCESS
STEAM
2700 gpm
Process
**
(613
Condensate
•*• Slowdown
-*- Boiler
Tube-blowing
PROCESS
STEAM
TURBINES
Exhaust
Steam
Return condensate
Air-cooled
condensers
SELECTIVE
I REUSE
I (see below)
*
I
Boiler blowdowns
Water treat rinses
Reclaimed water
L.
i
Treated
sanitary
effluent
Process
condensate
Sulfur pelletizing,
Haul road wetting,
Other uses in mining
BIOLOGICAL
TREATING
AIR
FLOTATION
o
o
in
I " T^
Sludge Sludge
I ^ Evaporation
API
SEPARATORS
Sewers and
storm water
T
Sludge
COOLING
TOWER
Evaporation
* 8200 acre-ft per year
** Phenol and ammonia by-products,
as well as residual H2S are removed
in the Phenosolvan unit (which includes
Blow-
down
ASH
QUENCH
H2S
and NH3 strippers)
Wetted
ashes
Figure 3
COAL GASIFICATION PLANT
WATER REUSE SYSTEMS
-------
TABLE 7 - WATER REQUIREMENTS AND DISPOSITION
gpm m /hr. %
Process Consumption
To supply hydrogen 1,120 254.2
Produced as methanation by-product -600 -136.2
Net consumption 520 118.0 10.2
Return to Atmosphere
Evaporation:
From raw water ponds 420 95.3
From cooling tower 1,760 399.5
From quenching hot ash 150 34.1
From pelletizing sulfur 250 56.8
From wetting of mine roads 730 165.7
3,310 751.4
Via stack gases :
From steam blowing of boiler
tubes 200 45.4
From stack gas S07 scrubbers 40 9.1
^ 240 54.5
Total return to atmosphere 3,550 805.9 69.6
Disposal to Mine Reclamation
In water treating sludges 100 22.7
In wetted boiler ash 30 6.8
In wetted gasifier ash 300 68.1
Total disposal to mine 430 97.6 8.4
Others
Retained in slurry pond 20 4.5
Miscellaneous mine uses 580 131.7
Total others 600 136.2 11.8
GRAND TOTAL 5,100 1,157.7 100.0
(1) Does not include water derived from burning
of boiler fuel
45
-------
-- By-product water from the methanation synthesis is recovered
for use as boiler feedwater.
— Mechanical refrigeration is used in the Rectisol plant, rather
than less costly absorption refrigeration, so that air-cooling
could replace water cooling, thus avoiding evaporative water
losses.
— Finally, selected effluent waters will be used for pelletizing
the by-product sulfur, and for dust abatement on the mining area
roads.
There will be no discharge of effluent wastewater. Water not evapo-
rated or converted to SNG is ultimately buried as wet ash and sludge
in the strip-mine pits as they are filled and graded for land reclama-
tion.
THE MINING OPERATION
The strip-mining of about 9.4 million tons of coal per year is a
major operation. In fact, such a surface mine will be among the
world's largest. It is beyond the scope of this report to go into
any detail on the strip-mining, other than to emphasize its very
large magnitude.
The task of filling the open pits, grading the land for reclamation,
and providing the ultimate revegetation will be gigantic, and will be
a significant factor in the environmental analysis of any coal gasifi-
cation project.
STACK GASES
Table 8 is an itemized listing of the plant stacks, and the quantity
and composition of their stack gas effluents.
OTHER ENVIRONMENTAL FACTORS
The key environmental factors, all discussed above, can be summarized
46
-------
TABLE 8E — STACK GASES FROM COAL GASIFICATION-ENGLISH UNITS
Total
Stack Gases
MM SCFD tons/day
Glaus tail gas
Boiler stacks
Superheater stack
Nitrogen vent
CO 2 vent
CO 2 vent
Coal lock vent
Ash lock vent
Coal conveyor vent
Emergency flare
35
845
138
502
211
78
77
245
39
(design
1
32
5
18
12
4
2
9
1
,
,
,
,
,
>
>
t
9
486
800
370
500
200
400
900
400
470
°F
250
250
600
100
65
50
65
175
65
ft/sec
80-100
80-100
80-100
80-100
80-100
80-100
80-100
60-80
60-80
Tons/day of
S09
2.8
9.4
1.7
(almost
NO
m
15.
1.
•—
9
5
pure
(0.5 tons/day
Emissions
Partic.
-
1.8
0.026
nitrogen)
of COS)
(99% CO 2 and 1% CH4)
(99+% air, lOppmv H2S)
-
-
-
-
0.5
0.1
data unavailable) - -
Heat Release
MM Btu/day
Glaus tail gas
Boiler stacks
Superheater stacks
363,000
7
0,800
10,200
(1)
(2)
(3)
Ibs/MM
SO.
Z.
0.015
0.27
0.33
Btu
NO
-
0.
0.
Height,
feet
150-300
150-300
150-300
150-300
150-300
150-300
150-300
100-200
100-200
250-350
Heat Release
x—
45
29
Partic.
-
0.05
0.005
(1) Based on heating value of coal fed to Lurgi gasifiers
(2) Based on heating value of coal fines burned in boilers
(3) Based on heating value of by-product oils burned in superheater
-------
TABLE 8M — STACK GASES FROM COAL GASIFICATION - METRIC UNITS
oo
Total
Mnm /day
Glaus tail gas
Boiler stacks
Superheater stack
Nitrogen vent
CO 2 vent
CO 2 vent
Coal lock vent
Ash lock vent
Coal conveyor vent
Emergency flare
0
22
3
13
5
2
2
6
1
.9
.6
.7
.5
.7
.1
.1
.6
.0
(design
Stack Gases
Mg/day*
1,348
29
4
16
11
3
2
8
1
,756
,872
,783
,068
,992
,631
,528
,334
°C
121
121
316
38
18
10
18
79
18
m/sec
24-30
24-30
24-30
24-30
24-30
24-30
24-30
18-24
18-24
Mq/day
SO-,
"" " <£*
2.5
8.5
1.5
(almost
of Emissions
NO.,
14.4
1.4
pure
(0.45 Mg/day
Partic.
-
1.
0.
6
024
nitrogen)
of COS)
(99% C02 and 1% CH4)
(99+% air, lOppmv H2
0.
-
-
0.
s)
45
09
data unavailable) - -
Heat Release
Gcal/day
Glaus tail gas
Boiler stacks
Superheater stacks
91,476
17,842
2,570
(1)
(2)
(3)
kg/Gcal
SO,,
z.
0.027
0.49
0.59
Height,
metres
46-91
46-91
46-91
46-91
46-91
46-91
46-91
30-61
30-61
76-107
Btu Heat Release
NO..
Partic.
•*».
0.81 0.
0.52 0.
09
009
(1) Based on heating value of coal fed to Lurgi gasifiers
(2) Based on heating value of coal fines burned in boilers
(3) Based on heating value of by-product oils burned in superheater
Mg/day is equivalent to metric tons/day
-------
very briefly as follows:
-- Thermal efficiency and comparison to the alternative use of
coal for power generation
— SO- emissions to the air
— Water consumption and disposition
— The mining operation and subsequent land reclamation
Other environmental factors are relatively minor by comparison,
but are briefly discussed in this sub-section.
*
The plant will require about 30 MW of electric power for lighting,
instruments, air-cooler fans, pumps and other uses.
All wetted ashes, water treatment sludges, and blowdowns are ultima-
tely disposed of in the mining operation for land reclamation. The
specific process proposed in this design for sulfur plant tail gas
treating and boiler stack gas scrubbing is the Chiyoda Thorobred
Process developed in Japan. It converts SO,, to dry calcium sulfate
(CaSO.) as noted earlier. The CaS04 is of high enough quality to
perhaps find a market in competition with natural CaSO. (gypsum).
Other SO- removal processes may or may not produce a marketable end-
product. In any event, if the selected process produces a 'throw-away'
end-product sludge, it could be disposed of in the mining land recla-
mation along with the wetted ashes and water treatment sludges.
With 250,000 horsepower of steam turbines and a multitude of air-
cooler fans, in-plant noise will be a distinct problem but not an
insurmountable one. A limit of 60-70 dBA at the plant property line
should be realistically attainable.
A good many storage tanks for chemicals, catalysts and liquid by-
products will be required. Coal and sulfur by-product storage piles
will also be needed.
There should be no problem with the periodic disposal of spent
catalysts via burial in the strip-mine pits.
49
-------
As can be noted from Table 8, electrostatic precipitators on the
boiler stacks and other dust control measures will provide particula-
tes emission levels (ibs/MM Btu of heat release) that will satisfy any
anticipated regulations.
A very large emergency flare system will be required. When flaring
at maximum emergency conditions, the flame will be quite high and
very noisy. This condition, however, should occur only rarely.
Coal gasification plants will be located at the 'mine mouth', i.e.
adjacent to the coal fields, and should therefore be in fairly remote
sites. Such sites will probably require the concurrent construction ofj
— Access roads and perhaps railroads
— Water supply pipelines
— Gas product pipelines
The plant and mine will require a total operating staff of perhaps
900-1000 people who, with their families, will have a permanent impact
on local housing. The peak construction staff will number about
3500 personnel but their impact on local housing should extend over a
2-3 year period only. These operating and construction personnel will
of course create a number of socio-economic impacts other than housing,
which must be evaluated.
OTHER PLANT CONFIGURATIONS
Other design configurations may vary significantly from that described
above. In particular, the choice of whether to burn coal fines to
produce steam (as described herein), or whether to gasify the fines
to produce low-Btu gas for steam generation or for compressor drive
energy is one which is very difficult to assess. Whether to utilize
very extensive air-cooling as in the specific design discussed herein,
or whether to use less costly water-cooling, is another difficult
choice to face. Finally, coals of other sulfur and ash contents as well
as other heating values would result in different emission spectrums.
50
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Although most of the coal gasification projects now underway in the
U.S. are planning to use Lurgi process technology, this may not always
be the case. Two other processes, dating back to the older low-Btu
•towns gas1 era, have about the same amount of commercial experience
as the Lurgi process. These are the Koppers-Totzek gasifiers with
about 16 commercial installations, and the Winkler gasifiers also with
about 16 commercial installations. Both of these processes were
developed to operate at essentially atmospheric pressure, as contrasted
with the Lurgi gasifier's operating pressure of 350-450 psi. The
licensors of these two processes have not developed the up-to-date
methanation technology required to produce pipeline quality, high-Btu
SNG. Lurgi has developed the required methanation technology and is
willing to guarantee their high-Btu SNG designs. Lurgi was also
quicker to exploit the U.S. market and has gained a considerable advan-
tage by being selected for most of the 'first-generation' SNG projects.
This advantage may prove to be transient and, with certain types of
coal, either Koppers-Totzek or Winkler may yet become a factor in the
production of high-Btu SNG from coal.
In addition to the Lurgi, Koppers-Totzek and Winkler processes, there
are a whole host of 'second-generation' process research programs
underway in the U.S. to develop more advanced gasifiers. This is a
partial listing of those programs:
Atgas (Applied Technology Corp.) — demonstrated in small scale,
short duration, batch tests
Bi-Gas (Bituminous Coal Research) — 120 ton/day pilot plant under
construction at Homer City, Pa.
C02 Acceptor (Consolidation Coal Co.) — 40 ton/day pilot plant
experiencing initial startup problems at Rapid City, S.D.
Hydrane (U.S. Bureau of Mines) — 200 Ibs/day bench scale unit in
operation
Hygas (Institute of Gas Technology) — 75 ton/day pilot plant is in
operation at Chicago, 111. Demonstration plant for 80 MM SCFD
of SNG is in design
51
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Molten Salt (M.W. Krel'ljSgg Co.) -- basic reactions established in
laboratory
Synthane (U.S. Bureau of Mines) --70 ton/day pilot plant under
construction at Bruceton, Pa.
Union Carbide Coal Gasification --25 ton/day pilot plant under
construction at West Jefferson, Ohio
Westinghouse Coal Gasification --15 ton/day pilot plant under cons-
truction at Walez Mill, Pa.
Wellman-Galusha Gasification -- some commercial operation in the U.S.
on a small scale to produce low-Btu gas.
These development programs probably will not result in a commercially
viable process within the next few years. An optimistic estimate
of the time .required to complete these programs might be 2-5 years,
and a pessimistic estimate might be 5-10 years.
ADDITIONAL READING
Banchik, I. N. Clean Energy From Coal. Energy Pipelines and
Systems !_: 2 31-35, February 1974.
Bodle, W. W., K. C. Vyas. Clean Fuels From Coal. Oil and Gas
Journal 7_2:34 73-88, August 1974.
Boyd, N. F. Coal Conversion Processes Loom Big as a Source of
Hydrocarbon Fuels. Mining Engineering 26:9 34-41," September 1974.
Battelle Columbus Laboratories. Detailed Environmental Analyses of
a Proposed Coal Gasification Plant. February 1973.
Beychok, M. R., and A. J. Paquette. Clean Energy Via Coal Gasifica-
tion. 18th Annual Water Conference, New Mexico State University,
Las Cruces, New Mexico, April 1973.
52
-------
Beychok, M. R. Coal Gasification and the Phenosolvan Process.
ACS 168th National Meeting, Atlantic City, September 1974.
Electric Power Research Institute. Evaluation of Coal Con-
version Processes to Provide Clean Fuel (Part II). Palo Alto,
California, February 1974.
Osborn, E. F. Clean Synthetic Fluid Fuels From Coal: Some
Prospects and Projections. Mining Engineering 26:9 31-33,
September 1974.
Rudolph, P. H. The Lurgi Process Route to SNG from Coal. 4th
Synthetic Pipeline Gas Symposium, Chicago, October 1972.
Wett, T. SNG Plans Shift to Coal. Oil and Gas Journal 7_2:34
93-102, August 1974.
53
-------
SECTION VI
SNG FROM CRUDE OIL
Basically, SNG is produced from crude oil by first producing naphtha
and LPG, and then converting those products into SNG (as described in
Section IV herein). However, it would be too difficult and too costly
to so convert all the crude oil. The more reasonable approach is to
process the crude oil in a refinery configuration that produces an
SNG feedstock; (naphtha and LPG) as well as a low-sulfur fuel oil.
Most designs for producing SNG from crude oil are based on that
approach. Plants producing SNG and low-sulfur fuel oil are called
'SNG refineries'.
As discussed in previous sections, all SNG plants require a source
of hydrogen to combine with the feedstock's carbon — whether from
LPG, naphtha or coal — and form methane SNG. Since the SNG refinery
must first produce as much naphtha and LPG as reasonably possible,
the refinery also requires a source of hydrogen because the crude oil
has too low a hydrogen-to-carbon ratro. Finally, hydrogen is needed
to convert the sulfur content of the crude oil into gaseous H~S
(acid gas) which can then be removed and converted into by-product
sulfur. Therefore, all SNG refinery configurations include a hydrogen
plant to:
— Convert heavy hydrocarbons in the crude oil into lighter
hydrocarbons (LPG and naphtha)
— Convert LPG and naphtha into SNG
— Convert sulfur into gaseous H_S
There are dozens of configurations which could be used in an SNG
refinery. The final selection depends on the specific case and its
economics, the desired ratio of product SNG to product fuel oil, the
market picture for alternative by-products (e.g. petroleum coke rather
than fuel oil), the desired sulfur content of the product fuel oil,
and the individual preferences of the plant owners and designers.
54
-------
The composition of the crude oil (i.e. hydrogen-to-carbon ratio)
also has a strong influence on the SNG refinery configuration.
About the only common criteria among the many possible configurations
is that they all require a hydrogen plant and they all maximize the
reasonable yield of naphtha and LNG for subsequent conversion into
SNG.
As discussed in the previous Naphtha SNG section, there are at least
three process technologies available for the final conversion of LPG
and naphtha into SNG: (1) Lurgi's Gasynthan process, (2) the British
Gas Council's CRG process, and (3) the Japanese MRG process.
A TYPICAL SNG REFINERY PROCESS DESIGN
Figure 4 is a schematic flow diagram of a typical SNG refinery design.
Very few, if any, SNG refineries have yet to be constructed, and
Figure 4 is therefore based on a preliminary study design. It has
been simplified as much as possible, but an SNG refinery is a complex
plant and it is difficult to simplify without becoming meaningless.
This description of an SNG refinery is based on the use
of a specific crude oil, at a specific site, and a specific
production ratio of SNG to fuel oil, and is not universally
applicable. It is intended merely to illustrate the processes
involved.
In this particular design, the feedstock is a blend of crude oil and
condensate. The products are pipeline quality SNG and low-sulfur fuel
oil (0.3 wt % sulfur).
The configuration used in this design (Figure 4) utilizes an 'all-
hydrogen' refinery*. That is, hydrogen is used tos (1) desulfurize
* A 'partial-hydrogen' refinery would still use naphtha hydrotreating,
but the hydrocracker might be replaced by a non-hydrogen' fluid-bed
catalytic cracker. Also, the residuum catalytic desulfurizer might
be replaced by coking of the residuum. Again, many alternative
options are available.
55
-------
Cn
Sour Gas
" i '
f
ACID GAS
REMOVAL
& GAS
RECOVERY
P
Acic
Dry
dr ^ CLAUS UNIT * Tail Gas
1 Gas _^ e mATT f AS
UTRFATFR ' »• eyproauct
H9. »• TREATER ^Sulfur
— . — . MiJJKUUiiN ' ~~ 6 ,*-+**.
C3 - C4 _ PLANT _
_ CATALYTIC Naphtha
ra ^*" DESULFURIZER
W -P 4 "
^ £ L__ H2 T
•as jgj
•H M CD
3
Condensate °
*" CONDENSATE
.*
1
DISTILLATION ,,.,,,
,. Middle i
r*h- ' " '^^h T T""S^T^T^tf"^ ^^T"^ A ^^T^TT* T^
Naphtha
' 1
t !
Steam |
- 1
Hydrogen (H2)
o
'rv-> •> PO Vnirl-
U 2
- ^ NAPHlfHA SNG
Crude Oil CRUDE UNIT Distillates ' ' Naphtha " PLANT
M CQ I TT
— ^j re)
O CD
W
Resid RESIDUUM
»u /"» A m A T 'wrnT /"»
" CATALoiTTIC
DESULFURIZER
LOW-E
*" Fuel
T * ..
Steam "~ n2
sulfur
Oil
[™ AUXILIARY ~! L_ H
RRRVTPRS , ,,T l!to, qi-rnm 2
1
Fuel 1 1
*• BOILER PLANT 1 t
I & — • — >•' ) Cooling Water
waLei l^_ COOLING TOWER — , ^*- J •*
1 1
Figure 4
Process Flow Diagram
SNG FROM CRUDE OIL
-------
per day
300,000
65,000
365,000
Tons/day
45,773
8,300
106 SCFD 109 Btu/day
1,740
337
2,077
or 'hydro-treat1 the naphtha and the residuum fuel oil by converting
sulfur to H2S, and (2) crack or 'hydro-crack' the middle distillates
into naphtha.
The overall thermal efficiency of the SNG refinery will be about
83%. It will produce some 1130 MM SCFD of SNG along with about
103,000 barrels per day of low-sulfur fuel oil from 365,000 barrels
per day of feedstock:
Crude oil
Condensate
Product SNG - 25,353 1,130 1,106
Product Fuel Oil 102,700 16,345 - 627
1,733
A refinery feeding 365,000 barrels per day is not a small one — it
would rank among the largest oil refineries in the United States.
Very briefly, the processing steps in the SNG refinery (Figure 4)
can be summarized in terms of the various unit processes:
Crude Unit — In this unit, the crude oil and condensate are distilled
to boil off a stream of light ends plus naphtha and a stream of
middle distillate.
Residuum Desulfurizer — The residuum from the crude unit distillation
is catalytically desulfurized, using hydrogen to convert sulfur
(in the residuum) into gaseous H2S. This unit may also be
called a hydrotreater.
Hydrocracker — The middle distillate from the crude unit is cataly-
tically cracked into smaller molecules of naphtha. Hydrogen is
used to saturate the naphtha (i.e. provide the needed hydrogen-
to-car bon ratio) and simultaneously convert sulfur in the middle
distillate into gaseous H^S.
Catalytic Naphtha Desulfurizer — The virgin naphtha and light ends
from the crude unit are catalytically desulfurized (again using
57
-------
hydrogen to convert sulfur into gaseous H9S). This unit may
<£•
also be called a hydrotreater.
Gas Recovery Unit — The light ends and H S streams (sour gases)
from the hydrocracker and the two desulfurizers are distilled
in this unit. The resultant streams of dry gas (H^* C-, C~)
and C.,-C4 then pass through an organic amine solution which
absorbs and removes H2S from those streams. The amine is subse-
quently boiled to release the H2S (acid gas) which is sent to
the Glaus sulfur recovery unit. The dry gas is sent to the
hydrogen plant as feedstock. A part of the C^-C^ LPG stream is
also used as hydrogen plant feedstock:, and the remainder is used
as SNG feedstock.
Hydrogen Plant — The dry gas and C~-C. LPG feedstocks are converted
into hydrogen, using steam to provide additional hydrogen.
Glaus Unit — Here the H?S acid gas is burned with air and then
catalytically converted to by-product sulfur. The residual
'tail gas1 is then further processed, utilizing hydrogen once
again, to recover additional by-product sulfur.
Naphtha SNG Plant — Finally, the naphtha streams from the hydro-
cracker and from the naphtha desulfurizer, along with LPG from
the gas recovery plant, are converted into SNG. Steam and
hydrogen are used to combine with the hydrocarbons and to produce
methane SNG and reject CO^. (This is essentially the same unit
as discussed previously in Section IV on Naphtha SNG. It includes
steps for gasification, methanation of carbon monoxide, and the
removal of C02 and water).
Auxiliary Services — These include a boiler plant to provide process
steam as well as steam for generating electrical power. The
boilers will burn fuel produced in the refinery. A closed-loop,
evaporative cooling water system is also provided, as are provi-
sions for some air-cooling equipment.
58
-------
OVERALL PROCESS MATERIAL BALANCE
The overall material balance for the SNG refinery can be summarized
as follows!
Tons/day Wt %
INPUTS:
Crude oil (less sulfur) 44,668 59.65
Condensate (less sulfur) 8,280 11.06
Sulfur 1,125 1.50
Air (process consumption only) 2,467 3.30
Steam 18,339 24.49
TOTAL 74,879 100.00
OUTPUTS:
Product SNG 25,353 33.86
Product fuel oil 16,345 21.83
By-product sulfur 1,055 1.41
CO2 vents 21,738 29.03
Tail gas 1,882 2.51
Fuel oil (consumed in-plant) 8,506 11.36
TOTAL 74,879 100.00
This balance does not include combustion air for heaters and
boilers, or the resultant stack gases.
THERMAL EFFICIENCY COMPARISON FOR VARIOUS SNG PLANTS
As tabulated earlier in this section, the SNG refinery produces
1,733 x 109 Btu/day of product SNG and fuel oil from 2,077 x 109 Btu/
day of crude oil and condensate, which is an overall thermal efficiency
of 83.4%. It is interesting to compare the different thermal effici-
encies of producing SNG and by-products from naphtha, from crude oil
and from coal:
Thermal Efficiency
SNG from Naphtha (Section IV) 97.8%
SNG from Crude Oil (Section VI) 83.4%
SNG from Coal (Section V) 70.0%
59
-------
As would be expected, coal is the feedstock with the lowest hydrogen-
to-car bon ratio and is the most difficult to gasify. Naphtha has
the highest hydrogen-to-carbon ratio and is the easiest to gasify.
SULFUR BALANCE AND SC>2 EMISSIONS
The crude oil feedstock has a sulfur content of 2.46 wt %, and the
condensate feedstock contains essentially no sulfur (0.0025 wt %).
This amounts to a total sulfur input of 1125 tons/day.
The plant sulfur balance can be summarized as:
INPUT:
Crude oil and condensate
OUTPUTS:
Sulfur in SNG product
Sulfur in fuel oil product
By-product sulfur
Treated tail gas
Stack gases
(from in-plant fuel)
Tons/day
as Sulfur
1125
wt
100.00
Actual
Form
organic S
nil
49.0
1055.0
0.5
20.5
nil
4.36
93.78
0.04
1.82
-
organic
sulfur
SO 2
S02
S
1125.0
100.00
The total sulfur emissions to the air amount to 21 tons/day, or
1.86% of the input sulfur. The equivalent S02 emissions are 42 tons/
day.
WATER BALANCE
The SNG refinery, with its auxiliary boilers and cooling tower, will
require 12,620 gpm of raw water intake. The overall water balance
60
-------
is summarized below:
3
gpm m /hr %
INTAKE:
Raw water 12,620 2,865 100.0
DISPOSITION:
Process consumption
(hydrogen supply) 3,057 694 24.2
Cooling tower evaporation 6,080 1,380 48.2
Vents 698 158 5.5
Treated effluent discharge 2,785 632 22.1
12,620 2,864 100.0
Once again, we note that about 78% of the raw water intake is
ultimately returned to the atmosphere, when we include the water of
combustion that will be released wherever the product SNG and fuel
oil are burned. This is compared with 83% for the naphtha SNG plant
and 80% for the coal SNG plant.
The treated effluent discharge of 2,785 gpm includes boiler and
cooling tower blowdowns, as well as treated effluent waters. A con-
ventional refinery waste treatment plant processes these waters before
discharge. Treatment includes:
— In-plant sewer segregation and sour water stripping.
— Primary oil and suspended solids removal in an API separator
and air flotation unit.
— Secondary treatment via biological oxidation.
— Final disinfection.
STACK GASES
Table 9 is a listing of the plant stacks, and their stack gas
effluents.
61
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TABLE 9E — STACK GASES FROM SNG REFINERY - ENGLISH UNITS
Stack Gases
Tons/day
Ibs/MM Btu
MM SCFD
H Plant Heaters 898
Boilers 2,678
Process Heaters 1,200
Treated Tail Gas
C00 Vents 375
£.*
tons/day
34,332
102,400
45,936
1,882
21,738
SO_ NO MM Btu/day
2 X -
0.2 8.2 54,720
29.1 26.5 176,360
12.0 10.8 72,580
1.0
- -
42.3 45.5
SO , NO
0.01 0.30
0.33 0.30
0.33 0.30
-
-
(The H- Plant heaters use a very low sulfur in-plant intermediate
fuel. Hence, the lower emissions of S02 on a Ib/MM Btu basis)
-------
TABLE 9M — STACK GASES FROM SNG REFINERY - METRIC UNIT
Stack Gases
Mg/day"
kg/Gcal Btu
H2 Plant Heaters
Boilers
Process Heaters
Treated Tail Gas
CO 2 Vents
Mnm^/day Mg/day*
24.1 31,146
71.7 92,897
32.1 41,673
1,707
10.0 19,721
S00 NO
0.18 7 . 44
26 .40 24 . 04
10.89 9.80
0.91
-
38.38 41.28
Gcal/day SO,, NO..
^ ' £* '" - ' '"" J\.
13,789 0.013 0.540
44,443 0.594 0.540
18,290 0.594 0.540
_
_
(The H2 Plant heaters use a very low sulfur in-plant intermediate
fuel. Hence, the lower emissions of SO- on a kg/Gcal Btu basis)
Mg/day is equivalent to metric tons/day
-------
OTHER ENVIRONMENTAL FACTORS
The key environmental factors, which already have been discussed
above, are:
— Water consumption and disposition
— SO., emissions
Other environmental factors, all relatively minor, are briefly
discussed below.
There are a number of solid waste disposal problems involving raw and
effluent water treatment sludges, spent catalysts and spent chemicals.
The sludges may amount to as much as 40 tons/day, and the design
proposes to dispose of them in a 20-30 acre biological land cultivation
area. Spent catalysts and chemicals require disposal only at infrequent
intervals (12-24 months), and these will either be returned to their
manufacturers for reclaiming or, in some cases, may possibly be used
for land fill.
The usual noise problems associated with a major oil refinery will
be encountered. However, good design practice should make a 55-65 dBA
limit at the plant property line realistically achievable during normal
operation.
About 135 MW of electrical power will be required by the plant, but
it will be generated on-site in this design.
Storage tanks with a capacity of about 15 million barrels (630 million
gallons) will be required for feedstock, product fuel oil, and in-
plant intermediate products.
A very large emergency flare system will be required, just as in the
coal gasification plant.
Since the fuel oil produced and burned in-plant has a very low ash
content (about 0.01 wt % or less), there will be no problem with
stack gas particulates.
64
-------
Construction manpower will peak at about 5000 personnel. Depending
on the plant location, this may cause local temporary housing problems
and other socio-economic impacts.
ADDITIONAL READING
Beychok, M. R. Aqueous Wastes from Petroleum and Petrochemical
Plants. John Wiley § Sons, London, 1967.
Beychok, M. R. State-of-the-Art Wastewater Treatment. Hydrocarbon
Processing j>£:12 109-112, December 1971.
Hazelton, J. P., and R. N. Tennyson. SNG Refinery Configurations.
Chemical Engineering Progress £9:7 97-101, July 1973.
65
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SECTIONoVII
LNG ~ LIQUEFACTION AT SOURCE
Natural gas can be liquefied by refrigerating it to approximately
-259°F at atmospheric pressure. Liquefaction of the gas 'shrinks1
about 625 cubic feet of gas into 1 cubic foot of liquid. This makes
it economically feasible to transport natural gas from remote overseas
sources to the domestic U.S. market. The liquefied natural gas (LNG)
is transported from those remote sources in very large, refrigerated
ships called LNG tankers or LNG carriers. Each tanker can carry an
amount of LNG which, when regasified at the market terminal, will
become 3 billion SCF of natural gas.
TYPICAL PROCESS DESIGN FOR LNG LIQUEFACTION
First, it must be understood that there is no typical design for
liquefying natural gas. Any given design depends on a number of
factors:
— The pressure and composition of the raw natural gas ia a very
important factor which will determine much of the design configura-
tion.
— A decision must be made whether to remove LPG and condensate, if
any, from the raw gas at the liquefaction site or whether to remove
those natural gas liquids (NGL) at the market terminal. (The
usual decision has been to remove the NGL at the liquefaction site
although import regulations or other,factors may make it more
desirable to ship the NGL to the market terminal with the LNG).
— The type of refrigeration process must be chosen. There are a
number of processes to be considered but generally they fall into
two categories! the classical 'cascade1 system and the 'mixed compo-
nent ' system.
— The location and ambient temperature conditions of the site are
also factors in the design.
— Finally, individual preferences of the plant owners and the designers
will affect the design.
66
-------
In general, however, all LNG liquefaction plants have certain common
characteristics. Since the raw gas must be refrigerated to very low
temperatures, it must first be 'treated1 to remove acid gases (H?S and
C02) and water which would otherwise freeze and plug the refrigeration
system equipment. In any event, they must be removed for another
reasons to meet pipeline and end-use specifications at the marketing
site.
Next, the NGL will be removed and purified (if the gas contains any
significant amounts), assuming the decision were made to remove them
at the liquefaction site.
Finally, the gas will be cryogenically processed (refrigerated to
very low temperatures) and liquefied at about -259°F. The LNG product
is then stored in large tanks until loaded onto the LNG tankers. The
boil-off vapors from the storage tanks, caused by atmospheric heat
flowing into the cold tanks, are returned to the cryogenic plant for
re-processing. The vapors displaced from the tanker, when loading
out LNG, are returned to the storage tanks to replace the volume of
liquid loaded out.
In summary then, an LNG liquefaction plant will consist of;
— Raw gas treating to remove H2S, C02 and water.
— Removal and recovery of natural gas liquids (NGL), if any.
— Cryogenic liquefaction of the gas.
— Storage of the LNG product, and facilities for loading LNG
aboard tankers or carriers.
Figure 5 presents a process flow diagram for a plant which liquefies
an average of 200 MM SCFD of natural gas.
This description of an LNG liquefaction plant is based on a
specific feed gas composition and a specific site, and is not
universally applicable. It is intended merely to illustrate
the processes involved.
67
-------
Raw
Natural Gas
-*. CCU Vent
FEED GAS
TREATING
T
CRYOGENIC
LIQUEFACTION
OO
Fuel
Gas
Fuel
Gas
Air
Boil-off
Oxygen Vent
LNG
STORAGE
AIR
SEPARATION
PLANT '
T
Fuel
Gas
LNG Product
to tankers
Vapor return
Figure 5
Process Flow Diagram
LNG LIQUEFACTION
-------
This design was based on a very 'sweet' raw gas containing essentially
no natural gas liquids, so the only raw gas treatment required is the
removal of C02 and water. The compositions of the feedstock: and the
product are:
Volume %
Raw Gas LN6 Product
Nitrogen 0.43 0.28
Methane 99.51 99.66
Ethane and Propane Q.Q6 0.06
100.00 100.00
Water, ppmv 275 less than 1
C02, ppmv 1,000 less than 50
H2S, ppmv nil nil
The plant was designed to utilize gas-turbines for driving the compre-
ssors in the refrigeration cycle. Since the chosen cycle was 'mixed
component' refrigeration, and since one of the refrigerant components
used in this case is nitrogen, an air separation plant is needed to
obtain nitrogen from the atmosphere. Gas-turbines are also used for
driving the compressors in the air separation plant. The total compre-
ssion in the overall plant amounts to about 85-90,000 horsepower.
Air-cooling is used throughout the plant. All heating needs and all
gas-turbines are supplied with treated feed gas as fuel, so no steam
boiler is required. With no cooling tower and no boiler plant, the
intake of raw water is very minimal, only 5,000 gallons per day (3.5 gpm)
THERMAL EFFICIENCY
The consumption of fuel for process and other heating and for the
approximately 90,000 horsepower of gas turbines totals 18 MM SCFD of
treated feed gas. Thus, the plant must feed 218 MM SCFD of gas to
-liquefy 200 MM SCFD. Therefore, the plant has an overall thermal
efficiency of 91.7% based on feed and product heating values.
69
-------
Some of the energy used in the plant, however, is provided by the
pressure of the raw feed gas. If the gas enters the plant at 500-1000
psig and leaves as a liquid at atmospheric pressure, that expansion
energy has been utilized within the process. Eventually, at the LNG
market regasification site, most of that pressure will have to be
re-supplied for the distribution pipeline. This point is mentioned to
emphasize that the thermal efficiency of an LNG liquefaction plant is
affected to some extent by the pressure energy available in the feed
gas.
STACK GASES AND EMISSIONS
The only stack gas emissions from the plant are those resulting from
the burning of 18 MM SCFD of fuel gas. By far, the largest amount of
that fuel will be used in the gas turbines. The fuel gas will be
treated feed gas, or almost pure methane with no sulfur content. The
only emission of concern, therefore, is NO . A well-designed gas turbine
X
burning methane should not produce more than 0.25-0.35 Ibs. of NO per
X
MM Btu heat release.
Although gas turbines use 200-300% excess air, we can use Table 3 to
estimate that the total stack gas rate (corrected to 15% excess air)
will be 11,830 SCF/MM Btu when burning methane. Thus, we can arrive at:
Total fuel burned 18 MM SCFD of C-
Q
Total heat release 18 x 10 Btu/day
Total wet stack gas rate 213 MM SCFD (8,149 tons/day)
Total NOX 2.3-3.2 tons/day
(0.25-0.35 Ibs/MM Btu)
«
The 218 MM SCFD of feed gas contains 1000 ppmv of C0~, which is
reduced to 50 ppmv in the feed gas treater. This amounts to a vent of:
C02 vent 207,000 SCFD
24,040 Ibs/day
12 tons/day
70
-------
Finally, the air separation plant will vent about 1.5 tons/day of
oxygen to the atmosphere.
WATER BALANCE
The total water intake to the plant will be only about 5,000 gallons/
day because the total plant cooling in this specific case is provided
by air-coolers. If a cooling water system had been necessary or
economic, the water intake would have been much higher.
All of the water is used for plant wash-down, sanitary uses, potable
drinking water and make-up to the plant's self-contained fire-fighting
or firewater system. A small, prefabricated waste- treatment unit will
process the effluent water from the plant and return 5,000 gallons/day
to the local waterway.
OVERALL MATERIAL BALANCE
tons/day wt %
INPUTs
Raw feed gas 4,612.0 99.8
Air (to air separation plant) _ 7.9 0- 2
4,619.9 100.0
OUTPUTS :
LNG product 4,220.0 91.3
Fuel (burned in-plant) 380.0 8.3
C02 vent 12.0 0.3
02 vent 1'5
N losses and purging 6.4 — P-ii
4,619.9 100.0
71
-------
OTHER ENVIRONMENTAL FACTORS
Only a very few other factors need be considered, and they are
briefly discussed below.
The plant will require a very large emergency flare system, much the
same as in all the other plants discussed in this report.
With 85,000 to 90,000 horsepower of gas turbines, the plant will have
a distinct noise problem. Nonetheless, a plant property line limit of
60-70 dBA should be attainable.
Tankage on the order of 4,000-5,000 barrels will be required to store
the liquid refrigerants.
About 1,000,000 barrels of cold LNG storage will also be required.
The safety aspects of that storage deserve serious study in each case.
Dredging of the harbor to accommodate LNG tankers (if that is required)
will create some environmental concerns that should be carefully
considered.
OTHER PLANT CONFIGURATIONS
A design using water-cooling and steam turbines would be quite different,
in terms of water and fuel balance, than the one described herein. If
the feed gas contained H2S, that would also alter the emission factors
given.
ADDITIONAL READING
Bourquet, J. M. Ecomonics of Today's Plants. Hydrocarbon Processing
49:4 93-96, April 1970.
72
-------
Crawford, D. B., and R. A. Bergman. Innovations Will Mark LNG-
Receiving Terminal. Oil and Gas Journal .72:31 57-61, August 1974.
Dames § Moore. Detailed Environmental Analysis, Proposed Liquefied
Natural Gas Project for Pacific Alaska LNG Company. Unpublished
report, July 1973.
DiNapoli, R. N. Design Needs for Base-Load LNG Storage,
Regasification. Oil and Gas Journal .71:43 67-70, October 1973.
Durr, C. A. Process Techniques and Hardware Uses Outlined for
LNG Regasif ication. Oil and Gas Journal 7_2:19 56-66, May 1974.
Dyer, A. F. LNG from Alaska to Japan. Chemical Engineering
Progress 6j>:4 53-57, April 1969-
73
-------
SECTION VIII
LNG — REGASIFICATION AT MARKET
Liquefied natural gas (LNG) is transported to market regasification
plants in very large carriers. Each tanker can deliver as much as
855,000 barrels of LNG, which will become about 3 billion SCF of
natural gas when regasified.
Basically, an LNG regasification plant simply heats and boils the
LNG to reconvert it to natural gas for pipeline distribution. The
plant will contain three functional facilities:
— A tanker docking and unloading facility
— Large LNG storage tanks
— A regasification facility wherein the LNG is vaporized
(i.e. heated and boiled)
In general, LNG will be withdrawn from the storage tanks as needed
to supply the plant's base-load output of gas plus any peak-load
requirements during cold weather. The LNG is raised to pipeline
pressure (500-1000 psig) by cryogenic pumps, and is then vaporized by
exchanging heat with water or by fuel-fired heating equipment. Since
the LNG receiving terminal is usually in a coastal harbor, seawater is
readily available for vaporizing the LNG.
TYPICAL DESIGN FOR LNG REGASIFICATION
Figure 6 presents a schematic flow diagram for a typical LNG regasi-
fication plant.
This description of an LNG regasification plant is based on
a specific design for a specific site, and is not universally
applicable. It is intended merely to illustrate the processes
involved.
This plant was designed to vaporize a base-load of about 1,000 MM SCFD
of gas. It also includes facilities to vaporize an additional 450 MM
SCFD of gas for 20 days per year (the peak-load days).
74
-------
Supply at 73 F
Warmed seawater
from power plant Return at 58 °F
Vapor return
to tankers "I
LNG
from
tankers
Boil-off
| 1
I I
j
LNG
STORAGE
(-259 °F)
WARM WATER
VAPORIZERS
(47 0F)
TRIM
HEATERS
Base-load
1000 MMSCFD
Fuel
FIRED
VAPORIZERS
Peak-load
Pipeline Gas
(50°F)
450 MMSCFD
(20 days per year)
Fuel
Figure 6
Process Flow Diagram
LNG REGASIFICATION
-------
Base-load vaporization in this design is accomplished by using warmed
seawater (73°F) obtained from an adjacent large power plant*. The LNG
and the seawater exchange heat in tubular exchangers wherein the LNG
is heated and vaporized and the seawater is cooled. About 16 billion
Btu's of heat per day are exchanged when vaporizing 1,000 MM SCFD of
gas. The vaporized LNG leaves the exchangers at 47 F and is then
'trim-heated* to 50°F (required for pipeline transmission) by small gas-
fired heaters, which supply about another 89 million Btu's per day.
The peak-load vaporization of an additional 450 MM SCFD of gas is
accomplished in gas-fired vaporizers which will supply about 7 billion
Btu's of heat per day.
The vaporizing operations can be summarized as follows:
Water:
Inlet temperature, °F
Outlet temperature, °F
Flow rate, gpm
Heat exchange, 10 Btu/day
Vaporized gas:
Flow to pipeline, MM SCFD
Temperatures:
From water exchangers
Into pipeline
Fired heat input, 10 Btu/day
Fired heat fuel, 106 Btu/day
Base-Load
73
58
89,500
16,200
1000
47
50
88.8
110.4
Additional
Peak-Load
(20 days/year)
450
50
7340
7640
* The power plant takes in seawater at 50°F, uses it to condense
turbine exhaust steam and discharges the water at 73°F. The
LNG regasification plant receives the water at 73°F and cools
it to 58 F by heat exchange with LNG. Thus, water returns to the
sea about 8 F warmer than originally obtained.
76
-------
THERMAL EFFICIENCY
During the long voyage in the LNG tankers, about 2.5% of the LNG boils
off (due to the absorption of atmospheric heat) and is used as tanker
fuel. This fuel consumption will be included in the following account-
ing of thermal efficiency for the regasification plant.
The regasification plant uses about 25,000 KW of electrical power,
mostly for the cryogenic pumps (which supply the required pipeline gas
transmission pressure) and for the seawater pumps. This amounts to
2,000 x 10 Btu/day of energy. Since that energy is generated in a
power plant typically operating at about 33% efficiency, the regasifi-
cation plant is in fact using about 6,000 x 10 Btu/day of equivalent
fuel when it consumes 25,000 KW of power. This fuel consumption will
also be included in the following efficiency accounting. Finally, the
20 days of additional peak-load vaporizing will be pro-rated over the
year to arrive at a total daily average basis for thermal efficiency.
Delivered to Pipeline
Base Pro-rated
On Tankers Load Peak-Load
Gas, MM SCFD 1051 1000 25
HEAT INPUTS: 109 Btu/day
Gas loaded on tankers (as LNG) 1051.0
Electrical power (equivalent fuel) 6.0
Fuel for fired vaporizers 0-5
1057.5
HEAT OUTPUTS:
Gas to pipeline 1025.0
Fuel for tankers (boil-off) 26.0
Consumed (to pressurize & vaporize LNG) 6.5
1057.5
Thermal Efficiency (based on product gas output)
= (1025/1057.5) 100 = 96.9%
(1) Assuming a gas heating value of 1000 Btu/SCF as typical
(2) The 7.64 x 109 Btu/day of peak load vaporizing fuel amounts to
0.4 x 109 Btu/day when pro-rated to 365 days. The trim heaters
for base-load use another 0.1 x I0y Btu/day.
77
-------
If we refer to Section VII on LNG liquefaction and consider that
plant's thermal efficiency of 91.7% as being typical, then we have an .
overall LNG project thermal efficiency amounting to 91.7% of 96.9%,
or 88.9%.
Where has the 11.1% of the heat been 'lost1? In a number of placess
— Supplying energy to refrigerate and liquefy the LNG at the
source liquefaction plant
— Supplying fuel for the LNG tankers
— Supplying energy to pump seawater through the LNG vaporizers
— Supplying energy to pump the LNG up to pipeline distribution
pressure
— Supplying fuel for gas-fired LNG vaporizers
If we consider the overall LNG project (liquefaction, tanker transport
and regasification) as a gas transmission system over a 5,000-6,000 mile
distance, the overall energy loss of 11.1% can be rationalized as about
2% per 1000 miles, which is quite good.
STACK GASES AND EMISSIONS
The only source of air emissions in the regasification plant design
(Figure 6) is the stack gas from the fired vaporizers. Since the fuel
supply is vaporized LNG, the sulfur content of the stack gases is
practically nil, but they will contain nitrogen oxides as shown below:
Base-Load Peak-Load
Trim Heaters Vaporizers
Stack gases, tons/day 53 2990
, MM SCFD 1.4 78
NO , Ibs/day 20 917
J\.
, Ibs/MM Btu 0.18 0.12
These are relatively insignificant emissions, especially when we
consider that the peak-load vaporizers are only used 20 days per year.
78
-------
WATER BALANCE
The only water balance factor in the plant is the use of 89,500 gpm
on a once-through basis for vaporizing the base-load LNG. The water
enters the gasification plant at 73°F and leaves at 58°F, which is only
8°F warmer than when originally taken from the sea by the power plant.
The LNG plant will also require about 3,000 gallons/day (2.1 gpm) of
city water for sanitation and potable water.
OTHER ENVIRONMENTAL FACTORS
In general, an LNG regasification plant is a very clean one, without
any major air emissions or wastewater discharges. The once-through
cooling of seawater will normally create a "cold thermal impact" problem
when the seawater is returned, although in the specific case discussed
herein, that problem was solved by re-using warm water from an adjacent
power plant.
The primary concern with an LNG receiving terminal will be one of safety.
Incoming tankers will be fully loaded with LNG which will be off-loaded
and stored on-site in very large tanks — perhaps 2 to 3 tanks of
500,000 to 750,000 barrels each. This will require careful and detailed
evaluation of each specific site.
Noise from the cryogenic and seawater pumps should be a relatively
minor problem.
A large emergency flare will be required, just as in all the previous
plant discussions.
Dredging of the harbor to accommodate the LNG tankers (if that is
necessary) will create some environmental concerns that require study.
79
-------
THE DIFFERENCE BETWEEN BASE-LOAD AND PEAK-SHAVING LNG PLANTS
A gas distribution company must supply two types of demand. One is
a year-round demand for an average or 'base-load* amount of gas. The
other is an additional 'peak-load' demand, during the coldest winter
season, for an incremental amount of gas over and above the base-load.
Many gas companies are having difficulty in obtaining enough domestic
U.S. gas to supply their average base-load. Such companies are import-
ing LNG from overseas, and regasifying the LNG at coastal receiving
terminals. These are usually very large installations, including
LNG tanker docks and unloading systems, and are called 'base-load LNG
plants'. It is these base-load plants which have been described in
Sections VII and VIII herein.
Other gas companies may have somewhat more than enough domestic gas
to supply their base-load demands, but not enough to supply their
incremental peak-load demand in the winter. Those companies have two
options:
1 — During the summer, they can divert excess gas supplies into under-
ground caverns for storage until the winter. Then during the peak
season, they can withdraw gas from the caverns.
2 — If suitable underground areas are not available, excess summer
gas can be withdrawn from their supply pipeline and liquefied by
refrigeration. The liquified gas (LNG) can be stored in large
tanks, and withdrawn for regasification during the winter peak
season. Such an installation is called a 'peak-shaving LNG plant'.
The basic difference between the two types of LNG plants (base-load and
peak-shaving) is that the peak-shaver is usually a fairly small plant
other than for a large LNG storage capability. Peak-shaving plants are
smaller than imported LNG base-load plants because:
— The incremental peak-gas demand may be only 10-40% of the base-load
demand.
80
-------
-- The peak season may only last 1-2 months, whereas the low-demand
summer season may last 5-7 months. Thus, there may be 7 summer
months in which to produce and store LNG for use during a 1 month
peak season. This is a production-to-usage time ratio of 7:1. If
the peak demand rate is 35% of the base-load rate, LNG can be
produced and stored in the summer at a rate that is only 5% of the
base-load rate.
ADDITIONAL READING
Bourquet, J. M. Economics of Today's Plants. Hydrocarbon Processing
49:4 93-96, April 1970.
Crawford, D. B., and R. A. Bergman. Innovations Will Mark LNG -
Receiving Terminal. Oil and Gas Journal 7_2:31 57-61, August 1974.
Dames § Moore, Detailed Environmental Analysis, Proposed Liquefied
Natural Gas Project for Pacific Alaska LNG Company. Unpublished
report, July 1973.
DiNapoli, R. N. Design Needs for Base Load LNG Storage, Regasifica-
tion. Oil and Gas Journal _71_:43 67-70, October 1973.
Durr, C. A. Process Techniques and Hardware Uses Outlined for LNG
Regasification. Oil and Gas Journal ^72:19 56-66, May 1974.
Dyer, A. F. LNG From Alaska to Japan. Chemical Engineering Progress
6j>:4 53-57, April 1969-
81
-------
SECTION IX
METHANOL FUEL
As discussed in previous sections, natural gas can be liquefied for
transport in large refrigerated LNG tankers to regasif ication terminals
near the end-use market. As a technologically viable alternate, the
natural gas could be converted to methanol (an alcohol) which can be
transported to market and burned directly as a liquid fuel without any
regasif ication step at all. Since methanol has a boiling point of
148°F, it is a liquid at ordinary temperatures and requires no refrig-
eration. Obviously, the cost of storage, handling and transportation
facilities for methanol would be much less expensive than those for LNG.
Because of this, many companies are evaluating the economics of trans-
porting overseas natural gas as methanol rather than LNG. In fact,
some companies have announced plans to proceed with such projects.
Some of the physical properties of methanol and LNG are compared belows
(2)
Methanol LNG
Chemical formula CH3OH CH.
Liquid density, lbs/ft3 49.6^ 26.
HHV, Btu/lb 9,750 23,900
HHV, Btu/CF of liquid 484,000 632,000
Boiling point at atmospheric pressure 148°F -259°F
(1) Based on pure methanol (2) Based on pure methane
(3) At 60°F (4) At -259°F
TANKER AND CAPITAL REQUIREMENTS COMPARED TO LNG
Most published studies agree that the economic advantages of methanol
storage and transportation make it competitive with LNG when the round
trip transportation distance is about 8,000-10,000 nautical miles. At
even longer distances, a methanol project seems to be distinctly more
economic than a comparable LNG project.
82
-------
Table 10 presents a detailed comparison of the tanker requirements
for equivalent methanol and LNG projects. Briefly, Table 10 can be
summarized as follows:
Methanol LNG
Delivered product 25,000 tons/day 500~MM SCFD
Delivered energy, 1012 Btu/year 178 184
One-way trip, nautical miles 6,250 6,250
Round-trip, nautical miles 12,500 12,500
Tanker capacity 160,000 tons 125,000 cu.m.
Tanker speed 16 jmots 20 knots
Round- trips/year/tanker 9.7 11.8
Tankers required 6 6
Thus, 6 tankers would be required for either a 25,000 ton/day methanol
project or for a 500 MM SCFD LNG project, both large projects delivering
essentially equivalent amounts of energy (178 to 184 x 10^2 Btu/year).
160,000-ton methanol tankers would cost about $33 million each, and
125,000 cubic meter LNG tankers would cost about $80 million each.
Therefore, the total tanker cost of the methanol project would be about
$280 million less than the equivalent LNG project, based on mid-1973
costs and on a 12,500 nautical mile round- trip distance.
Comparing the overall capital investments for the equivalent plants,
it can be seen that the savings in tanker costs more than offset the
higher cost of the overseas methanol conversion plant relative to the
LNG plant:
_ CAPITAL INVESTMENT _
Methanol LNG
Delivered product 25,000 tons/day 500 MM SCFD
Capital investment:
Overseas conversion plant 375 MM $ 260 MM $
6 tankers • • 200 MM $ 480 MM $
Market terminal 20 MM $ 80 MM $
595 MM $ 820 MM $
These capital investment estimates are based on mid-1973 costs and
are perhaps accurate within ± 20%. The LNG project includes
regasification, and the methanol project does not.
83
-------
TABLE IDE -- TANKER REQUIREMENTS (METHANOL VS LNG) -
ENGLISH UNITS
HHV, Btu/lb
HHV, Btu/CF (liquid)
Typical tankers i
Delivered cargo, cu.meters
, short tons
, 1012 Btu
Travel speed, knots
12,500 nautical miles, round-trip;
Round-trip travel, days
Loading/unloading/bad weather, days
Total trip, days
Round-trips per year
Energy delivered per tanker per year,
1012 Btu's
Project sizes-& tanker requirements;
Delivered product, tons/day
, MM SCFD
, 1012
Btu/year
METHANOL
9,750
484,000
160,000
3.12
16
Tankers required
30.3
25,000
178
6
(3)
LNG
23,900
632,000
125,000
2.79
20
(1)
(2)
32.6
5.0
37.6
9.7
26.0
5.0
31.0
11.8
32.9
500
184
6
(3)
(1) Equivalent to 1,010 Btu/SCF (gas)
(2) 1 cu. ft. of LNG liquid = about 625 cu.ft. of natural gas
(3) Practically equivalent project sizes since regasification
of LNG consumes some energy for vaporizing and for pumping
(see LNG Regasification section). Methanol sold as liquid
fuel, with no regasification.
84
-------
TABLE 10M -- TANKER REQUIREMENTS (METHANOL VS LNG) -
METRIC UNITS
METHANOL LNG
HHV, teal/kg 5j417 13,279(1)
HHV, kcal/m (liquid) 4,307,000 5,625,000(2)
Typical tankers;
Delivered cargo, cubic metres - 125,000
, metric tons 145,150
> Teal 786 703
Travel speed, km/hr 29.6 37.0
23,150 kilometres, round-trip;
Round-trip travel, days 32.6 26.0
Loading/unloading/bad weather, days 5.0 5.0
Total trip, days 37.6 31.0
Round-trips per year 9.7 11.8
Energy delivered per tanker per year,
Teal 7,624 8,295
Project sizes & tanker requirements;
Delivered product, metric tons/day 22,680
, Mnm3/day - 13.40
, Teal/year 44,856(3) 46,368(3)
Tankers required 6 6
(1) Equivalent to 9,500 kcal/nm (gas)
(2) 1m3 of LNG liquid = about 625 m3 of natural gas
(3) Practically equivalent project sizes since regasification
of LNG consumes some energy for vaporizing and for pumping
(see LNG Regasification section). Methanol sold as liquid
fuel with no regasification.
85.
-------
As can be seen, the overall methanol project requires considerably
less capital, about $225,000,000 less. However, more capital must be
invested overseas and this may raise considerations of political sensi-
tivity.
As will be seen later in this section, the methanol project has a thermal
efficiency of about 55%, compared with the LNG project's thermal effi-
ciency of about 89% (see previous sections). Thus, the methanol project
will consume about 60% more raw natural gas than will the LNG project
to produce the same amount of energy. The cost of raw natural gas
therefore becomes significant in the relative economics of the alternative
projects. When all the factors of capital, operating and raw gas costs
are considered, it has been estimated that the comparative end-product
fuel values, delivered at the market terminal, are:
Round-trip
distance, $/million Btu's
nautical miles Methanol LNG
24,000 1.10 1.60
16,000 1.05 1.30
8,000 0.98 0-98
(Based on a raw natural gas price of ll
-------
TYPICAL PROCESS DESIGN FOR METHANOL SYNTHESIS
The synthesis of methanol from natural gas is a two-step process.
First, the natural gas is 'reformed' to produce a gas containing
primarily carbon monoxide and hydrogen. The gas is then converted to
methanol in a 'methanol synthesis' unit, and the methanol is distilled
to remove and recover water. The two chemical reactions can be written
as:
CH4 + H20 •* CO + 3H2 -» CH3OH + H2
As can be seen, the conversion produces excess hydrogen (H?) as well
as methanol (CH^OH). Rather than waste this hydrogen, a supply of
carbon dioxide (CO,,) can be reacted with the excess hydrogen to make
additional methanol:
1/3 CO2 + H2 -» 1/3 CH3OH + 1/3 H20
The resulting overall reaction of converting methane plus carbon
dioxide plus steam into methanol can be written as:
CH4 + 1/3 C02 + 2/3 H20 •* 4/3 CH3OH
Figure 7 presents a schematic flow sheet for converting natural gas
into methanol, which involves five process steps:
This description of a methanol plant is based on literature
studies and estimates, and is not universally applicable.
It is intended merely to illustrate the process involved.
Reforming — Natural gas, CO- and steam are reformed, at about 200-
300 psi pressure and 1500-1600 F, to yield the synthesis feed gas.
Compression — The synthesis feed gas is compressed to the pressure
required in the methanol synthesis unit.
Methanol Synthesis — The synthesis gas is catalytically converted
to methanol and water. Three process technologies are available
for this synthesis:
(a) The ICI process (England)
(b) The Lurgi process (Germany)
(c) The Vulcan process (U.S.A.)
87
-------
00
00
1
Stack gas ^
'
(N
o
u
1
Natural
CO 2
REMOVAL
Water '
L
I
Gas ,
0)
-P
CQ
1
i
QUENCH
I
I
fS-
«
i
i-
-s.
x.
j
N.
V
i
i
%
V
1
Fuel
gas
* —
CO
(0
Gn
3d
ns
4-)
CO
N
i
^\
I
REFORMER FURNACE
s-. ^^~~^/ AND HEAT EXCHANGE
M
(U
r
L
0)
-p
CO
1
^^ /
/
Y-
METHANOL METHANOL Methanol
. COMPRESSION »- SYNTHESIS *" DISTILLATION Fuei
\ \
Water Water
F
Purge gas
Figure 7
»
Process Flow Diagram
METHANOL FUEL
-------
These processes vary from 'low-pressure1 to 'high-pressure1 over
a range of 750 to 4500 psi pressure, and a temperature range of
400-700°F.
Distillation — The methanol product is boiled to remove and recover
water. The product methanol is then stored for subsequent loading
aboard tankers.
Stack Gas Quench and CO2 Removal — A portion of the stack gases from
the reformer furnace is cooled by quenching with water. The
cooled gases are then processed to remove and recover CO,, as
required in the production of methanol.
If we consider the flow scheme in Figure 7 as a single 'module', the
largest such module under consideration today would produce about
5,000-7,500 tons/day of methanol. Thus, a 25,000 ton/day methanol
project would require 4 to 5 parallel modules, each as shown in Figure 7.
THERMAL EFFICIENCY
The overall thermal efficiency of a plant producing 25,000 tons/day of
methanol from natural gas can be approximated as:
109 Btu/day
(HHV)
Natural gas feed 530
Fuel gas to reformer 340
Fuel gas to electrical generation 15
TOTAL INPUTS 885
Product CH3OH 488
Overall thermal efficiency = (444/885)(100) = 55%
The overall project efficiency is, in fact, lower yet because of the
tanker fuel requirements. When we compare this very low efficiency
with the 89% thermal efficiency of an LNG project, it becomes obvious
that the methanol project involves a 'trade-off of natural gas conser-
vation versus lower cost storage and transportation. From the environ-
mental viewpoint, can we afford a 55% efficiency versus an 89%
efficiency in order to conserve capital?
89
-------
OVERALL MATERIAL BALANCE
The material balance for the chemical processes involved can be
approximated as:
MM SCFD Tons/day
Natural gas feed 525 11,100
Water (consumed chemically) - 7,000
C02 8,600
TOTAL INPUTS 26,700
Product CH3OH ' 25,000
Purge gas 1>700
TOTAL OUTPUTS 26,700
The material balance for the fuel gas combustion and CO^ recovery can
be expressed ass
Tons/day
Reformer fuel gas 7,100
Purge gas to reformer fuel 1,700
Fuel gas to electrical generation 300
9,100
Combustion air (w/10% excess) 172,800
TOTAL INPUTS 181,900
C02 8,600
Stack gases 173,300
TOTAL OUTPUTS 181,900
T^6 overall material balance is the combination of the above two
balances:
Tons/day
Natural gas feed 11,100
Water (consumed chemically) 7,000
Fuel gases 7,400
Combustion air 172,800
TOTAL INPUTS 198,300
Product CH3OH 25,000
Stack gases 173,300
TOTAL OUTPUTS 198,300
90
-------
WATER BALANCE
Water is required in the process plant:
— as boiler feedwater to produce steam for reaction, for driving
compressors, and for heat in the methanol distillation.
— as makeup to the cooling water system.
— for the usual potable and sanitation requirements.
Most of the steam used for compressor drives and for distillation heat
can be recovered and reused as boiler feedwater. Hence, only the
boiler and cooling water system blowdowns must be made up by fresh
water .
It can be assumed that the excess reaction steam, when removed in the
compression and distillation sections (see Figure 7), can be reused as
boiler feedwater after some nominal treating.
Thus, there are only four ultimate consumptions of water which must be
supplied by fresh water:
— Boiler blowdown
— Cooling water blowdown
— Chemical consumption of reaction steam
— Potable and sanitation uses
Chemical consumption of steam (i.e. water) amounts to 0.28 tons per
ton of product, as shown in the overall material balance. The total use
of fresh water for makeups and chemical consumption has been estimated
as ranging from 1.5 to 2.5 tons per ton of product. For a 25,000 ton/day
methanol plant, that would amount to 6,250-10,400 gpm — a very large
amount. The breakdown is approximated as:
tons/ton product
Chemical consumption 0.3 1,250
Cooling water makeup 1.0 - 2.0 4,150 - 8,300
>.
Boiler feed makeup 0.2 850
1.5 - 2.5 6,250 - 10,400
* For a 25,000 ton/day methanol plant, and neglecting the relatively
insignificant amount of potable/sanitation water.
91
-------
Obviously, if once-through sea-water cooling is used rather than an
evaporative cooling tower system, then the fresh water consumption
might be as low as 0.5 ton per ton of product (2,000 gpm). Alternatively,
extensive use of air-cooling would decrease the fresh water needs.
It might be interesting at this point to compare the fresh water usages
of the various chemical conversion processes discussed in this report:
q
10 Btu/day qpm
Naphtha SNG 100 380
i -->\
Coal SNG 310 5,100V '
Product Energy Fresh Water
m
(1)
(2)
(3)
Methanol Fuel 488 8,325
(9)
Oil SNG 1,733 12,620^'
(1) All air-cooling
(2) Extensive air-cooling
(3) Average of 6,250-10,400 gpm
This tabulation shows that the coal SNG and methanol plants are by far
the largest users of fresh water per unit of product energy.
SUMMARY OF ENVIRONMENTAL FACTORS
Since all the fuel burned in the plant is natural gas, which must be
purified prior to use as feedstock, there will be no stack gas emission
problems of any kind. If the natural gas purification plant is included
in the complex, it can be assumed that it includes a sulfur removal and
recovery unit.
The major environmental consideration is the fresh water usage. The
quantity required is very large, unless a, once-through seawater cooling
system is used.
The process effluents of excess reaction steam as condensed water (see
Figure 7) must be treated and reused as boiler feedwater.
92
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Socio-economic/socio-political factors are probably the most significant,
i.e., can a process which is only 55% efficient in its conservation of
energy be justified by a savings in capital investment, most of which
must be invested in an overseas nation?
The other factors (noise levels, emergency flares, and construction
personnel) will be very similar to those for the SNG plants discussed
in previous sections.
ALTERNATIVE CONFIGURATIONS
This section has been devoted to the production and transportation of
methanol from overseas sources of natural gas.
Considerable interest has also been evidenced in the production of
methanol from coal. As discussed in Section V herein, the crude gas
obtained from coal gasification is rich in carbon monoxide, carbon
dioxide and hydrogen. This crude synthesis gas could be converted into
methanol. In this case, the coal gasification process offers a number
of opportunities to improve the thermal efficiency of the methanol
synthesis. Therefore, methanol produced from coal may be more attractive
than methanol produced from natural gas --at least from the viewpoint
of basic energy conservation.
ADDITIONAL READING
Anon. Outlook Bright for Methyl-Fuel. Environmental Science and
Technology _7:11 1002-1003, November 1973.
Duhl, R. W., and T. 0. Wentworth. Methyl Fuel from Remote Gas Sources.
llth Annual Technical Meeting, Southern California AIChE, Los Angeles,
Calif., April 1974.
Dutkiewicz, B. Methanol Competitive With LNG on Long Haul. Oil and
Gas Journal 7±:18 166-178, April 1973.
93
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Killer, H., and F. Marschner. Lurgi Makes Low-Pressure Methanol.
Hydrocarbon Processing 49:9 281-285, September 1970.
Quartulli, 0. J., W. Turner, and R. Towers. Which Route to Bulk
Methanol. Petroleum and Petrochemical International, July-August-
September 1973 (3 parts).
Royal, M. J., N. M. Nimmo. Big Methanol Plants Offer Cheaper LNG
Alternatives. Oil and Gas Journal 71:6 52-55, February 1973.
Soedjanto, P., and F. W. Schaffert. Transporting Gas - LNG vs
Methanol. Oil and Gas Journal 71:24 88-92, June 1973.
94
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SECTION X
NATURAL GAS PIPELINES
Natural gas pipeline systems include many facilities other than the
pipe through which the gas is transported. An overall system begins
with the wellhead and gas treating facilities at the producing wells,
and includes the compressor stations which move the treated gas through
a pipeline network to the end-use market.
TYPICAL GAS PIPELINE SYSTEM
Figure 8 is a schematic flow diagram for a complete gas pipeline system.
It includes three basic functional components:
— The Wellhead Facilities;
The raw gas from a group of gas wells is piped to nearby wellhead
separator stations which separate and remove water and associated
oil from the gas.
— The Field Gas Treating Plant;
The gas from a number of wellhead separator stations is then gathered
and piped to a nearby field gas treating plant. As discussed earlier
in this report (see Section II), the gas treating plant removes C02
and H~S from the raw natural gas. In almost all cases, the H^S will
be converted to by-product sulfur.
The gas treating plant also dries the gas to meet pipeline trans-
mission dewpoint specifications. (Although not shown in Figure 8,
the treating plant would remove and recover by-product natural gas
liquids (NGL) if they were present in sufficient quantities to make
their recovery economically attractive). Finally, the treating plant
provides treated gas for the local fuel needs of the field facilities.
— The Gas Pipeline and Compressor Stations;
The treated natural gas then enters the pipeline transmission system
for transport to market terminals. Large compressors are stationed
along the pipeline (perhaps 100-200 miles apart) and are used to move
the gas through the line.
95
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WELLHEAD FACILITIES
WELLHEAD
SEPARATOR
STATION
<£>
Water
WELLHEAD
SEPARATOR
STATION
V Gas
Water
Oil
Gas gathering line
FIELD
GAS
TREATING
PLANT
Oil
Gas
I
Oil gathering line
1
fuel
-^ Stack gases
-^- By-product Sulfur
(if any)
to market
I
I
|
COMPRESSOR
STATION
-J >
COMPRESSOR
STATION
Figure 8
Process Flow Diagram
GAS PIPELINE SYSTEM
-------
Two types of compressors are used in pipelines. The oldest type is
the reciprocating-piston compressor using a gas-fired engine as the
motive driver. The more recent type is the centrifugal compressor using
a gas-fired turbine as the motive driver. The gas-turbine centrifugals
are rapidly gaining in popularity, although reciprocating units are
still being used.
The purpose of discussing an overall -system in Figure 8 is to emphasize
that a pipeline project may include much more than the pipe through
which the treated gas moves. All pipeline projects, however, will not
necessarily include all of the components shown in Figure 8. Some wells
do not produce associated oil, and some raw gases may not contain much
CO- or H?S or significant amounts of NGL. Some projects may only
involve additions to an existing system, or new lateral transmission
lines to some additional market terminals. In other words, some projects
may include only minimal field facilities while others may not include
such facilities at all.
GAS TRANSMISSION PIPELINE COSTS
Tables 11 and 12 present some detailed statistics and cost data regarding
gas pipelines. In brief, current costs for the pipe itself have been
estimated to average about $6,800 per mile per inch of pipe diameter.
Thus, a 1,000 mile pipeline of 36-inch diameter would currently cost
about $245,000,000. This includes rights-of-way, materials and labor
for a line installed on land. It does not include such unusual conditions
as may be encountered by an Arctic pipeline.
The cost of undersea lines installed offshore might be 3 to 6 times as
much as a pipeline on land.
The current cost of compressor stations (including land, buildings,
materials and labor) has been estimated to average about $305 per horse-
power for centrifugal compressors and about $565 per horsepower for
reciprocating compressors.
97
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TABLE HE — GAS PIPELINE COSTS - ENGLISH UNITS
Basis: (a) Costs based on 1969 completions.
(b) All lines are on land (no offshore lines).
(c) Lines include main transmission pipelines as well as
lateral distribution lines.
(d) Costs include rights-of-way, materials, labor and
other costs.
(e) Costs do not include compressor stations, field
gas gathering systems, or field gas treating plants.
(f) Costs do not include unusual conditions (such as for
Arctic pipelines).
Line Diameter Cost per mile Cost per Inch-Mile
(inches) ($) ($/inch-mile)
6
8
10
12
16
20
24
30
36
42
36,000
41,000
50,200
60,000
78,400
101,800
171,840
175,200
216,720
267,540
Range (1969 completions)
Average
Average
(1969 completions)
(1974 completions) '
6,000
5,125
5,020
5,000
4,900
5,090
7,160
5,840
6,020
6,370
5,000 - 7,160
5,650
6,780
(1) Based on 20% inflation during 5 year period of 1969-1974
-------
TABLE 11M — GAS PIPELINE COSTS- METRIC UNITS
Basis: (a) Costs based on 1969 completions
(b) All lines are on land (no offshore lines)
(c) Lines include main transmission pipelines as well as
lateral distribution lines
(d) Costs include rights-of way, materials, labor and
other costs
(e) Costs do not include compressor stations, field gas
gathering systems, or field gas treating plants
(f) Costs do not include unusual conditions (such as
for Arctic pipelines)
Line Diameter
(cm)
15.2
20.3
25.4
30.5
40.6
50.8
61.0
76.2
91.4
Cost per km
($)
22,370
25,480
31,200
37,290
48,730
63,270
106,800
108,890
134,690
106.7 166,280
Range (1969 completions)
Average (1969
Average (1974
completions )
completions ) '
Cost per cm/km
( $/cm/km )
1,470
1,255
1,230
1,225
1,200
1,245
1,750
1,430
1,475
1,560
1,200 - 1,750
1,385
1,660
(1) Based on 20% inflation during 5 year period of 1969-1974
99
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TABLE 12M — SOME GAS PIPELINE STATISTICS - ENGLISH UNITS
9 3 (1 )
1 — Total daily gas transmission = 1.69 x 10 nm /day
2 — Total miles of pipeline:
gas transmission = 302,490 km1
field gas gathering = 94,930 knrT
3 — Total transmission compressor stations^1 '
= 1,030 stations
= 8,453 MW
= average of 8.2 MW
(2)
per station x '
= average of 1 station per 294
tan of transmission pipeline
4 — Total field gas processing compressor stations
= 725 stations
= 1,491 MW
= average of 2.1 MW per station* '
5 — New transmission compressors (completed in 1969):
Range _ Average
Centrifugal ( gas- turbine ):
KW ,,.. 746-9,321 4,937
Cost, $/KWkJ' 232-654 355
Reciprocating (gas-engine) :
KW ,_. 373-6,711 3,803
Cost, $/KWV0' 450-762 660
(1) In U.S.A. at end of 1972
(2) May be more than 1 compressor per station
(3) Cost includes land, buildings, equipment and labor
(4) Assuming 15% escalation during 5 year period of 1969-1974,
current costs would be 408 $/KW for centrifugal and 759$/KW
for reciprocating
100
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TABLE 12E — SOME GAS PIPELINE STATISTICS - METRIC UNITS
q / I \
1 — Total daily gas transmission = 63 x 10 SCFDV '
2 — Total miles of pipeline:
gas transmission = 188,000 miles
field gas gathering = 59,000 miles
3 — Total transmission compressor stations
= 1,030 stations
= 11,335,000 horsepower
= average of 11,000 horsepower
per station '
= average of 1 station per 183
miles of transmission pipeline
4 — Total field gas processing compressor stations
= 725 stations
= 2,000,000 horsepower
= average of 2,760 horsepower
(2)
per station
5 — New transmission compressors (completed in 1969):
Range Average
Centrifugal (gas-turbine drive):
Horsepower 1,000-12,500 6,620
Cost, $/HP(3) 173-488 265(4)
Reciprocating (gas-engine drive):
Horsepower 500-9,000 5,100
Cost, $/HP(3) 336-568 492(4)
(1) In U.S.A. at end of 1972
(2) May be more than 1 compressor per station
(3) Cost includes land, buildings, equipment and labor
(4) Assuming 15% escalation during 5 year period of 1969-1974,
current costs would be 305 $/HP for centrifugal and 565 $/HP
for reciprocating.
101
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Based on 1972 U.S. statistics, there is an average of one compressor
station of 11,000 horsepower per each 183 miles of gas transmission
pipeline in the country (see Table 12). Thus, the average 1,000-mile
pipeline would have about 5 or 6 compressor stations with a total horse-
power of about 60,100. Assuming centrifugal compressors were used,
these would currently cost about $18 million. Therefore, an average
1,000-mile transmission pipeline of 36-inch diameter would have a total
cost of about:
Pipeline $245,000,000
Compressors 18,000,000
$263,000,000
Costs of field gas gathering and treating are too specific and too
variable to permit any generalized cost estimates.
COMPARISON TO SNG, LNG AND METHANOL PROJECTS
At the end of 1972 (see Table 12), the U.S. had a total of 188,000 miles
of gas transmission pipelines with 11,335,000 compressor horsepower.
The network transported 63 billion cubic feet of gas per day. Relating
this to the previous sections on SNG, LNG and methanol projects:
% of 1972
Pipeline Transmission
250 MM SCFD of SNG 0.4
500 MM SCFD of LNG 0.8
25,000 tons/day of methanol 0.8
Obviously, a great many of these alternative fuel supply projects will
be required to alleviate current and projected energy shortages.
ENVIRONMENTAL FACTORS
The environmental factors relating to wellhead and field gas treating
facilities are too specific and too diverse to attempt any generalized
statements.
As for the pipeline and compressor stations, the major environmental
impacts will be those associated with land disturbances along the rights-
of-way (ROW). Land disturbance factors will vary widely, depending upon
102
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the characteristics of the area through which the pipeline is routed.
In some locations, the pipelines may require ROW fencing and access
roads, which will cause other environmental effects.
The noise levels of large compressors are very high. However, in most
instances, compressor stations are in remote, non-urban areas and
enclosed. Therefore, noise level impacts on communities should be
minimal.
Usually, compressor drivers are fueled by the clean-burning pipeline
gas. Therefore, S00 and N0__ emissions from the driver stack gases
^ X
should be low. As a good approximation for gas-turbines burning pipe-
line gas:
Per Horsepower
Fuel burned 11,000 Btu/hr
Wet Flue Gas rate 340 SCF/hr
NO emissions 0.0033 Ibs/hr
iX.
S02 emissions 0.000015 Ibs/hr
Thus, a 10,000-horsepower compressor station will result in the
following:
Fuel burned:
Btu/hr 110,000,000
SCF/hr 110,000
Wet Flue Gas, SCF/hr 3,400,000
NO emissions:
Ibs/hr 33
Ibs/MM Btu 0.3
S02 emissions:
Ibs/hr 0.15
Ibs/MM Btu 0.0014
The above data are based on a fuel gas containing about 0.5 grains
H-S/lOO SCF and on the gas-turbine using about 225% excess air
4b
Socio-economic impacts caused by construction personnel will depend
upon the size and duration of the project and the number of workers
required.
103
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O'Donnel, J. P. Pipeline Growth Remains Slow. Oil and Gas Journal
21:24 112-119, June 1973.
O'Donnell, J. P. 13th Annual Study of Pipeline Installations
and Equipment Costs. Oil and Gas Journal (>8/. 31 99-120, August 1970.
Trans-Alaska Report: Alyeska North Slope. Oil and Gas Journal
7,2:11 52-110, March 1974.
104
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SECTION XI
LIQUID FUELS FROM OIL SHALE
t,
Geologically speaking, oil shale is not a shale and it contains
virtually no oil. It is a sedimentary rock containing a solid
organic material called 'kerogen'. When heated, the kerogen yields
substantial amounts of hydrocarbon crude oil and gas — ranging
typically from 10 to 60 gallons of crude oil per ton of shale.
Aeons ago, oil shale had a beginning similar to conventional pet-
roleum crude oil, when organic matter was deposited in large and
ancient lakes. However, the oil shale deposits were not subjected
to the heat and pressure required to form petroleum. Instead, the
organic matter was transformed into the solid hydrocarbon kerogen
and locked into a marlstone matrix. The geological term for our
Western oil shale is 'kerogenous marlstone'. A typical oil shale
contains about 15 wt% kerogen and 85 wt% of carbonates, feldspars,
quartz and clays:
Kerogen content 15 wt%
Kerogen composition: wt%
Carbon 80.5
Hydrogen 10.3
Nitrogen 2.4
Sulfur 1.0
Oxygen 5.8
Mineral content 85 wt% 100.0
Carbonates 48.0
Feldspars 21.0
Quartz 15.0
Clays 13.0
Analcite and Pyrite 3.0
100.0
Oil shale is found on every continent throughout the world. Reserves
of oil shale are usually expressed in terms of the barrels of oil
contained in the shale deposits, as determined by a standard labor-
atory analysis. Over 15 nations around the world have extensive
105
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shale oil reserves, the largest of which are:
In-place Reserves
Brazil 342 billion barrels
U.S.A. 2,000 billion barrels
Zaire 103 billion barrels
In the United States, shale deposits occur in a great many states,
the most prominent being in these areas:
Colorado-Utah-Wyoming
Montana
California
Alaska
Texa s-0 kl ahoma-Ar kans a s
Eastern U.S.
From the viewpoint of reserves and recoverability, the best oil
shale deposits for development in the U.S. are the Green River
Formation deposits in Colorado, Utah and Wyoming. Of these, the
Piceance Basin deposits are considered to be of prime importance.
As shown in Figure 9, the Green River Formation encompasses about
17,000 square miles and has an in-place oil potential that has been
estimated to be at least 2,000 billion barrels. At our current
national oil consumption rate of about 18 million barrels a day,
the Green River Formation represents about a 300 year supply of
in-place oil. It has also been estimated that about 85 billion
barrels of the total in-place reserves could be recovered with today's
mining technology. Thus, about a 12 year national supply of oil could
be recovered without requiring any technological break-throughs in
mining methods. To put this in perspective, it is almost as much oil
as produced in the entire U.S. since the Civil War (1860). And we can
assume that advances in mining technology will progressively make more
of our in-place reserves recoverable, including those in the other
U.S. oil shale deposits.
Commercial shale oil production has been practiced for many years. It
began as early as 1840 in France and Scotland, and subsequently in
other countries. Through the years, most of these operations ceased
106
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Sand Wash
8as in
WYOMING
Rock
Springs
Great D'vLle 3,3sin
Naval Reserves
1 and 3
X
• Rifle
Battlement
Mesa
Grand
Mesa
Area underlain by
shale which is un-
appraised or of a
low grade
Area underlain by
shale of >10 feet
thick, which yields
25 gallons or more
oil per ton of
shale
Figure 9
OIL SHALE DISTRIBUTION
IN THE
GREEN RIVER FORMATION
-------
when petroleum crude oil became available. China and Estonia (now in
the U.S.S.R.) have the only commercial shale oil production operations
today. China produces about a 100,000 barrels a day, principally in
Manchuria. Estonia has been producing shale oil for 50 years and their
current output is perhaps 50,000 barrels a day of oil plus about
100 MM SCFD of low-Btu fuel gas. In Brazil, a semi-commercial proto-
type plant designed to produce 1,000 barrels a day of oil and over
1 MM SCFD of gas is currently in startup. For contrast, the forecasts
for near-term U.S. shale oil production in the Green River Formation
area range from 1 to 4 million barrels a day. At that rate, the
currently recoverable 85 billion barrels of oil in that area would
last from 60 to 240 years.
As a broad generality, the raw shale oil that can be extracted from
Western oil shales has the following characteristics!
Gravity, °API 18-28
, Ibs/gal 7.882-7.387
Pour point,' °F 30-90
Sulfur, wt % 0.6-0.8
Nitrogen, wt % 1.6-2.2
Distillates, vol % i
Naphtha and lighter 18-24
Diesel oil 24-17
Fuel oil 34-33
Residuum 24-26
Assuming an oil shale containing 15 wt % of kerogen (of which about
90% is recoverable hydrocarbon with a gravity of about 23°API), the
yield of raw shale oil would be 35 gallons per ton of shale. Thus,
a shale oil extraction project producing 50,000 BSD of raw shale
oil would require 60,000 tons per day of oil shale feedstock. If
the near-term U.S. shale oil production should reach 4 million
barrels a day, then the mining of oil shale feedstock might be
expected to approach 5 million tons per day.
108
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CURRENT DEVELOPMENT PROJECTS
During the last 15-20 years, the U.S. Bureau of Mines and various
oil companies have investigated many processes for extracting shale
oil from our Western oil shales. Most of these processes fall into
two categories — (1) retorting of mined shale and (2) in-situ com-
bustion (i.e. underground in-place retorting). Recently, a University
of California research team has begun a study of biochemical leach-
ing as another approach.
At this time, the most advanced retorting processes from the view-
point of testing are:
— The Oil Shale Corporation's TOSCO II process
— Union Oil Company's Steam Gas Recirculation (SGR) process
— Development Engineering Incorporated's Parahoe process
— The Lurgi-Ruhrgas process
The Institute of Gas Technology and the Bureau of Mines have other
oil shale processes in development.
Currently, the major oil shale projects actively underway include
the following:
— The ARCO Colony project is designing a 50,000 BSD shale oil plant
at Parachute Creek, Colorado using the TOSCO II process. Although
a construction contract for the plant had been awarded, inflation
has raised the plant cost estimates and resulted in shutting down
the project for the time being.
— Union Oil has tested a 3 ton/day SGR unit at Parachute Creek: and
is proceeding with a 1,500 ton/day pilot plant. Union Oil ultim-
ately plans a 50,000 BSD shale oil project.
— Standard Oil of Ohio (SOHIO) heads a 17-company consortium in
operating a $7,500,000 demonstration project in the Bureau of
Mines facility at Anvil Points, Colorado. The demonstration
project is using a 10% foot diameter Parahoe retort.
— Garret Research and Development, a subsidiary of Occidental Petr-
oleum, is testing and developing a modified in-situ process.
109
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— Superior Oil plans to test and develop a retorting process
to recover shale oil as well as nacohlite (soda ash) and
dawsonite (an aluminum-bearing mineral).
SHALE OIL PRODUCTION
An overall block flow diagram for a shale oil production project
is depicted in Figure 10. Based on above-ground retorting, the
individual steps in the project would includes
Mining — Either surface or underground mining of the oil shale
could be used. However, the Green River Formation deposits
are not particularly well suited for the various surface mining
techniques — strip mining, open pit mining, or the so-called
'glory hole' mining. In all probability, the room and pillar
method of underground mining (with access by adit, slope or
shaft tunnels) will be used in the Green River Formation
deposits.
Raw shale stockpile — Primary crushing of the mined shale will be
at the mine portal, and the coarsely crushed shale will be
conveyed to the raw shale stockpile. For a 50,000 BSD shale
oil project, involving 60,000 tons/day of mined shale, the
coarse shale stockpile will contain about 500,000 tons which
will cover about seven acres to a height of about 200 feet.
Crushing — The shale is then conveyed to the final crushers which
will produce a fine shale of less than % inch in size. Convey-
ors will carry the fine shale to storage silos containing about
15,000 tons (about a 6-hour supply).
Retorting — The retorts, or pyrolysis units, will use heat to
vaporize and remove the kerogen from the shale. Figure 11 is
a block flow diagram of the TOSCO II retorting process. As
shown in Figure 11, heat is transferred into the shale by
solid-to-solid heat exchange between the shale and hot ceramic
balls. The balls are heated in a vertical ball heater and
then fed into the retort to mix with preheated shale. The
resulting pyrolysis temperature is 900°F, which converts the
kerogen into hydrocarbon oil vapors.
110
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STORAGE
SILOS
CRUSHING
1
RAW SHALE
STOCKPILE
MINING
•Flue gas
RETORTING
UNITS
Spent shale
disposal
SHALE OIL
REFINING
By-product
Sulfur & NH-
•*- LPG
Low-sulfur
Fuel Oil
-»•- Coke
Figure 10
Process Flow Diagram
SHALE OIL PRODUCTION
-------
Raw
Shale
Water
Flue
Gas
Gas oil
Residuum
Spent shale
DRUM
MOISTURIZER
DRUM COOLER
°)
CONVEYOR BELT
Figure 11
Process Flow Diagram
TOSCO II RETORTING
-------
The ceramic balls, spent shale and oil vapors are disengaged
in a rotating screen (or 'trommel') within the retort. The
spent shale is cooled, moisturized and conveyed to disposal.
The balls are returned to the ball heater by a vertical-lift
ball elevator. The oil vapors are fractionated and separated
into the crude products of gas, naphtha, gas oil and residuum
oil. Foul water, condensed in the fractionation, is sent to
a stripper for removal of H2S and ammonia. The stripped water
is then used to moisturize the spent shale.
Shale oil refining — The raw hydrocarbon products from the retorts
will be upgraded in conventional oil refining units. These will
include:
— Gas recovery and acid gas removal
— Synthesis of hydrogen for catalytic desulfurizers
— Naphtha desulfurizing and gas oil desulfurizing
— Coking to convert residuum oil into additional naphtha
and gas oil
— Strippers to remove H«S and ammonia from sour waters
— Sulfur recovery and ammonia recovery
The sales products (see Figure 10) will be LPG, low-sulfur fuel
oil, petroleum coke, and by-product sulfur and ammonia. The
project's internal fuel needs will be supplied by by-product
fuel gas, butanes and some fuel oil.
Auxiliary services — These will include a boiler plant to generate
steam, a closed-loop evaporative cooling tower, water treatment,
and other systems. In addition, about 85 MW of purchased elect-
rical power will be needed during normal operation.
This description of a shale oil production plant
is based on a specific design and process at a
specific site and it is not universally applic-
able. It is intended merely to illustrate the
processes involved.
OVERALL PROJECT MATERIAL BALANCE
The overall material balance for a complete shale oil production
113
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project, such as is described above, can be summarized as follows:
Tons/day (1) BSD wt %
INPUT:
Raw shale 66,000
OUTPUTS :
C LPG 385 4,330 0.6
Low-sulfur fuel oil 7,200 47,000 10.9
Petroleum coke 800 - 1.2
By-product sulfur 157 - 0.2
By-product ammonia _ 135 - 0 . £
Total sales products 8,677
Spent shale (2) 53,743 - 81.5
C00 vent stack(3) 355 - 0.5
( 41
Shale dust emissions'1 ' 10 - negl.
Water of retorting*5 ^ 900 - 1.4
Project fuel(6) 2,315 - 3.5
Total products 66,000 100.0
(1) Short tons (2) Excludes moisturizing water
(3) Only the carbon portion of the hydrogen plant C02 vent
(4) From vent stacks in the retorting units
(5) Water formed chemically during retorting of the shale
(6) 4,060 x 106 Btu/hr of fuel with a heating value of 21,025 Btu/lb.
Equivalent to 15,700 BSD of a typical fuel oil with a heating
value of 6.2 x 10 Btu per barrel.
This balance does not include combustion air for heaters and boilers,
and the resultant stack gases. Nor does it include water usage and
disposition.
OVERALL THERMAL EFFICIENCY
The total hydrocarbons obtained from the shale (the sales products
plus the project fuel) amount to 10,992 tons/day as seen above.
Assuming an average heating value of about 20,000 Btu/lb, the total
hydrocarbons in the shale therefore contain 440 x 10 Btu/day of
heating value .
114
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Since the project consumes 97.5 x 109 Btu/day of fuel, the apparent
thermal efficiency is 77.8% : .^ , n ..,
Tons/day 10^ Btu/day
Fuel gas 1,023 45.5
Fuel oil 832 32.5
Butanes 460 19.5
2,315 97.5
The use of 85 MW of purchased elctricity requires the burning of
g
20 x 10 Btu/day of fuel for power generation. If this is included
in the energy balance, the thermal efficiency is reduced to 73.3%.
OVERALL SULFUR BALANCE
The overall sulfur balance for the shale oil project will be:
Tons/day Actual form
INPUT: as Sulfur present
Sulfur in raw shale ' 528 sulfur compounds
OUTPUTS:
Sulfur in LPG product neglig. -
(2)
Sulfur in fuel oil product 36 organic sulfur
Sulfur in coke product 4 organic sulfur
By-product sulfur 157 sulfur
(4)
Sulfur in spent shalex ' 323 sulfur compounds
SO,., emissions from burning
project fuel 7.6 S02
SO2 emissions from sulfur
recovery tail gas 0.4 SO2
528
(1) Based on 0.8 wt % sulfur in the raw shale
(2) Based on 0.5 wt % sulfur in the low-sulfur fuel oil
(3) Based on 0.5 wt % sulfur in the coke
(4) Based on 0.6 wt % sulfur in the spent shale
(5) Based on 14 mol wt. fuel gas with 10 grains H2S per 100 SCF,
project fuel oil with 0.8 wt % sulfur, and butanes with 0.1 wt %
sulfur. The quantities of gas, oil and butanes are as seen above.
The tail gas sulfur emission is about 0.25% of the sulfur fed to the
recovery units. In other words, the sulfur recovery units are about
99.75% efficient.
115
-------
STACK GASES
Table 13 is an itemized listing of the plant stacks with the quantity
and composition of their stack gas effluents. The tabulation does
not include the emergency flare stack, nor does it include other
miscellaneous vents.
The total emissions of S00, N(D and particulates, during normal
Z. .X
operations, are summarized belows
Tons/day
S02 16.0
NO 12.2
X *
Particulates 13.0
The SO- emissions are based on the overall sulfur balance and on
the project fuel consumption in combustion units (heaters, boilers,
etc.). It was assumed that each combustion unit will use its pro-
rata share of gas, butanes and oil based on each combustion unit's
heat release. The overall emission of SO- from fuel combustion
(15.2 tons/day) amounts to 0.31 lbs/MM Btu of heat release. This
is well within the EPA's New Source Performance Standards (NSPS)
for fuel burning —which are 1.2 and 0-8 lbs/MM Btu for coal and
oil burning, respectively.
The estimated NO emissions (12.2 tons/day) are based on achieving
-fv
0.25 Ibs NO^MM Btu, or less. This is consistent with the EPA's
NSPS for fuel burning — which are 0.2 and 0.3 lbs/MM Btu for gas
and oil, respectively.
The estimated particulates emissions from combustion (4.9 tons/day)
amount to 0.1 Ibs of particulates/MM Btu. The EPA's NSPS for any
fossil fuel is 0.1 lbs/MM Btu, and it was assumed that this stand-
ard could be met.
The particulates emissions from the spent shale moisturizer (3.1
tons/day), and from the crushing and conveying systems (5.0 tons/day)
U6
-------
TABLE 13E — STACK GASES FROM SHALE OIL PRODUCTION- ENGLISH UNITS
Project Fuel
Heat Release
Total Stack Gases
Tons/day of Emissions
MM Btu/day
Retorting flue gas:
Ball heater 58,900
Ball circulation 4,400
Refining heaters 30,800
Boilers 3,400
97,500
Sulfur recovery tail gas
Spent shale moisturizer -
Crushing and conveying -
CO 2 vent
MM SCFD
1,561^
322^
33g(2),
37(2)
40
144
907
92
Tons/day
57,660
11,890
12,520
1,370
1,700
3,570
34,700
2,900
°F
130
140
500
500
100
200
60
200
SO0
9.2
0.7
4.8
0.5
15.2<3>
0.8(3>
nil
nil
(45 wt%
16.0
NO..
7.3
0.6
3.9
0.4
12.2(4)
nil
nil
nil
C02> 55 w
12.2
Partic.
3.0
0.2
1.5
0.2
4.9(5)
nil
3.1
5.0
t% H?0)
13.0
(1) From venturi wet scrubbers.
(2) Based on 11,000 SCF of wet flue gas per 106 Btu of fuel heat release.
(3)Equivalent to 7.6 tons/day of elemental sulfur from fuel burning and 0.4 tons/day of
elemental sulfur from tail gas (as shown in overall sulfur balance).
(4) Based on achieving 0.25 Ibs NO^MM Btu of heat release. EPA standards are 0.2 and 0.3
Ibs NO^/MM Btu for firing gas and oil, respectively.
(5) Based on achieving 0.1 Ibs particulates/MM Btu of heat release. EPA standard is 0.1
Ibs/MM Btu for any fossil fuel.
(6) Dust collection system stacks at primary crusher, final crusher and shale fines
storage silos.
-------
TABLE 13M — STACK GASES FROM SHALE OIL PRODUCTION - METRIC UNITS
Project Fuel
Total Stack Gases
Mg/day of Emissions
oo
Retorting flue gas:
Ball heater
Ball circulation
Refining heaters
Boilers
Sulfur recovery tail gas
Spent shale moisturizer
Crushing and conveying
CO - vent
Heat Keiease
Gcal/day
14,842
1,109
7,762
857
24,570
_
_
-
-
Mnm /day
41. S^1^
8.6^
9.1(2)
1.0^
1.1
3.9
24.3
2.5
Mg/day*
52,309
10,787
11,358
1,243
1,542
3,239
31,480
2,631
°C
54
60
260
260
38
93
16
93
SO^
8.3
0.6
4.4
0.5
13.8
0.7^)
nil
nil
(45 wt%
14.5
NO ,
6.6
0.5
3.5
0.4
11.0(4)
nil
nil
nil
C02, 55 i
11.0
Partic.
2.7
0.2
1.4
0.2
4.5<5>
nil
2.8
4.5
*rt% H20)
11.8
(1) From venturi wet scrubbers
3
(2) Based on 1,169 nm of wet flue gas per Gcal of fuel heat release.
(3) Equivalent to 6.9 metric tons/day of elemental sulfur from fuel burning and 0.36 metric
tons/day of elemental sulfur from tail gas.
(4) Based on achieving 0.45 kg NO /Gcal of heat release. EPA standards are 0.36 and 0.54
kg NO /Gcal for firing gas and oil, respectively.
(5) Based on achieving 0.18 kg particulates/Gcal of heat release. EPA standard is 0.18
kg/Gcal for any fossil fuel.
(6) Dust collection system stacks at primary crusher, final crusher and shale fines
storage silos.
* Mg/day is equivalent to metric tons/day
-------
amount to 0.3 and 0.08 grains of particulates/SCF respectively.
These are consistent with the control systems used for removal
of dust particles in those services — wet scrubbers for the
moisturizer vent, and baghouses for the crushing and conveying.
The control of N0x emissions to the levels discussed above (0.25
Ibs/MM Btu) will require special combustion design features such
as two-stage combustion, low usage of excess air, flue gas recirc-
ulation, and perhaps preferential use of fuel gas and butanes in
certain services (rather than fuel oil).
OVERALL WATER BALANCE
The total project, including mining and spent shale disposal, will
require 5,475 gpm of water. As shown in Table 14, the total fresh
water requirement will be 4,970 gpm (about 8,000 acre-ft-year).
Almost all of the water supplied to the project will eventually
return to the atmosphere. As seen in Table 14, 71.4% returns direct-
ly to the atmosphere as evaporation, and from vents and stacks.
Another 25.9%, for_ revegetation and shale moisturizing, will event-
ually return to the atmosphere either directly or indirectly.
There will be no direct discharge of wastewaters to any natural
waterway. Practically all of the effluent wastes from the project,
after stripping for removal of H2S and NH3 and treatment for oil
removal, are disposed of with the spent shale. Whether or not this
will eventually contaminate underground aquifers, nearby streams,
or surface run-off will depend upon a broad range of complex factors
such ass
— Whether the spent shale is disposed of by backfilling the mine,
or by placement in a surface embankment. At least one of the
major projects, under study at this time, is currently planning
to use surface disposal.
119
-------
TABLE 14 ~ WATER REQUIREMENTS AND DISPOSITION
WATER REQUIREMENTS
Fresh water:
Dust suppression
Revegetation
Boilers, cooling tower, utility
Shale moisturizing makeup
Total fresh water
Other water:
Natural shale surface water
Water of retorting
Water of combustion
Total water required
WATER DISPOSITION
Return to atmosphere :
Dust suppression (evaporation)
Cooling tower (evaporation)
(4)
Hydrogen unit C02 vent '
Flare steam, misc. vents and losses
Retorting flue gas stacks
Shale moisturizing stacks
Total return
Revegetation
Spent shale moisture
Sanitary effluent
Total disposition
gpm
1,025
70
3,055
820
/ 9 ^
4,970^'
75
150
280
5,475
825
1,000
445
475
660
500
3,905
70
1,350(5>
150
5,475
m3/hr
233
16
693
186
1,128
17
34
64
1,243
187
227
101
108
150
114
887
16
306
34
1,243
_%_
18.7
1.3
55.8
15.0
90.8
1.4
2.7
5.1
100.0
15.1
18.3
8.1
8.7
12.1
9.1
71.4
1.3
24.6
2.7
100.0
(1) For mining, crushing and spent shale disposal.
(2) Equivalent to 8,000 acre-ft/year, or 11.1 cubic ft/sec.
(3) Water formed chemically during retorting of shale, and from fuel
burned in ball heater and ball circulation system.
(4) 267 gpm of water'vapor, plus 178 gpm of steam used to produce
CO2 and hydrogen.
(5) The difference between 1,350 gpm for spent shale moisture and
820 gpm of shale moisturizing makeup is supplied by use of stripped
sour water and other treated recycled effluent waters.
120
-------
— The topography of the selected disposal site, as well as the
sub-surface geology and hydrology.
— The permeability of the spent shale surface embankment, as well
as the leaching characteristics of the spent shale.
— The structural integrity, erosion potential and liquefaction
potential of the spent shale embankment.
— The degree to which revegetation of the embankment surface can be
achieved.
— The feasibility of catchment dams to collect and divert surface
run-off around the embankment.
— The amount of rainfall and snowmelt at the selected disposal site,
as well as the balance between precipitation and natural surface
evaporation.
— The drainage systems that might be designed for the disposal
embankment.
It would be beyond the scope of this report to attempt any quantitative
estimate of the pollution potential from the spent shale disposal.
However, it is a serious point of concern and one which will require
a great deal of study for each specific project site,
SPENT SHALE DISPOSAL
The amount of spent shale for disposal from the specific design
discussed herein will be about 53,750 tons/day. When moisturized with
12% water, the spent shale sent to disposal will be about 61,000 tons/day.
Over a 20-year period, this will amount to about 450 million tons. It
has been estimated that disposal of that amount of spent shale would
require about 800 acres covered to an average depth of 350 feet.
The disposal of spent shale is probably the major environmental factor
involved in a shale oil production project. The amount of land required
for the disposal site, the revegetation and reclamation of that land,
and the potential for water pollution from the spent shale embankment
are major problems that must be recognized and effectively dealt with.
121
-------
OTHER WASTES
Shale Dust — Shale dust from the retorting units, in the form of a
wet sludge from the vent stack venturi scrubbers, will amount to
about 950 tons/day. This has been included in the estimated
53,750 tons/day of spent shale for disposal. An additional
425 tons/day of raw shale dust from the dust collection systems
(at the crushers and the shale storage silos) will be sent to the
spent shale disposal site.
Catalysts — Spent catalysts in the various shale oil refining units
must be replaced with fresh catalysts at intervals varying from
1 to 5 years. The maximum amount of spent catalyst involved is
about 850 tons/year on an annualized basis — which is a relatively
insignificant tonnage compared to the 22 million tons/year of
moisturized spent shale. These spent catalysts will be sent to
the spent shale embankment.
About 535 tons/year (of the 850 tons/year total) will be a material
used to remove arsenic from the shale oil naphtha and gas oil.
This material will contain about 107 tons/year of arsenic, of
which about 29 ppm will be water-soluble. As a result, perhaps
6.2 pounds per year of water-soluble arsenic could potentially be
leached from the spent shale embankment. However, the spent shale
itself contains perhaps 0.11 ppm of water-soluble arsenic, which
would amount to 4,840 pounds per year in the 22 million tons/year
of moisturized spent shale. Thus, although the spent catalyst
will contribute relatively very little potential arsenic leachate,
the overall arsenic leachate potential must be carefully investi-
gated .
Filter media — About 215 tons per year of diatomaceous earth and
215 tons per year of spent activated carbon will be discharged
from filters used in amine systems for gas treating. These
materials will probably be sent to the spent shale embankment.
Coke — The 800 tons/day of coke produced in the shale oil project
will either be sold as fuel, or sent to the spent shale embankment.
122
-------
Spent Caustic — About 2 tons/day of spent sulfidic caustic will be
disposed of in the spent shale.
Sludges — Sludges from fresh water clarification and demineralization,
oily water API separators, and sanitary sewage treatment will all
be sent to the spent shale embankment.
In summary, these materials might all be sent to the spent shale
disposal sites
Tons/day Tons/year
Spent shale (dry) 53,750 19,619,000
Spent shale moisture'X' 7,300 2,665,000
Raw shale dust 425 155,000
Spent catalysts - 850
Filter media - 430
Coke^ 800 292,000
Spent caustic 2 730
Water treating sludges ? ?
(1) Stripped sour water, boiler blowdown, cooling tower blowdown,
treated wastewater, demineralizer rinse waters, etc.
(2) Will be sold as fuel, if possible.
OTHER ENVIRONMENTAL FACTORS
The mining of 21,700,000 tons per year of oil shale (66,000 tons per
day for about 328 days per year) is a very major operation. The
disposal of some 22,500,000 tons per year of spent shale and other
solid wastes is an equally large operation. Although it is beyond
the scope of this report to do other than quantify these operations,
it should be emphasized that they will cause major environmental
concerns and they must be carefully dealt with.
The air emission and water balance factors have been discussed and
quantified. Other environmental factors are relatively minor by
comparison, but are briefly discussed in the following sub-sections.
123
-------
In-plant noise will be a distinct problem, but not an insurmountable
one. The mining arid crushing operations, in particular, may require
administrative controls in addition to engineering design controls.
A limit of 60-70 dBA at the plant property line should be realistically
attainable.
A number of storage tanks will be required for plant products and
intermediates, as well as for chemicals, catalysts and water supply.
These may total to about 1,500,000 barrels of storage.
A large emergency flare system will be needed. When flaring at
maximum emergency conditions, the flame will be quite high and very
noisy. However, this condition should occur only rarely. Under
normal conditions, the amount of flaring should be rather nominal and
it can be designed to be smokeless.
The plant will probably require access roads, a railroad spur, and
a 20 to 30-inch water supply pipeline. These might require a total of
300-350 acres in addition to the land required for mining, processing
and spent shale disposal.
The plant and mine will require an operating staff of about 800-1,000
people. The peak construction staff will number perhaps 2,000 and the
total construction period may be 3-4 years. These operating and
construction personnel will create a number of housing and other socio-
economic impacts, some of which will be permanent and others will be
relatively temporary.
OTHER PROCESS CONFIGURATIONS
The project described herein is based on the TOSCO II retorting system.
As discussed earlier herein, there are at least three other retorting
systems that might be used. As an additional variable, underground
in-situ combustion might be used. These other options, if selected,
124
-------
might significantly change the emission and disposal factors presented
in this section.
The degree to which the shale oil is refined could also vary quite
widely from project to project. Again, this could significantly
change the emission and disposal factors.
The recovery of hacohlite (sodium bicarbonate) and dawsonite (an
aluminum-bearing mineral) along with shale oil would undoubtedly change
the emission and disposal factors presented in this section.
ADDITIONAL READING
Anon. What's Shale Oil's Real Potential. Hydrocarbon Processing
,53:7 13, July 1974.
Anon. Union Claims Boost in Shale-Oil Technology. Oil and Gas
Journal 7_2:24 26-27, June 1974.
Colony Development Operation. An Environmental Impact Analysis for
a Shale Oil Complex at Parachute Creek. Colorado. Vol. I, Part 1,
Atlantic Richfield Company, Denver, 1974.
Colorado State University. Water Pollution Potential of Spent Oil Shale
Residues. Grant No. 14030 EDB, U. S. Environmental Protection Agency,
December 1971.
Federal Council for Science and Technology. Extraction of Energy
Fuels, Chapter III -- Development of Oil Shale. NTIS Publication
PB-220 328, U. S. Dept. of Commerce, Sept. 1972. (Also, Bureau of
Mines Open File Report 30-73.)
Pfeffer, F. M. Pollutional Problems and Research Needs for an Oil
Shale Industry. U. S. Environmental Protection Agency, EPA-660/2-74-067,
June 1974.
125
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Pforzheimer, H. Paraho--New Prospects for Oil Shale. Chemical
Engineering Progress 70:9 62-69, September 1974.
Stanford Research Institute. Evaluation and Development of an
Environmentally Acceptable Oil Shale Industry. Technical Proposal to
U.S. Environmental Protection Agency (SRI No. ORU-74-20), May 1974.
Weichman, B. E. Oil Shale, Coal, and the Energy Crisis. Chemical
Engineering Progress 69:5 94-95, May 1973.
Weichman, B. E. Energy and Environmental Impact from the Development
of Oil Shale and Associated Minerals. AIChE Manuscript 4272, 1972.
West, J. Drive Finally Building in U.S. to Develop Oil Shale. Oil
and Gas Journal 72^:8. 15-19, February 1974.
126
-------
SECTION XII
COAL LIQUEFACTION
As discussed in an earlier section herein, coal can be gasified to
produce a clean, sulfur-free gas essentially of the same quality as
natural gas. The gasification of coal also produces some by-product
liquid fuels, amounting to 15-20% of the total fuel values produced.
As an alternative to gasification, coal may be converted, either by
pyrolysis or by dissolution in a solvent, into a range of fuels.
These include clean gas, low-sulfur fuel oils or synthetic crude oil,
solid char, and solvent refined coal. All of the pyrolysis and
dissolution processes are broadly referred to as 'coal liquefaction1
— although that is somewhat of a misnomer since the end products
include gas and solid fuels as well as liquid fuels.
Pyrolysis involves heating the coal at pressures of about 10 psig
to strip out the volatile hydrocarbons, and then catalytically
hydrotreating the hydrocarbon liquids to desulfurize them. Relatively
large amounts of gas and solid char are produced along with the
hydrocarbon liquids. Some of the gas or the char can be converted to
supply the hydrogen needed for hydrotreating the liquid products.
Alternatively, the char can be gasified to produce additional fuel
gas product. The heat required for the pyrolysis processes may be
obtained by burning some of the pyrolysis char with either oxygen or
air.
The dissolution processes actually dissolve coal in a hydrogenated
solvent oil at temperatures of 750-850 F and pressures of 150 to
2,500 psig. The end products (after removal and recovery of the
solvent oil) include gas, oil, and char or a coking feedstock. In
one case, a solid fuel is produced (solvent refined coal). The dis-
solution processes can be sub-classified into three categories:
1 — Those which do not use a catalyst or a hydrogen gas supply
in the dissolution reaction.
127
-------
2 — Those which do not use a catalyst, but which do use a
hydrogen gas supply in the dissolution reaction.
3 — Those which use both catalyst and a hydrogen gas supply
in the dissolution reaction.
Table 15 lists most of the coal liquefaction processes currently
in development in the U.S. There are three pyrolysis processes
included in Table 15. Although the pyrolysis itself does not util-
ize either catalyst or hydrogen, the subsequent hydrotreating of
the product oil does require a hydrogen supply.
The six dissolution processes in Table 15 are sub-classified (see
above discussion) as to their usage of catalyst or hydrogen in the
dissolution reaction. As shown in Table 15, all of the non-catalytic
dissolution processes will require a subsequent hydrotreater for
their oil products. The hydrotreating desulfurizes the oil and also
provides a hydrogenated solvent oil. On the other hand, the catalytic
processes, which require hydrogen gas for the dissolution reaction,
do not need the subsequent hydrotreating of product oils. The hydrogen
environment in the catalytic dissolution simultaneously causes the
product oils to be hydrogenated.
In any event, all of the processes (pyrolysis and dissolution) need
a hydrogen supply for one purpose or another. The hydrogen may be
supplied by an external source, by conversion of some product gas,
or by gasification of product char. In some cases, the coke produced
from the product coking feedstock may be subsequently gasified to
provide a hydrogen supply.
Table 16 presents a brief summary of the developmental status of
the various coal liquefaction processes. None of the processes has
yet been fully developed. Unless their funding and development are
dramatically accelerated, it will probably be 4-6 years before any
of these programs result in a large commercial plant.
128
-------
TABLE 15 — COAL LIQUEFACTION PROCESSES
DISSOLUTION
REQUIRES t
CATALYTIC
DEVELOPER
Pyrolysis Processes:
FMC Corp.
Garrett Res. & Dev.
The Oil Shale. Corp.
Dissolution Processes:
Consolidation Coal Co.
Exxon Res. & Eng.
Pittsburgh and Midway
Mining Co. (PAMCO)
Hydrocarbon Research
(HRI)
Bureau of Mines
Gulf Res. & Dev.
PROCESS NAME
COED (Char Oil
Energy Development)
Coal Pyrolysis
TOSCO AL
CSF (Consol
Synthetic Fuel)
Exxon Process
SRC (Solvent
Refined Coal)
H-Coal
Synthoil
CCL (Catalytic
Coal Liquids)
FUEL PRODUCTS
Gas, oil and
chard)
Gas, oil and
chard)
Gas, oil and
chard)
(2)
Gas and oilv '
(2)
Gas and oilv '
Gas, oil and
refined coal
Gas, oil and
coker feed (4)
Gas, oil and
coker feed (4)
Gas, oil and
co leer feed(4)
CATALYST
N/A
N/A
N/A
No
No
No
Yes
Yes
Yes
H2
N/A
N/A
N/A
NO
NO
Yes
Yes
Yes
Yes
n. i ufuj a. .tvon j. .OJA
FOR OIL
Yes
Yes
Yes
Yes
Yes
Yes
No
No
No
(1) Char most probably gasified to supply low-Btu fuel gas
(2) Produces char which will most probably be converted to supply hydrogen for hydrotreater
(3) The technical literature indicates this process to be similar to CSF process
(4) The product coke might possibly be converted to supply hydrogen to dissolution reactor
-------
TABLE 16 — DEVELOPMENTAL STATUS OF COAL LIQUEFACTION
PROCESS
COED
Garrett
TOSCOAL
CSF
Exxon
PAMCO SRC
H-Coal
Synthoil
Gulf CCL
STATUS
12 years of development by the FMC Corporation and the U.S. Office of
Coal Research. A 36 ton/day pilot plant has operated since 1970.
5 years of development. A 3.6 ton/day pilot plant is currently in
operation.
Test runs have been made in a 25 ton/day pilot plant. Analagous exper-
ience has been obtained in 1,000 ton/day semi-works oil shale unit.
A 70 ton/day pilot plant was shut down after 40 months of testing,
with less than 20 days of onstream operation. A detailed review of
operating problems and process improvements is now underway.
No information available.
A 50 ton/day pilot plant is now under construction.
A 3 ton/day pilot plant has been operated. A 700 ton/day demonstration
unit has been proposed as the next step of development.
A % ton/day pilot plant is currently in operation. Planning is under-
way for a 5-10 ton/day pilot plant.
Development work has been done on a small 120 Ib/day unit. A 1 ton/day
pilot plant is in planning.
-------
TYPICAL PROCESS FLOW DIAGRAMS
Although some detailed designs have undoubtedly been prepared by the
coal liquefaction process developers and their engineering-contractors,
such designs are not readily available in the published literature.
The process flow diagrams discussed herein are only conceptual and
do not reflect a detailed design. However, they will serve to illus-
trate the basic process concepts.
Figure 12 is a flow diagram of a coal liquefaction plant based on the
COED process listed in Table 15. The crushed coal feedstock is first
dried with hot flue gas, and then subjected to four stages of low-
pressure (i.e. 10 psig) pyrolysis. The pyrolysis temperature ranges
from 600°F in the first stage to about 1600°F in the fourth stage.
Some of the char is burned with oxygen in the fourth stage, and the
hot gas from that stage provides heat for preceding stages. The
hydrocarbon gases from the pyrolysis stages are cooled (or scrubbed)
to produce a raw gas and a raw oil. The gas is processed for removal
of H2S and NHU, which are converted into by-product sulfur and NH^•
The resulting product is a clean, medium-Btu gas. Some of that gas
is converted to hydrogen which supplies the product oil hydrotreater.
The pyrolysis char is gasified to produce a low-Btu gas.
Figure 13 is a coal liquefaction flow diagram based on the Garrett
pyrolysis process listed in Table 15. The crushed coal feedstock is
first carbonized at llOO°F in an:entrained-bed reactor. The resulting
hydrocarbon gases and char are then separated. Part of the char is
burned in a char heater which provides a hot char recycle to supply
heat for the carbonizer. The hydrocarbon gases are cooled and scrubbed
to yield a raw gas and a raw oil. Then the gas is processed for
removal and recovery of by-product sulfur and NH.,. Some of the clean
gas product is converted to hydrogen which supplies the product oil
hydrotreater. As noted in Table 15, the product char could be
converted to produce a low-Btu gas product.
131
-------
w
Gas _ pq
i CJ
co
Coal \
~~
.-i _ . _
D Gas j.
• ^^———^BB^^^ ..i
o
Char i
flue ,. I
Oa<=! 1
Flue
Gas
D — "nvvov ^"^ROOTT^
1 — 1st ovrolvsis (600°F)
2 = 2nd pyrolysis (850°F)
3 = 3rd pyrolysis (1000°F
= 4th pyrolysis \1600WF
By-product
OUJ.ruir a, wn3
Gas GAS Medium- Btu
PROCESSING Gas
1 1
.„. " ». Vent CO
Gas OIL S ' __ __ ^
RECOVERY 0 HYDROGEN
d PLANT
Oil OT
*" 1 Hydrogen
Oil ^ HYDRO- Synthetic
!., *" TREATER Crude Oil
j-^
By-product
^ ** Sulfur
Char 3 Gas i
IjAu J-iOW JJtU
PROCESSING Gas
Char 4
Steam f
_& CHAR
w^xja^i char*^ GASIFIER (FMC's COED Process)
*
)O 4~f^3iTi JC JL U U.JL ti JL ^
.
*< Process Flow Diagram
Air
COAL LIQUEFACTION
(COED PROCESS)
-------
Crushed
Coal
ft!
*- Flue Gas
Gas
GAS COOLER
& SCRUBBER
1
fc—
^/
\
1^
Char 1 T.
1 7\ T "^
Oil
PROCESSING
HYDRO-
TREATER
By-product
*5ulfuf•& NH-
Gas
Vent CO,
Synthetic
*"Crude Oil
-*~ Product
(sold as solid fuel
or converted to low-Btu gas)
(Garrett Process)
Figure 13
Process Flow Diagram
COAL LIQUEFACTION
(GARRETT PROCESS)
-------
The TOSCOAL pyrolysis process, although not illustrated in this
section, would utilize the same basic design as shown in Figure 11
(in Section XI on shale oil production). The TOSCOAL process would
be essentially the same as the TOSCO II oil shale retorting process,
except that crushed coal would be processed rather than oil shale.
The resulting pyrolysis oils would require hydrotreating to produce
low-sulfur fuel oils or a synthetic crude oil.
Figure 14 is a coal liquefaction plant flow diagram based on the
catalytic dissolution H-Coal process listed in Table 15. The crushed
coal feedstock, is slurried with a recycle of heavy oil product,
mixed with hydrogen gas, heated to about 850°F and then reacted at
about 2,500 psig. The raw gas from the reactor is processed for
removal and recovery of by-product sulfur and NHg. The gas processing
also separates unused hydrogen for recycle to the dissolution reaction.
The raw oil from the high-pressure reactor is 'flashed' down to low-
pressure. The flashed vapors are distilled in an atmospheric pres-
sure distillation unit, and the flashed liquid is distilled under
vacuum. The distilled products are low-sulfur fuel oils, a heavy oil
recycle to the coal slurry preparation, and a residuum slurry which
can be fed to a coking plant. Figure 14 indicates an external source
of hydrogen gas for the dissolution reaction — but the coke produced
from the residuum slurry could be gasified to provide a hydrogen
supply.
These process flow descriptions typify the concepts involved in the
pyrolysis and the dissolution liquefaction processes. Flow diagrams
for the other processes listed in Table 15 are readily available
in the technical literature (see the additional reading list at the
end of this section).
OVERALL THERMAL EFFICIENCY
As best as can be determined from the available literature, the
overall thermal efficiency of the coal liquefaction processes is
about 65% — which compares rather well with the 70% thermal effic-
134
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Hydrogen
Crushed
Coal
tn
SLURRY
PREPARATION
^ Recycle Hydrogen
Gas
A
By-product
"Sulfur & NH.
GAS
PROCESSING
Sour Gas
CD
K
W
Product Gas
oil
HEATER
ffi
O
Light Oil
' Product
ATMOSPHERIC
DISTILLATION
VACUUM
DISTILLATION
mHeavy oil
' Product
Heavy Oil Recycle
Slurry to
Coking
(H-Coal Process)
Figure 14
Process Flow Diagram
COAL LIQUEFACTION
(H COAL PROCESS)
-------
iency for a Lurgi coal gasification project.
The thermal balance for a COED liquefaction plant (see Figure 12)
processing 25,000 tons/day of Illinois coal would approximate the
following:
109 Btu/day
INPUTS :
25,000 tons/day of coal ® 12,500 Btu/lb 625
3,750 ton/day of purchased oxygen 10
190 MW of purchased electrical power 46
681
OUTPUTS :
26,000 BSD of oil (§ 5.9 x 10 Btu/barrel^ '
1,330 MM SCFD of gas @ 215 Btu/SCF
(1) This assumes a total compression requirement of 56,250 HP
to cryogenically separate and provide oxygen at about
10 psig, and this amounts to 360 HP-hr per ton of oxygen.
It also assumes that the compression will require about
7488 Btu/HP-hr, which is equivalent to a thermal energy
efficiency of about 34%.
(2) This assumes that the electrical power generation will
require 10,045 Btu/KW-hr, which is equivalent to a thermal
energy efficiency of about 34%.
(3) This is equivalent to a 29 °API product oil with a heating
value of 19,000 Btu/lb.
(4) This is the total net output of the liquefaction plant
after supplying the plant fuel needs.
The overall thermal efficiency for the above COED process balance
is 64.5%, when including the energy required to produce the pur-
chased oxygen and electric power.
A similar thermal balance for a CSF liquefaction plant- (see Table
15) processing 23,360 tons per day of a Pennsylvania coal would
136
-------
109 Btu/day
approximate the following:
INPUTS:
23,360 tons/day of coal (§ 10,830 Btu/lb
3,180 tons/day of purchased oxygen ^ '
OUTPUTS:
47,600 BSD of oil <§ 6 x 106 Btu/barrel 285
Product fuel gas 75
Residuum oil 85
Plant fuel (heaters, boilers, power generation) -106
339
j
(1) This assumes a total compression requirement of 82,810 HP
to provide oxygen at 1,000-1,200 psig, which amounts to
625 HP-hr per ton of oxygen. It also assumes that the comp-
ression will require about 7488 Btu/HP-hr, which is equiv-
alent to a thermal energy efficiency of about 34%.
The overall thermal efficiency for the above CSF process balance
is 65.1%, when including the energy required to produce the pur-
chased oxygen. Electric power has been generated in-plant in
this case, rather than being purchased.
SULFUR EMISSIONS
i
Lacking a detailed design for a coal liquefaction plant, it is not
possible to quantify an overall material or sulfur balance. Nor is
it possible to quantify stack emissions or water balance. However,
generalizations and estimates can be made.
One of the major functions of a coal liquefaction plant would be
to produce clean, low-sulfur fuels from a relatively high-sulfur
coal — so we can base our estimates on such coals, we can assume
that the difference between the heating value of the feedstock
coal and of the net plant products is consumed as plant fuel, util-
ized as reaction heat, and rejected as heat loss. We can further
137
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assume that 60% of the difference is plant fuel and 40% is reaction
heat and heat loss. These assumptions make it possible to estimate an
overall sulfur balance for given sulfur contents in the coal and the
products. For example, from the COED thermal balance discussed above:
Estimated plant fuel =0.6 (625-439)
= 111.6 x 109 Btu/day (18,900 BSD)
Assuming that the Illinois coal has 3.5 wt % sulfur and the product
sulfur levels shown below, we obtain: tons/day
sulfur
INPUT: 25,000 tons/day coal (3.5 wt % S) 875
OUTPUTS:
26,000 BSD product oil (0.3 wt % S)
1,330 MM SCFD product gas (10 gr H2S/100 SCF)
18,900 BSD plant fuel oil (0.3 wt % S)
By-product sulfur (i> 99.5% recovery)
Sulfur recovery tail gas
* Total sulfur emissions =13 tons/day
As another example, from the CSF thermal balance discussed above:
Plant fuel (as given) = 106 x 109 Btu/day
= 85 x 10 Btu/day residuum (12,700 BSD)
+ 21 x 10 Btu/day gas (98 MM SCFD)
Assuming that the Pennsylvania coal has 4.0 wt % sulfur and the
product sulfur levels shown below, we obtain: . .,
tons/day
sulfur
INPUT: 23,360 tons/day coal (4.0 wt % S) 934.4
OUTPUTS:
47,600 BSD product oil (0.3 wt % S) 22.0
251 MMSCFD net product gas (10 gr H2S/100 SCF) 1.8
12,700 BSD residuum fuel oil (0.7 wt % S) 15.3 *
98 MM SCFD fuel gas (10 gr H2S/100 SCF) 0.7 *
By-product sulfur (@ 99.5% recovery) 890.1
Sulfur recovery tail gas 4.5 *
934.4
* Total sulfur emissions = 20.5 tons/day
138
-------
These estimated sulfur balances indicate that coal liquefaction
plants processing 23,000-25,000 tons/day of coal having 3.5-4.0
wt % sulfur will release 13-21 tons/day of sulfur to the atmosphere.
The equivalent S02 release would be 26-42 tons/day. These estimates
are based on having sulfur recovery units (within the liquefaction
plants) which are designed to achieve 99.5% recovery of process H~S.
£1
The resulting yield of by-product sulfur will range from 840-890
tons/day .
OTHER ENVIRONMENTAL FACTORS
As a broad generalization, all of the other environmental factors
involved in coal liquefaction would probably be of the same magnitude
as a coal gasification plant (see Section V) .
Probably the major environmental problems might center around the
mining of 25,000 tons/day of coal. However, since most of our high-
sulfur coal is in our Eastern and Mid-Western states, the coal would
probably be mined underground rather than strip-mined on the surface.
Underground mining might have less environmental impact than strip-
mining.
Although a water balance cannot be estimated without a detailed design
being available, we can assume that the coal liquefaction plants will
require a large supply of fresh water — but perhaps somewhat less
than needed by a comparable coal gasification plant.
ADDITIONAL READING
Anon. U.S. Coal-Liquefaction Use Seen 4-10 Years Away, Oil and
Journal 72:37 48, September 1974.
Bodle, W. W., and K. C. "Vyas . Clean Fuels. From Coal. Oil and
Gas Journal 72:34 73-88, August 1974.
139
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Boyd, N. F. Coal Conversion Processes Loom Big as a Source of
Hydrocarbon Fuels. Mining Engineers 26:9 34-41, September 1974.
Brunsvold, N. J., H. D. Terzian, J. A. Hamshar, and J. F. Jones.
Processing Coal to Produce Synthetic Crude Oil and a Clean Fuel Gas,
So. Calif. Section, AIChE, Los Angeles, April 1974.
Electric Power Research Institute. Evaluation of Coal Processes to
Provide Clean Fuel (Part II). Palo Alto, Calif., February 1974.
Sass, A. Garrett's Coal Pyrolysis Process. Chemical Engineering
Progress 7jO:l 72-73, January 1974.
O'Hara, J. B., S. N. Rippee, B. I. Loran, and W. J. Mindheim.
Environmental Factors in Coal Liquefaction Plant Design. Office of
Coal Research R§D Report No. 82 - Interim Report No- 3, 1974.
140
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SECTION XIII
GLOSSARY
Terminology
Definition
Acid gases
Associated gas
Cl* C2' C3' C4' etc>
Condensate, or
natural gasoline
Dry gas
Field gas plants,
gas treating plants,
gas recovery plants
Flue gas, stack gas
Heavy hydrocarbons
Heavy oils
High-Btu gas
Higher heating value,
gross heating value
Hydrocarbon
Light gasoline,
light naphtha
Light hydrocarbons,
light ends
Low-Btu gas
Lower heating value,
net heating value
H9S and C00
~ 2.
Raw natural gas occurring with crude oil
from the same well
Hydrocarbons with 1, 2, 3, 4, etc. carbon
atoms
Liquid C,-j C,-, C_, etc. derived from raw
natural gas
A gas containing primarily C- and C-, with
very little C3 or heavier hydrocarbons
Plants which process raw natural gas to
recover liquids, to remove H2S and C02, and
to remove water
Synonymous terms for the gases resulting
from the combustion of a fuel
Higher-boiling, higher-density hydrocarbons
with about 7 or more carbon atoms
Fuel oil, heavy distillate oil, heavy
furnace oil, No. 6 oil, bunker oil, resid.
Hydrocarbon mixtures of from Cj.6 to €20+ an<3
boiling from 650 to 1000+°F, derived from
crude oil
Fuel gas with higher heating value of about
1000 Btu/SCF or more
The total heat released when a fuel is burned
Chemical molecule composed of hydrogen and
carbon atoms
Liquid €5, €5, C7, CQ derived from crude
oil. About the same as condensate from raw
natural gas
Low-boiling, low-density hydrocarbons with
from 1 to 6 carbon atoms
Fuel gas with higher heating value of
350-450 Btu/SCF or less
The effective usable heat released when a
fuel is burned (after some gross heat release
is used in vaporizing the combustion product
water)
141
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Terminology
Definition
Middle distillates
Naphtha, gasoline,
full range naphtha
% excess air
% 0- in flue gas
Sour gas
Sweet gas
Thermal efficiency
Virgin naphtha,
virgin oils
Wet gas
Kerosene, diesel oil, jet fuel, light
furnace oil. Hydrocarbon mixtures of from
CIQ to C15 and boiling in the range of
350 to 6500F, derived from crude oil
A hydrocarbon liquid mixture of €5 to C^
and boiling in the range from 100 to 400Op
The percentage of Combustion air supplied
to a burning fuel, over and above that
required to combine with the fuel hydrogen
and carbon
The % of oxygen in the flue gas, as a
result of using excess combustion air
A gas containing H~S
A gas containing little or no H-S
The percentage of the total heating value
input (including fuels) to a plant that
is recovered as product and byproduct heating
value or equivalent energy
Naphtha and oils derived from atmospheric
and vacuum distillation of crude oil
A gas containing significant amounts of
C or heavier hydrocarbons
Abbreviations and Units
Definition
API
Btu
CO, C0
DFG
gpm
H2, H2
H2S
HHV
LHV
LNG
LPG
American Petroleum Institute
British thermal unit, the amount of heat
required to raise the temperature of 1 pound
of water by I°F
Carbon monoxide and carbon dioxide gases
Dry flue gas
Gallons per minute
Hydrogen and water
Hydrogen sulfide gas
Higher heating value
Lower heating value
Liquefied natural gas, mostly methane
Liquefied petroleum gases, usually 03 and C4
14.2
-------
Abbreviations and Units
Definition
MM, or 10
NGL
02, N2
ppmv
ppmw
ROW
S
SCF
SCFD
SNG
SPG
WFG
Synonymous terms for the number 1 million
(or 1,000,000)
Natural gas liquids, a collective name for
CU LPG, C. LPG, and CC-C0 condensate
J 4 DO
Oxygen and nitrogen gases
Parts per million by volume
Parts per million by weight
Right-of-way
Sulfur
A standard cubic foot of gas, measured at
atmospheric pressure and 60°F
Standard cubic feet per day
Substitute or synthetic natural gas
Substitute or synthetic pipeline gas.
Synonymous with SNG
Wet flue gas
Equivalents
1 Ib of S
1 Ib of H2S
1 Ib of S02
1 Ib of NO
•2C
1 Ib of 02
1 Ib of N2
1 Ib of H20
1 Ib of C02
1 Ib of flue gas
1 Ib of natural gas
1 gpm of water flow
1 day
1 ton
1 barrel
equals
equals
equals
equals
equals
equals
equals
equals
equals
equals
equals
equals
equals
equals
2 Ibs. of S02
11.15 SCF of H2S
5.92 SCF of SO-
8.24 SCF of NO
11.84 SCF of 0,
x
13.54 SCF of N2
21.06 SCF of H20
8.61 SCF of C02
ca. 13.07 SCF of flue gas
ca. 23.69 SCF of natural gas
500 Ibs/hr of water flow
1,440 minutes
2,000 pounds (a short ton)
42 gallons
143
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
REPORT NO.
EPA-660/2-75-011
2.
3. RECIPIENT'S ACCESSION>NO.
iTITLE AND SUBTITLE
Process and Environmental Technology for Producing
SN6 and Liquid Fuels
5. REPORT DATE
Approved 03/75
6. PERFORMING ORGANIZATION CODE
7.AUTHORIS)
Milton R. Beychok
8. PERFORMING ORGANIZATION REPORT NO
9, PERFORMING ORGANIZATION NAME AND ADDRESS
Milton R. Beychok, Consulting Engineer
17709 Oak Tree Lane
Irvine, California 92664
10. PROGRAM ELEMENT NO.
11. CONTRACT/GRANT NO.
68-03-2136
12. SPONSORING AGENCY NAME AND ADDRESS
13. TYPE OF REPORT AND PERIOD COVERED
EPA, Robert S. Kerr Environmental Research Laboratory
National Environmental Research Center
Ada, Oklahoma 74820
14. SPONSORING AGENCY CODE
15, SUPPLEMENTARY NOTES
16. ABSTRACT
This report presents the process technology and environmental factors involved in
the emerging industries for providing new supplemental energy supplies from
non-conventional sources. It includes: (1) the production of substitute natural
gas (SNG) from coal, crude oil and naphtha, (2) importing overseas gas supplies in
the form of liquefied natural gas (LNG) and as liquid methanol, (3) the regasifica-
tion of LNG, (4) the production of liquid fuels from oil shale, and (5) the
liquefaction of coal to produce clean fuels. The report also includes introductory
chapters to familiarize the reader with the technology of oil and gas processing,
heat balances, fuel combustion and stack gases, thermal efficiencies, and water
balances.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIEHS/OPEN ENDED TERMS C. COSATI Field/Group
Crude oil, Coal, Fossil fuels, Oil shale,
Methyl alcohol, Natural gas, Liquified
petroleum gas, Coal gasification,
Liquifaction» Water balance, Heat
balance, Industrial Waste
Substitute natural
Sulfur balance
Energy conversion
gas
13/02
moIS
DISTRIBUTION STATEMENT
19. SECURITY. CljASS (ThisReport)
9. SECURITY CI,ASS
Unclassified
21
. OF PAGES
20. SECURITY CLASS (Thispage)
22. PRICE
Unclassified
EpA Porm 2220-1 (9-73)
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