-------
low sulfur fuel oil, flue gas desulfurization, use of low
sulfur coal, and burning of refuse in the units.
Oil with a sulfur content no greater than 0.85% S~
(assuming 18,740 BTU/lb) would be required to meet the
emission standard. Such oil is available from Arabia and
Indonesia, at costs ranging from $11.95 to $13.20 per barrel.
($1.93 to $2.13/MM BTU). This represents an increase in
fuel costs of 2 to 22 cents/MM BTU or 0.32 to 3.52 mills/
KWH.
Flue gas desulfurization systems were evaluated for the
Cabras and Tanguisson plants. Both limestone and seawater
scrubbing systems are suitable for installation at these
plants. Capital and operating costs for the flue gas de-
sulfurization options as well as the use of low sulfur oil •
are presented in Table 1. Also included is the anticipated
increase in the average residential consumers monthly bill.
Low sulfur coal is not a viable alternative for the '
Cabras plant due to the severe derating that the units would
incur if converted. Coal is available from Australia that
could meet the SOj emission regulations? it should be con-
sidered as a possible fuel for Cabras Units 3 and 4.
-Solid,waste could be used to supplement existing fuel
supplies but will not ease the fuel requirements foa^-the
Guam power plants. A detailed study would be required,
however, to assess the practicability of such a combined
firing system on Guam.
-------
Table 1. COST COMPARISON OF THE VARIOUS ALTERNATIVES FOR MEETING S02 EMISSION REGULATIONS
Option
Capital
Annual8
Increase in
avg. monthly
bill
Change in
avg. monthly
bill
$ MM
$/KW
$ MM
mills/KWH
$
%
Present fuel
0
0
0
0
0
0
Arabian low sulfur
oil
0
0
0.22
0.32
0.32
0.6
Indonesian low
sulfur
0
0
2.23
3.20
3.20
5.6
Limestone scrubbing
(Cabras 1 and 2)
9.22
69.81
3.65
4.21
4.21
7.4
Limestone scrubbing
(Tanguisson 1 and
2)
6.24
117.81
1.96
7.02
7.02
12.3
Limestone scrubbing
(Cabras and
Tanguisson)
13.28
71.78
5.18
5.52
4.52
7.9
Seawater Scrubbing
(Cabras 1 and 2)
5,38
40.74
1.85
2.13
2.13
3.7
Seawater scrubbing
(Tanguisson 1 and
2)
3.18
59.91
1.06
3.82
3.82
6-7
a Annualized costs do not include oil cost savings resulting from the use of lower
-------
A noncontinuous emission limitation could be initiated
on Guam to avoid violations of the ambient air standards.
Such a system would require the installation of weathffr
^©recasting equipment, air quality monitors, additional
personnel, an alternate low sulfur fuel oil (0.75% S) supply
system for each plant, and 200 foot high stacks at the Piti
plant. An effective supplementary control system would
minimize violations of the ambient air standards but would
Tiot meet emission limitation regulations.
If only the Cabras unit is brought into compliance,
four alternatives are available:
1. Shut down the plant.
2. Burn low sulfur oil.
3. Install limestone scrubbers.
4. Install seawater scrubbers.
Table 2 lists the advantages and disadvantages of each
alternative plus identifies their expected impact on elec-
tricity costs. The evaluation indicates that bringing the
Cabras units into compliance with NSPS will have little
effect on the average residential electricity bill.
-------
Table 2, COMPARISON OF ALTERNATIVES FOR CONTROLLING S02 EMISSIONS FROM THE CABRAS POWER PLANT
Option
Capital
Annuallied
Change In average Monthly
electric bill
Earliest l»pl•-
mentation date
Advar|t*4**/#1 sadvantagea
* m
9
\
Chat down Cabraa plant
0
S.)«
7.66
13.4
0 aontha
1. Compliance la achieved In th«
ahortest! possible time.
I. Reliability of tha electric
ayatem with this plan la un-
acceptable after 1976.
1. A larqe capital lnveatment la
abandoned.
4. Electric rataa ara lncreaaed.
Low Mlhr oil
0
0.1]
0.J2
0.6
0-6 Montha
1. Compliance la achieved In the
ahorteat poaalble time without
shuttinq down the Cabraa plant
3. Syatem reliability la aatla-
factory.
1. A contract with GOKCO muat be
broken.
tlmton* wiiMnti*
t.ll
0.9)
1.13
3.)
30 aontha
1. Compliance la achltrtd.
2. Low-coat fuel (Arabian hlqh-
aulfur) My be used.
J. System reliability la satis-
factory.
4. Land may be reclaimed with
acrubber a lodge.
3. Compliance is not achieved for
20 months.
6. Unatabillied acrubber aludge
could affect Island ground-
water supplies* stabilized
aludqe probably would not
create ground-water contamina-
tion problems.
7. Secondary environmental Im-
pact a of Increased truck traf-
fic to carry sludge and lime-
atone would need to be e*~
plored.
0. Scrubber aludqe could cause
fugitive dust problems wlthoet
careful design.
•eavateri ocrubbera*
S.St
l#.S2)
10.15)
U.J)
24 months
1. Compliance la achieved.
2. Low cost fuel (Arabian hlgh-
aulfur) may bowsed. ¦
J. System rellapllitf la aatls-
factory.
4. Compliance is not achieved for
24 months.
5. An environmental Impact state-
ment must be prepared describ-
ing the ecological effects of
the system. Since the effect#
•re unknown at present, an ex-
tensive study Is required.
ۥ To date this system has been
usad to a United extent.
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1.0 INTRODUCTION
Pursuant to Section 111 of the Clean Air Act, the
Administrator of the U.S. Environmental Protection Agency
(EPA) promulgated standards of performance for new and
modified fossil-fuel-fired steam generators; the standards
pertain to plume opacities and emissions of particulate,
sulfur dioxide, and oxides of nitrogen. These New Source
Performance Standards (NSPS)'are applicable to each fossil-
fuel-fired steam generating unit constructed or modified
after August 1971 and having capacity of more than 63 million
Kcal (250 MM BTU) per hour heat input.
The Guam Power Authority (GPA) recently started oper-
ation of Cabras Power Plant, Unit 1. It was proposed initially
that this unit burn low-sulfur fuel oil. Because of tightened
fuel oil supplies and increasing fuel prices, however, GPA
did not procure low-sulfur fuel oil.
The U.S. Environmental Protection Agency retained
PEDCo-Environmental Specialists to evaluate the options
available to GPA for meeting the NSPS. A PEDCo team conducted
a field survey on Guam from December 9-12, 1974, and met
with representatives of the Guam Environmental Protection
Agency, the Guam Power Authority, the U.S. Navy, and the
Guam Oil Refining Company (GORCO).
-------
Four plants of the Island-Wide Power System (IWPS) were
inspected: Cabras, Piti, Tanguisson, and Inductance.
Control options were evaluated for the Piti and Tanguisson
plants, as well as the Cabras Plant, so that the analysis
cjju'Id .consider possible economies of scale (e.g. in installation
and operation of flue gas desulfurization equipment) and
possible application of system-wide controls (e.g. fuel
switching, load shifting)
Background information on Guam and the Guam Power
Authority is given briefly below.
Guam
Guam is located in the western Pacific, approximately
3700 miles from Hawaii and 6000 miles from San Francisco.
The island is about 30 miles long, and its width ranges from
4 to 6-1/2 miles. The land mass encompasses approximately
210 square miles. Guam's population numbers approximately
110,000. Guamanians account for 56 percent of the total
population, military personnel 28 percent, state-siders 7
percent, and Phillipinos 6 percent; the remainder consists
of Chinese, Japanese, Koreans, and other ethnic groups.
Following the Spanish-American War in 1898, Guam became
a U.S. possession under the administration of the U.S. Navy.
In 1950 Congress enacted the Organic Act, placing the island
under a civilian administrator, a Governor appointed_J?x the
President. The first popular election for Governor of Guam
was in November 1970.
-------
Tourism is probably the single most important factor in
the economy. Over the past several years this industry has
gfiown at a .-tremendous rate, from barely 2000 visitors «t-
1964 to more than 215,000 in 1973. Approximately 75 percent
of all visitors to Guam are classed as tourists. Most come
from Japan, approximately 72 percent; the United States
ranks second with 16 percent, followed by the trust ter-
ritory and others, with 5 and 7 percent respectively.
Various economic indicators for selected years are presented
in Table 1.1.
The Guam Power Authority (GPA)
GPA provides electrical "service to the civilian popula-
tion of Guam. In 1975 GPA will provide service to all
¦customers in Guam, including the military.
historically the electric power system on Guam has been
owned and operated by the U.S. Navy. When Guam was granted
territorial status in 1950, responsibilities for power
distribution were transferred from the Navy to the Public
Utility Agencies of Guam (PUAG). At that time the agency
had responsibility for all utility services to civilian
customers. In 1968 the Guam Power Authority was formed by
air act of the Guam Legislature. In October 1972, GPA and
the.Navy signed an agreement establishing 1975 as a 'target,
date when GPA will assume full control of operation of the
Island-Wide Power System.
-------
Civilian and military power requirements have increased
approximately 82 percent, from 83.5 megawatts in 1967 to
152.1 megawatts in 1973. This increase represents an average
growth rate of 10.5 percent per year. In 4 years electrical
power requirements doubled from 181 million kilowar.r-nrynrs
irv-^l £6-9 - to 361 million kilowatt-hours in 1973. The number
of civilian customers served in 1973 was 19,942, an increase
from 12,885 in 1969.
-------
2.0 ISLAND-WIDE POWER SYSTEM
The Guam Power Authority is a government-owned system
providing electricity to all of Guam's service areas. The
United States Navy owns and operates some of the production
and transmission facilities, which are used jointly for the
supply of electric power to Department of Defense installa-
tions and to GPA for resale to their customers.
In October 1973 GPA and the Navy entered into a power
pool agreement, which provides for the operation by each of
their respective production and transmission facilities to
meet power requirements of the Island-Wide Power System
(IWPS). The agreement calls for full control of IWPS operation
by the Guam Power Authority by late 1975.
The IWPS generating units and power generation require-
ments are discussed in the following sections.
2.1 PHYSICAL PLANT FACILITIES
2.1.1 Cabras Steam Plant
The Cabras Steam plant is located on Cabras Island near
¦•¦he western shore of Guam and adjacent to the site of the
Pit! Steam plant. Only Unit 1 (66 MW) is presently operating
having become operational in September 1974. When the plant
is completely operational, four identical boilers, rated at
66 MW each, will provide a total plant capacity of 264 MW.
-------
Unit 2 will be operational in May 1975, Unit 3 in 1977, and
Unit 4 in 1978. The Cabras plant will then be the largest
generating station on Guam and will provide most of the
iJcland's Dower-generating capacity. Cabras is owned and
operated by the Guam Power Authority and is part of the
Island-Wide Power System. The boilers for Units 1 and .2,
manufactured by Babcock and Wilcox Company, are designed to
burn oil. Each boiler will exhaust through a separate
stack. Height of the stack for Unit 1 is 200 feet; Unit 2
will have a 400-foot stack. Stack heights for Units 3 and 4
are not known.
A completed survey form giving detailed operations and
emissions data of the Cabras plant is presented in Appendix
A.
2.1.2 Piti Steam Plant
The Piti Steam plant is located on the western shore of
Guam near Cabras Island. The plant is owned and operated by
the Navy and is part of the Island-Wide Power System. The
Piti plant now provides the largest installed capacity on
tfie island, with five units giving a total generating
capacity of 79.5 megawatts.
The five boiler/turbine generating units at the Piti
piant-were manufactured by Combustion Engineering and were
designed to burn oil only. Units 1 and 2 were placed^in
operation in 1951, Unit 3 in 1953, Unit 4 in 1964, and Unit
5 in 1965. Capacities of units 1, 2, and 3 are rated at
-------
11.5 MW each; Units 4 and 5 are rated at 22.5 MW each.
Although turbine 1 has been decommissioned, Boiler 1 ramains
in_ooeration supplying steam to Turbines 2 and 3. Eaci*-
bG&Ier exhausts through a separate stack. Stacks for
Boilers 1, 2, and 3 are 88 feet 8 inches high; stacks for
Boilers 4 and 5 are 75 feet 7 inches high.
A completed plant survey form of the Piti plant is
presented in Appendix B.
2.1.3 Tanguisson Steam Plant
T.he Tanguisson plant is located on the western shore of
Guam, near Tumon Bay below Two Lover's Leap. Guam Power
Authority is the owner of Unit 2 and operator of the entire
plant. The Navy owns Unit 1. The plant consists of two
base-loaded, Combustion Engineering boilers, rated at 26.5
MW each and designed tp burn oil. Total plant capacity is
53 MW. Unit 1 was installed in 1971 and Unit 2 in 1972.
Each unit exhausts through a separate 131-foot stack.
A completed plant survey form of the Tanguisson plant
is presented in Appendix C.
2.1.4 Inductance Power Barge
The Inductance Power Barge is located off the western
shore -of Guam at Polaris Point in outer Apra Harbor. The
baroe is operated by the Guam Power Authority and is part of
the Island-Wide Power System. The Army owns the barge and
leases it to the Navy, which in turn leases it to GPA. The
Power Barge consists of two Babcock and Wilcox boilers,
-------
which are used for peaking purposes. Both boilers are rated
at 14 MW and are designed to burn oil. The two boilers are
Coupled to a single turbine rated at 28 MW. The barged was
k&i'ifc An 1943 and towed to the island in 1971. Each boiler
exhausts through a separate 64-foot stack.
A completed survey form of the Inductance Power Barge
is presented in Appendix D.
2.1.5 Other Power Generation
In addition to the four power plants just described,
which burn No. 6 fuel, the Navy and GPA operate diesels at
Dededo, Tamuning, Agana, Barrigada, and Orote. Details of
the ownership, size, and the number of units at the diesel
plants and the four power plants are presented in Table 2.1.
None of the power plants on Guam is equipped with
systems for continuous control of sulfur dioxide or par-
ticulate emissions. The Piti units have opacity meters for
detection of visible particulate emissions.
2.2 POWER GENERATION REQUIREMENTS AND RELIABILITY8
2.2.1 Power Generating Requirements
The combined load of the Island-Wide Power System is
expected to reach a peak demand of 162.8 MW in 1975. The
coincident demand excluding transmission losses is projected
to reach 156.8 MW in 1975. System peak demand is expected
to increase at a compound annual rate of 11.2 percent.
The energy requirement of the system is projected to be
992.4 GWHR in 1975. The forecasted compound rate of in-
a Information for this section was prepared by Foster
-------
Table 2.1 SUMMARY OF ISLAND WIDE POWER SYSTEM CHARACTERISTICS
Plant
MW
Owner
Operator
Service
Comments
Piti
1
2
3
4
5
11.5
11.5
11.5
22.5
22.5
Navy
Navy
Navy
Navy
Navy
Navy
Navy
Navy
Navy
Navy
Floating
Floating
Floating
Floating
Floating
Unit I' miolne de-
commissioned; boiler
still in Use.
Cabras
1
2
3
4
66.0
66.0
66.0
66.0
GPA
GPA
GPA
GPA
GPA
GPA
GPA
GPA
Floating
Floating
Floating
Floating
Startup May 1975
Planned January 1978
Planned July 1978
Tangulssan
1
2
26.5
26.5
Navy
GPA
GPA
GPA
Floating
Floating
Inductance
28
Army
GPA
Floating
Two boilers for one turbine
Dededo
1
2
3
4
2.5
2.5
2-5
2.5
GPA
GPA
GPA
GPA
GPA
GPA
GPA
GPA
Peaking
Peaking
Peaking
Peaking
Tamuning
1
2
3
4
2.5
2.5
2.5
2.5
GPA
GPA
GPA
GPA
GPA
GPA
GPA
GPA
Peaking
Peaking
Peaking
Peaking
Agana
1
2
3
0.6
0.6
0.6
Navy
Navy
Navy
Navy
Navy
Navy
Peaking
Peaking
Peaking
One of thg Ag\kna units
has been permanently dis-
-------
Table -2*1 (continued) SUMMARY OF ISLAND WIDE POWER SYSTEM CHARACTERISTICS
Plant
MW
Owner
Operator
Service
Coiranenrtwr
Agana
4
0.6
Navy
Navy
Peaking
5
0.6
Navy
Navy
Peaking
6
0.6
Navy
Navy
Peakinq
7
0.6
Navy
Navy
Peaking
8
0.6
Navy
Navy
Peaking
9
0.6
Navy
Navy
Peaking
10
0.5
Navy
Navy
Peaking
Barrigade
1
2.0
Navy
Navy
Peaking
Units 1 and 2 are
2
2.0
Navy
Navy
Peaking
dedicated standbys
3
2.0
Navy
Navy
Peaking
to Naval Communica-
4
2.0
Navy
Navy
Peaking
tion Center
5
2.0
Navy
Navy
Peakinq
6
2.0
Navy
Navy
Peaking
Orote
1
0.6
Navy
Navy
Peaking
2
0.6
JJavy
Navy
Peaking
3
0.6
Navy
Navy
Peaking
4
0.6
Navy
Navy
Peakinq
5
0.6
Navy
Navy
Peaking
6
0.6
Navy
Navy
Peakinq
7
0.6
Navy
Navy
Peaking
8
0.6
Navy
Navy
Peaking
9
0.6
Navy
Navy
Peakinq
10
0.6
Navy
Navy
Peaking
Notes: 1. The floating units are loaded in the following order: Cabras, Tanqu*sspn,
Piti 4 and 5r Piti 1, 2, and 3, Inductance.
-------
crease in energy requirements is 10.8 percent per year. The
system annual load factor is projected to be about 70.per-
cent.
Table 2.2 provides a breakdown of the IWP System peak
ipad" by year. Table 2.3 is a summary of the peak demand and
energy data used in the study.
2.2.2 Power Generation Reliability
In evaluating system reliability five alternatives for
supplying present and expected future load requirements were
studied. An analysis of the system reliability was made for
each of the five plans. These plans are described in the
following paragraphs:
Plan A
This plan proposes that the Cabras Plant not be oper-
ated until sometime after 1980. Units 1 and 2 would be
"mothballed" and Units 3 and 4 would not be built during the
period of the study.
All other existing diesel and steam-turbine capacity
would be maintained to meet load requirements. The total
capacity of this system would be 222 MW.
Plan B
This plan is the currently proposed expansion plan for
the system. It calls for the operation of Cabras No. 1 in
1574", "Cabras No. 2 in 1975, Cabras No. 3 in 1978, and Cabras
Ho. 4 in 1979. Each of these units is to have a rating-of
66 MW.
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Table 2.2 SUMMARY OF ISLAND-WIDE POWER SYSTEM DEMAND
UNITED STATES NAVY
GUAM POWER AUTHORITY
TOTAL
YEAR
PEAK
DEMAND
(MW)
INCREASE
(MW)
INCREASE
(*>
PEAK
DEMAND
(MW)
INCREASE
(MW)
INCREASE
m
PEAK
DEMAND
(MW)
INCREASE
(MW)
INCREASE
(«)
1970
59.4
—
41.8
101.2
—
1971
66.3
6.9
11.6
49.2
7.4
17.7
115.5
14.3
14.1
1972
72.6
6.3
9.5
56.2
7.0
14.2
128.8
13.3
11.5
1973
68.1
(4.5)
(6.2)
70.9
26.7
47.7
138.5
22.2
17.2
1974
65.0
(3.1)
(4.6)
79.8
8.9
12.8
144.8
5.8
4.2
1975
70.0
5.0
7.7
86.8
7.0
8.8
156.8
12.0
8.3
1976
75.0
5.0
7.1
94.7
7.9
9.1
169.7
12.9
8.2
1977
80.0
5.0
6.7
107.7
13.0
13.8
187.7
18.0
10.6
1978
85.0
5.0
6.2
131.3
23.6
22.0
216.3
28.6
15.2
1979
90.0
S.O
5.9
145.9
14.6
11.1
235.9
19.6
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Table 2.3 SUMMARY OF LOAD DATA
ISLAND-WIDE POWER SYSTEM
YEAR
PEAK
DEMAND
(MW)
MINIMUM
DEMAND
(MW)
ENERGY
(GWHR)
LOAD
FACTOR
(%)
1975
162.8
72.3
992.4
69.61
1976
180.5
80.1
1072.9
67.9
1977
199.7
88.6
1187.5
67.9
1978
230.1
102.1
1369.0
67.9
1979
251.9
111.8
1497.5
67.9
1980
280.9
124.7
1659.7
67.4
In addition, retirements of 44 MW, 28 MW, and 10 MW are
scheduled for 1975, 1978 and 1979 respectively. These
retirements are to be concurrent with the Cabras units. The
retired capacity will consist of diesel units of 600 KW, 2.0
MW, and 2.5 MW, and steam-turbine capacity of 11.5, 20 and
28 MW. Two of the units to be retired are power barges.
Plan C
-This plan calls for the Cabras Unit No. 1 to be placed
on."cold stand-by" until 1977. Cabras Unit No. 2, which is
rearing completion, is to be placed on "cold stand-by"
status until 1978.
-------
The existing capacity is to be retained in service and
used to serve existing and future loads.
The timing, as will be discussed in more detail later,
IFs based on the maintaining of a system which is no less
reliable than the one presented in Plan B.
This plan is predicated on the assumption that the
Cabras units could not be brought into compliance with
emission standards. It also presupposes that any plan with
less reliability than Plan B would be unacceptable.
Plan D
This plan is the same as Plan B except that the oper-
ating costs are calculated on the basis of using low-sulfur
fuel.
Plan E
This plan is based on the assumption that the Cabras
Plant can be brought into compliance with emission standards
in 1976 by purchasing low-sulfur oil. It proposes that both
Units 1 and 2 at Cabras be placed in service starting in
1976, using low-sulfur oil as a fuel. All other existing
capacity would be retained in service and used to serve
system load.
The third and fourth units at Cabras would not be
constructed until after 1980. An earlier construction of
these, units./ provided they are also in compliance, could be
scheduled if fuel prices and the differential heat rates
justify the capital expenditure;
-------
The results of the analysis of the reliability of the
alternative plans considered indicate that the operation of
tibe Cabras Plant can be delayed until 1977. At that tame
CSbras" Unit No. 1 or other suitable capacity must be placed
in service to maintain adequate reliability. Capacity must
again be added in 1978 to maintain adequate reliability.
Operation of four units at Cabras does not result in sig-
nificant improvement in system reliability.
The currently planned retirements of diesel and steam
turbine capacity must be delayed until after 1980 to main-
tain system reliability and serve load if the Cabras units
are not placed in service.
The economic analysis indicates that a significant
reduction in system fuel cost is possible if the Cabras
Units 1 and 2 can be made to meet emission standards rather
than delay operation of these units until needed to maintain
system reliability.
The reliability study is based upon a probability
analysis of the generating system for each plan. It was
made using a computer program to calculate the cumulative
probability of the availability of varying amounts of
-capacity. The calculations were made for each year of each
plan. The measure of the reliability of each plan,mas the
probability that capacity would always be greater than or
equal to the system load (positive margin).
-------
The probability of positive margin was mathematically
converted into the probable number of days each year
tAieh there would be insufficient capacity to supply t&e
load. These figures can then be totaled over the study
period to form a basis of comparison.
Results of the reliability analysis are summarized in
Table 2.4.
Table 2.4 SYSTEM RELIABILITY
Plan
Total probable days
of unserved load
over a 10-year period
A
Unacceptable
B
6.36
C
8.17
D
6.36
E
4.91
As can be seen from the above table, the reliability of
the system with only two Cabras units added in 1976 (Plan E)
is greater than the plan with four Cabras units (Plans B and
D). The greater reliability results from the fact that
there are no retirements called for in Plan E.
Plan C which calls for the operation of the first two
Cabras units in 1977 and 1978 is no less reliable than the
four unit plans except in 1980. Plans B and D are the same
±n terms of reliability. They differ only in the type of
fuel used.
-------
As a point of reference, a commonly used "yardstick" of
reliability is that a system has acceptable reliability
provided that there is not more than one day of unser~\eed
ISad in ten years.
it is possible to observe the influence of unit size on
reliability. Table 2.5 shows the percent reserve and
probable days of unserved load for different conditions.
Table 2.5 EFFECT OF CABRAS UNITS ON SYSTEM RESERVE
REQUIREMENTS AND PROBABILITY OF UNSERVED LOAD
Reserve
Probable Number of
Condition
Percentage
Days of Unserved Load
No Cabras units
36.4%
0.15
Two Cabras units
36.2
0.51
Three Cabras units
40.5
2.47
From Table 2.5 it can be seen, that maintaining approxi
inately the same reserve percentage, an increase in the
number of large units will result in decreased reliability.
If reliability is to be maintained as the unit size is
increased, then percent reserve must be increased.
-------
3.0 ATMOSPHERIC EMISSION RATES AND REGULATIONS
Chapter 13, Section A, of the Guam Air Pollution Control
Standards and Regulations limits sulfur dioxide emissions to
0.80 pound of sulfur dioxide per million BTU heat input from
any stationary combustion source. In addition, the Cabras
Unit No. 1 is subject to Federal New Source Performance
Standards (40 CFR 60), which are summarized in Table 3.1.
In addition to maximum emission rates, NSPS also specify
requirements for performance testing, stack and process
monitoring, and recordkeeping and reporting.
Guam Air Pollution Regulations do not limit mass
emissions of particulate from gas or oil-fired stationary
combustion sources. These sources are governed by visible
emission regulations (Chapter 10 of the Regulations).
Continuous discharges are limited to 20 percent opacity or
No. 1 Ringelmann. During a period of 60 minutes, discharges
may exceed 60 percent opacity or No. 3 Ringelmann for 3
minutes.
Emissions of carbon monoxide and nitrogen oxides are
limited only indirectly by ambient air quality standards."
There are no regulations limiting emission of these contaminants
from stationary sources.
-------
Table 3.1 SUMMARY OF NSPS EMISSION STANDARDS
FOR NEW AND MODIFIED STEAM GENERATORS
Item
Standard
Fuel
Opacity
20%
All
Particulate
0.18 gm/MM cal input
All
(0.10 lb/MM BTU input)
so
1.4 gm/MM cal input
Oil
4L
(0.8 lb/MM BTU input)
SO
2.2 gm/MM cal input
Coal
(1.2 lb/MM BTU input)
(A
O
KJ
Combination
NOx
0.36 gr/MM cal input®
Gas
X
(0.20 lb/MM BTU input)
NOx
0.54 gr/MM cal input®
Oil
(0.30 lb/MM BTU input
NO
1.26 gr/MM cal input®
Coalb
X
(0.70 lb/MM BTU input)
NO
X
Prorated
Combination
* Expressed as SO,.
W *
Except lignite.
-------
Emissions of sulfur dioxide from GPA power plants are
estimated to be 3.3 lb/MM BTU, more than four times the rate
allowable under both Guam EPA and Federal EPA standards.
-------
4.0 AIR QUALITY IMPACT
4.1 AIR QUALITY DATA
The present air quality monitoring system on Guam
consists of six fixed stations and several mobile stations.
The fixed sampling sites are shown in Figures 4.1 and 4.2,
with locations of the Cabras, Inductance, Piti, and Tanguisson
Power plants.
Ambient Air Quality Standards for the Territory of Guam
are presented in Table 4.1. Table 4.2 lists the days on
which the SOj air quality standards were exceeded and the
apparent source of emission. Comparison of the air quality
data and the S02 air quality standard reveals the severe
impact of Guam's power plants on the island's air quality.
The Piti Power Plant is responsible for most of the
violations of air quality standards. Episode levels occurred
at the USO facilities when westernly winds from 7 to 16
miles per hour carried flue gases from the Piti plant
toward these facilities. Westerly winds occur infrequently
(onlv about 5 percent of the time); prevailing winds are
from the east.
An ambient air sampling program was conducted by a
Naval Civil Engineering Laboratory in May 1973 to measure
-------
v^
PITI
POWER
PLANT
USO CAFE
.(PART
COMMERCIAL PORT
(HI-VOL, S02, NOx)
CABftAS'lSLAlftJ
APRA HARBOR
CABRAS
POWER
PLANT}
4
c
-------
CABLE STATION
(S02, NOx)
TANGUISSON
POWER PLANT
AMANTES POINTM
DEDEDO
Figure 4.2 Location of ambient air quality monitors
near the Tanguisson Power Plant.
-------
Table 4.1 AMBIENT AIR QUALITY STANDARDS FOR THE TERRITORY OF GU&M
Pollutant
Level not
to exceed
Time period
Sulfur oxides
60 ug/nt3
(0.02 ppm)
Annual arithmetic mean.
365 ug/m3
(0.12 ppm)
Maximum 24-hour concentration not
to be exceeded more than once per
3 (0.5 ppm)
year.
1300 yg/m
Maximum 1-hour concentration not to
be exceeded more than once per year.
650 ug/m3
(0.25 ppm)
Maximum 4-hour concentration not to
be exceeded more than once per year.
Particulate matter
3
60 ug/m
150 pg/m3
360 ug/m3
Annual geometric mean.
Maximum 24-hour concentration not to
be exceeded more than once per year.
Maximum 8-hour concentration not to
be exceeded more than once per year.
Carbon monoxide
10 milligrams/m3 (9
ppm)
Maximum 8-hour concentration not to
be exceeded more than once per year.
40 milligratns/m3 (35
ppm)
Maximum 1-hour concentration not to
be exceeded more than once per year.
Photochemical oxidants
160 ug/m3
(0.08 ppm)
Maximum 1-hour concentration not to
be exceeded more than once per year.
Hydrocarbons
160 ug/m3
(0.24 ppm)
Maximum 3-hour concentration not to
be exceeded more than once per year.
Nitrogen oxides
100 ug/n»3
(0.05 ppm)
-------
Table 4.2 EPISODE CHRONOLOGY FOR THE
TERRITORY OF GUAM (1972-1974)
.Qatie
SO,
3
yg/m
Location
Source
Sampling
tperiod,
—hours
T/20772
1095
USO
cafe
Piti
48
7/26/72
3497
USO
cafe
Piti
24
7/27/72
3215
USO
cafe
Piti
24
10/3/72
733
USO
cafe
Piti
24
10/3/72
397
USO
shed
Piti
24
10/10/72
1368
USO
shed
Piti
24
10/11/72
695
USO
shed
Piti
24
10/12/72
498
USO
Shed
Piti
24
10/28/72
681
USO
shed
Piti
24
10/28/72
830
USO
bathhouse
Piti
24
11/14/72
2775
Station 3
YFP-10
1
11/21/72
400
Proteus Point
YFP-10
24
8/13/74
1536
Santos Park
Piti
1
3/3/74
873
SRF
Inductance
24
8/14/74
1005
USO pavillion
Piti
1
8/14/74
1197
Santos Park
Piti
1
8/15/74
1058
USO pavillion
Piti
1
8/15/74
1053
USO
bathhouse
Piti
1
11/18/74
844
Cable station
Tanguissan
24
-------
the impact of the Piti Plant under the prevailing easterly
winds. The samplers were located west of the Piti Plant at
varying distances. Results of this sampling, presented in
Table 4.3, are similar to the readings taken at the US6
facilities,
Episode occurrences also have resulted from emissions
from the Inductance, the Tanguisson Power Plant, and the
now-retired YFP 10 power barge. No episode conditions
caused by the Cabras Plant have been reported.
4.2 RESULTS OF AIR QUALITY MODELING
Two studies have been conducted using mathematical
models to predict SO^ ground level concentrations resulting
from emissions from the Cabras and Piti Power plants. Both
studies, by EPA and by Naval Civil Engineering Laboratory,
used the PTMTP model from EPA's UNAMAP system. This model
does not account for such dispersion interferences as buildings,
coastal location, or uneven topographical features. Because
of this limitation the model does not simulate accurately
the conditions at the Piti Plant, where the height of the
stacks relative to height of the boiler house causes flue
gas downwash. Both studies assumed stack heights of 200
feet for the Piti Plant, whereas height of the four Piti
stacks ranges from 75 to 89 feet. It is emphasized that the
results of these modeling studies are of limited utility,
indicating only the relative impact on air quality of changing
such parametric values as stack height and emission rates
The EPA study was centered on short time intervals up
-------
Table 4.3 NCEL MEASUREMENTS OF AMBIENT SO.
NEAR THE PITI PLANT
1973
Ddte
Duration of sampling
hours
SO2 measurements, ug/m^
Site 1
Site 2
Site 3
Site 4
May 30
2
9.4
2
9.8
2
11.8
1
3278
May 31
3
41.3
2
1536
7
50.9
1
ioi9
June 1
1
3957
1
4897
1
4081
1
3265
1
4244
1
3.3
Note 1: Winds were from the prevailing easterly direction
throughout the measuring period.
Note 2: Site 1 was located about 150 feet upwind of the
plant. Sites 2, 3, and 4 were 800, 200, and 225
feet downwind of the plant.
Uote~3: "Two additional measurements made inside the plant
fence about 50 feet downwind of the stacks yielded
values of 1438 and 3904 pg/m over time intervals of
35 and 10 minutes, respectively.
-------
to 4 hours and applied the most severe meteorological conditions.
Stability Condition 1 represents an unstable condition
caused by rapid heating of the ground under clear skies,
hlrgh sun elevation, and low wind speeds resulting in turbulent
nujcina. which brings stack emissions down to ground level in
relatively high concentrations within a relatively short
distance from the stack.
The cases evaluated for the Cabras and Piti plants
include normal and maximum operating load conditions for the
time period spanning 1976 through 1978, including provision
for one Cabras unit out of service for overhaul. Operating
loads for each unit were keyed to load projections by the
Guam Power Authority and the assumed use of 0.75 percent
sulfur fuel by both plants.
Table 4.4 presents results of the EPA modeling. Data
for runs 8 and 11 indicate a future problem if the proposed
3
4-hour standard of 650 yg/m is adopted. It appears that
satisfactory air quality can be obtained through 1978 if the
Piti Plant is equipped with 200-foot stacks and the Cabras
and Piti plants burn 0.75 percent sulfur oil. Once loads
reach or exceed the projected 1978 levels, use of oil
containing 0.5 to 0.6 percent sulfur may be required to
avoid violation of the proposed 4-hour standard of 650
vg/xn3.
-------
Table 4.4 RESULTS OF EPA MODELING
3
(S02 Concentrations in ug/m )
Sue
projected
load
condition
Kaxiansa ground
level cone, from
power plant
complex
Contribution of
Piti Plant to
naxinum
condition
HMxtmir ffrpund
level t
concentra t-fwi
from Piti Plant
1
1976-1 Cabras
Unit down
319
240
241
2
1978-1 Cabras
Unit down
375
224
226
3
1976-Nornal
.315
3
124
4
1977-Hormal
465
5
80
S
1978-Hornal
462
2
131
c
1978-Hajcittua
627
311
333
7
1978-Normal
141
106
127
•
1978-Maximum
714
101
248
• a
1976-NormaI
53
7
10
10
1978-Noraal
315
122
122
11
1978-Normal
105C
133
436
* All ran* except Run 9 were Individual maxiatum results and considered
applicable to standards of up to 4 hour duration. Run 9 results are
24 hour average values.
The NCEL modeling study was directed to determining the
maximum 24 hour average concentrations of sulfur dioxide
under various load levels for the worst meteorological
conditions. Meteorological conditions experienced on Guam
on July 7, 1972, were considered as representative "worst"
conditions. Parameter values for the day are presented in
T-ahle_4,5.
-------
Table 4.5 METEOROLOGICAL CONDITIONS USED IN THE
NCEL MODELING STUDY
secmierit
rro.
Wind
direction
degrees
Wind
speed,
m/sec
Stab
class
Mixing
ht, m
Temp.
Deg K
1
270.0
2.5
5
700.0
299.0
2
260. 0
1.5
5
700.0
299. 0
3
260.0
0.5
2
700.0
298.0
4
260.0
4.0
3
700.0
302.0
5
280.0
4.0
3
700.0
302. 0
6
280.0
0.5
2
700.0
302.0
7
250.0
3.0
3
700.0
300.0
8
270.0
2.5
5
700.0
300.0
Table 4.6 presents results of the NCEL modeling. Under
no conditions were either the primary or secondary 24-hour
levels for SO2 exceeded. Even decreasing the assumed height
of the Piti stacks to 150 feet in run 4 does not project a
violation of the 24-hour standards.
Table 4.6 RESULTS OF NCEL MODELING3
(SOj Concentrations in yg/in^)
tua
Projected
load
condition
Kaxiaua ground-
level conc. from
power plant
complax
Contribution of
Piti plant to
Mxirna
condition
Maximum ground-
level
concentration
from Piti plant
1
1976-Noraal
39
12
15
2
1976- 1
Cabras unit
down
39
29
29
3
1978-1
Cabras
unit down
S3
29
29
4b
1976-Normal
41
14
18
• All results are 24-hr ivtrigt nlutt.
* 150-foot stack elevation discharge for Piti power plant vas osed
-------
It should be noted, however, that results of the modeling
of the Cabras and Piti plants do not constitute conclusive
evidence that GPA can avoid violation of ambient air standards
bj~ installing 200-foot stacks at Piti and burning 0.75^
percent.sulfur fuel. The model provides no means of representing
the approximate effects of buildings or topography around
the plants and uses only a few sets of the many meteorological
conditions over a year's time. At best, the model can
approximate only the order of magnitude of the concentration
levels expected.
The other plants.on Guam were not included in the
modeling efforts. The Power Barge Inductance is in the same
general area as the Piti and Cabras plants but would be
difficult to model because of its short stacks. The Tanguisson
Plant would be very difficult to model because of the
surrounding topography. The plant is located below a 350-
foot cliff; since the stacks are only 131 feet high, emissions
are subjected to highly variable winds caused by the easterlies
spiraling down the cliff as the wind leaves the plateau at
the top of the cliff, as illustrated in Figure 4.3.
Although more elaborate models could be applied to the
plants on Guam, they would still yield only arbitrary and
approximate simulations of true conditions.
-------
wr'""
**»¥**¦ . > 1
WIND
PLATEAU LEVEL
TANGUtSSON
PLANT
BEACH LEVEL
-------
5.0 CHARACTERISTICS OF THE GUAM FUEL OIL SUPPLY
5.1 FUEL OIL MARKET CONDITIONS
On September 16, 1974, GPA began purchasing No. 6 fuel
oil for the Island-Wide Power System from the Guam Oil
Refining Company (GORCO). GPA supplies No. 6 oil to both
Navy PWC and GPA plants. Until that date, the Navy supplied
all the fuel for Guam. The Navy still supplies the diesel
fuel for GPA and Navy PWC diesel generator units. This fuel
is procured off-island from the Caltex Petroleum Corporation.
The contract between GORCO and GPA (signed October 8,
1974) contains a clause that escalates the price charged for
No. 6 fuel oil, cent by cent, using the OPEC crude price as
a basis. On September 16, 1974, GORCO charged GPA $10.786/bbl
for No. 6 fuel oil, the same price it was charging the Navy.
At the time of the transfer, the Navy charged GPA $12.786/bbl
for oil, since the Navy prices were based on the average,
price worldwide. Since that time the OPEC price has risen
and GPA now pays GORCO $11.86/bbl for No. 6 oil. Although
GORCO is able to escalate fuel costs, it is unable to pass
through, to .the consumer increased operating costs.
GORCO stores oil for GPA at their plant and sells -oil
based on their tankage gradings. The GORCO contract permits
sale to GPA of oil with a maximum sulfur content of 3.5
-------
percent. The average fuel analysis is shown in Table 5.1
Table 5.1 AVERAGE ANALYSIS OF GPA FUEL OIL
Analysis
Composition
HHV, BTU/lb
IB,740
Sulfur, %
3.1
Ash, %
0.1
Moisture, %
0.5 maximum
Sp. gravity
0.938
GPA obtained a variance front the Guam Environmental
Protection Agency to burn oil with a sulfur content that
does not meet regulations. The variance expires on December
31, 1975, the same date on which the oil contract ends.
The close of the Vietnam War caused a reduction in the
sales at the GORCO Refinery because of decreasing military
sales. Current rate of sale is approximately 18,000 bbl/day.
Capacity of the refinery is 30/000 bbl/day. GPA is GORCO's
only customer for No. 6 oil, using approximately 5500 bbl/day.
GORCO supplies all the JP-4 military jet fuel used on the
island. The Navy is the only market for this product.
Other companies supply jet fuels to the commercial airlines.
The light ends are sold as liquined petroleum gas (LPG) to
three cooking-gas suppliers on the island. Excess light
ends are used to run turbogenerators at the GORCO facility.
At "the- present time, GORCO has no customer for the diesel
fuel it produces. Diesel fuel used on the island by GPA -and
the Navy is supplied by Caltex.
-------
5.2 AVAILABILITY OF LOW-SULFUR OIL ON THE OPEN MARKET
5.2.1 Availability
According to a survey of oil companies active -in Ear
E£st_markets, low-sulfur heavy fuel oil for Guam power
plots- is readily available at the present time in both the
spot and long-term contract markets. Easing of the markets
for petroleum fuels generally and for low-sulfur fuel oil
in particular has stemmed from a variety of factors:
1. The worldwide recession
2. The tremendous rise in oil prices at the beginning
of 1974.
3. Conservation efforts in many consuming nations.
4. Completion of the rebuilding of oil inventories
drawn down during the Arab embargo.
5. A relatively mild winter in some of the major
consuming areas, particularly in Europe.
A mail and telephone survey was conducted covering 22
oil companies domiciled in Japan and other Par East countries.
Response to queries by mail was poor. Of twelve companies
contacted by telephone, largely American oil companies, all
but one indicated willingness to supply oil on Guam.
5.2.2 Fuel Oil Cost
The price a large consumer could negotiate with a
supplier cannot be determined precisely. Low sulfur fuel
oil (0.5 percent sulfur) is available from Indonesia and the
Persian Gulf at a range of prices summarized in Table 5.2.
-------
Table 5.2 FUEL OIL COST SUMMARY
Fuel type
Sulfur
content,
% S
Oil
cost,
$/bbl
Delivery
cost,
$/bbl
To t«ki
cost,
?/bt&_
IfidonesLian No. 6 fuel
oil
0.8
12.70
0.50
13.20
Persian Gulf No. 6
fuel oil
0. 8
10.95
1.00
11.95
Persian Gulf No. 6
fuel oil
3.4
9.75
1.00
10.75
Indonesian crude oil
0.1
12.60
0.50
13.10
Present fuel cost,
GORCO
3.1
11.85
5.2.3 Contract Conditions
Although the market has eased and many oil suppliers
have uncommitted products that they desire to sell, the
suppliers are reluctant to enter into any long-term con-
tracts unless the contract provides ample protection for
significant changes in supplies and costs. Nationalization
of part or all of the crude oil production in the major
producing OPEC countries, tremendous changes in costs of
crude, including taxes, and the Arab oil embargo have
profoundly affected the international oil companies. Since
these oil companies no longer control the supply and cost of
mucn of the oil they sell, they are interested in long-term
contracts only if these contracts cover escalations—in
price, retroactive increases in price to cover retroactive
increase in cost, and losses of supply.
-------
5.3 INSTALLATION OF FUEL OIL DESULFURIZATION FACILITIES
Direct and indirect desulfurization methods can be
applied to convert low-metal Arabian crude into low-sulfur
residual fuel. In the direct method, the heavy gas from the
distillation tower and the residual fraction are treated at
the same time to remove sulfur compounds. In the indirect
process the gas, oil, and residual fractions are separated
in a vacuum distillation step, the gas oil fraction is
desulfurized, and this product is then blended with the
residual fraction to yield a low-sulfur product.
Simplified flow diagrams of the direct and indirect
fuel oil desulfurization processes are shown in Figure 5.1.
In each case the key to the process is the hydrogen treat-
ment step, in which the sulfur reacts with the hydrogen to
yield hydrogen sulfide. The hydrogen sulfide is then
processed in a conventional sulfur recovery plant by the
Claus process.
Capacities of most new desulfurization units being
built today are in the 50,000 to 60,000 bbl/day range. The
Guam Power Authority, however, uses only about 5500 bbl/day
of residual fuel oil. Plants sized to meet GPA requirements
are no longer being built.
Table 5.3 shows approximate costs of a 6000 bbl/day and
a~507CT00 bbl/day desulfurization plant. The costs are based
"on the direct desulfurization process, a low- metal Arabian
crude with 2 percent sulfur, a finished low-sulfur fuel with
-------
SUl FUR-BEARING
G.1S TO SULFUK
RECOVERY PLAN!
HYDROGEN MAKE-UP
HYDROGEN RECYCLE
HEATER
SIPARATOR
SEPARATOR
PRESSURIZED
CATALYTIC
REACTOR
DESULFUR1ZED FUEL OIL
SIMPLIFIED DIRECT DESULFURIZATION PROCESS
VACUUM GAS OIL
no ' ' rt
SDLFUR RECOVERY
ATMOSPHERIC
RESIDUE
RESIDUAL
FUEL OIL
PRODUCT
VACUUM RESIDUE (PITCH)
OTHER J
REFINERY DISTILLATE STREAMS
HEATER
SEPARATORS
BLEND
CATALYTIC
REACTOR
VACUUM
STILL
SIMPLIFIED INDIRECT DESULFURIZATION PROCESS
Figure 5.1 Desulfurization processes.
-------
Table 5.3 CAPITAL AND ANNUALIZED COSTS FOR FUEL OIL DESULFURIZATION UNITS
50,000
BPD
6,000
BPD
Capital cost
$66,000,000
$12,000,000
Annual operating cost
Labors supervision - 0.5 men/shift
9 $9.50/hr
operating - 4.0 men/shift
# $8.00/hr
0.2.1
1.63
1.27
8.17
Maintenance, 41 of capital cost
19.47
21.92
Heat, 180 N BTU/bbl, 1.97 MM BTU
35.51
35.53
Cooling, 90 M BTU/bbl, 2.6C/M gal
0.34
0.34
steam, 60 lb/bbl, 2.63/MM BTU
15.70
15.70
Power, 8-14 KW/bbl, 4.4* KWH
35.20
35.20
Boiler water, 6.5 gal/bbl, 30C/M gal
0.20
0.20
Catalyst, 27-121 bbl/lb, 1.35«/lb
5.01
5.03
Hydrogen, 600 cu ft, 1.97/MCP
118.20
118.20
Royalty, 6C/bbl
6.00
6.00
Total direct charges, cents/bbl
232.53
248.36
Fixed charges at 20% of capital cost
72.33
109.58
TotAl cost, cents/bbl
304.86
-------
0.7 percent sulfur, and the present fuel and utility costs
on Guam.
The costs of refining low-sulfur fuel on Guam are:
pwnmarized-as follows:
Plant size
bbl/day
50,000
6,000
Cost per bbl, $
3.05
3.58
Cost per MM BTU, $
0.49
0.58
Cost per KWH, mills
7.87
9.24
Because of the high price of crude, cost of low-sulfur
fuels refined on Guam will be higher than that of low-sulfur
fuels refined in an OPEC country. Costs of OPEC fuel oils
are discussed in Section 6.1.
Before the October 1973 war in the Middle East, GORCO
was planning to increase the size of the refinery from
30,000 BPD to 130,000 BPD. A 60,000-BPD fuel oil desul-
furization unit was a part of this planned expansion; the
bulk of the low-sulfur fuel was destined for t-»e Japanese
market. The project is now in suspension until tx.^ neces-
sary long-term supplies of crude oil can be assured. Since
the cost of low-sulfur fuel oil produced in a small unit is
noncompetitive on the world market, GORCO has stated that it
is .unwilling to build a small unit unless it is guaranteed a
customer. GPA has stated that it is unwilling to be tied to
a single source.
-------
6.0 ANALYSIS OF CONTINUOUS EMISSION CONTROL ALTERNATIVES
Continuous SO2 emission control alternatives include
use of low-sulfur fuel and flue gas desulfurization. Applica-
tion of these alternatives to the GPA power plants is discussed
in the following subsections.
6.1 LOW-SULFUR FUEL OIL
For management reasons involving the supply, storage,
and distribution of fuel, the continuous use of low-sulfur
fuel oil by Cabras would essentially require the use of low-
sulfur fuel oil by all of the plants. To meet the sulfur
dioxide emission regulation of 0.8 lb/MM BTU, fuel oil of
the approximate analysis shown in Table 6.1 would be required.
Table 6.1 ANALYSIS OF FUEL OIL REQUIRED TO MEET NSPS
Analysis Composition
HHV, BTU/lb 18,740
S, % 0.85
Ash, % 0.10
Specific gravity 0.938
FUei-oils of this analysis are available from ArabHr~and
-Indonesia. Table 6.2 identifies the cost of each oil and
that of GPA's present fuel.
-------
Table 6.2 COSTS OF CRUDE AND FUEL OILS
Fuel oil source
Cost parameter
Mills/KWH
differential
5/bbl
$/MM BTU
g6RCO hiqh-sulfur (present fuel)
11.85
1.91
Arabian high-sulfur
10.75
1.73
(2.88)
Arabian low-sulfur
11.95
1.93
0.32
Indonesian low-sulfur
13.20
2.13
3.52
Indonesian low-sulfur (crude)
13.10
2.11
3.20
The average residential customer on Guam uses approxi-
mately 1000 kwh of electricity per month. The average
residential rate is 5.7 cents/kwh, yielding an average
residential bill of $57 per month. The cost differentials
for use of low-sulfur fuel for the expected incremental cost
range of low vs high sulfur fuel oil and their impacts on
the residential rate are shown in Table 6.3.
Table 6.3 COST DIFFERENTIAL FOR USE OF LOW-SULFUR FUEL OILS
Cost differential (1975)
Increase
in
average
monthly
bill
$
Change
in
average
monthly
bill
$
Option
$/year
mills/KWH
Present fuel
0
0
0
0
Low sulfur fuel oil
0
0
0
0
$1". 50/bb-l incre-
mental cost
2,855,000
3.87
3.Y7
6.8
$3.50 bbl incre-
mental cost
6,661,000
9.03
9.03
15.8
-------
Crude-oil firing was also investigated. Crude oil,
however, is more expensive than the available No. 6 fuel
GOrl-r Indonesian crude is less expensive than Indonesian fuel
on, But both are significantly more expensive than Persian
Gulf fuel oil. Thus, there is no economic incentive for
burning crude oil.
6.2 FLUE GAS DESULFURIZATION
Four processes were considered for controlling S02
emissions: the Wellman-Lord, vet lime, wet limestone, and
seawater scrubbing processes. Since Guam has no significant
market for sulfur or sulfuric acid, the Wellman-.Lord process
w-as not considered beyond the preliminary evaluation of
these by-product sulfur markets. Abundant low-cost lime-
stone and lack of on-island lime production eliminated the
wet lime process from further consideration; under these
conditions wet lime scrubbing would not be competitive.
The following sections present brief process descrip-
tions, process retrofit plans, and process costs for the wet
limestone and seawater scrubbing processes. FGD system
evaluations were conducted for the Cabras Units 1 and 2, and
Tanguisson Units 1 and 2.
6.2.1 Process Descriptions
"Wet Limestone Scrubbing - The limestone scrubbing
system illustrated in Figure 6.1, utilizes a limestone
(CaC03) 6lurry as the sulfur dioxide absorbent medium. The
sulfur dioxide reacts with the limestone to form calcium
-------
-------
sulfite (CaSO^), which is removed from the system as a waste
product. Flue gases from the boiler pass through a.booster
fSn to overcome ~the pressure drop in the scrubbing-system.
Flue gases from the boiler enter an absorber tower near
the base, where quenching with water reduces the temperature
of the gases before they ascend through the absorption
section of the tower. The ascending flue gases are brought
into contact with the limestone slurry in two or three
stages for sulfur dioxide absorption. Concentrations of
solids in the slurry range from 4 to 15 percent. Sulfur
dioxide removal efficiencies are usually 85 percent or
greater.
The scrubbed flue gases pass through a demister and are
reheated prior to discharge to the atmosphere. Reheating is
required to prevent plume fumigation and to raise the gas
temperature far enough above the dew point to prevent
excessive condensation.
Limestone slurry is prepared on the site by a wet ball
milling process. The limestone system entails an open
limestone storage area, handling and conveying equipment,
live storage silos, wet ball mills, and slurry storage
tanks.
Partial recovery of water is achieved througn eoxia/
liquid separation operations. The slurry leaving the
absorber goes to the absorber circulation tank, where
hydrated CaSO^ and CaSO^ crystals precipitate. A bleed
-------
stream containing these solids is sent to a gravity clarifier,
where the crystals, fly ash, and unreacted limestone Battle.
The overflow from the clarifier and the filtrate are
teamed to the circulation tank. The underflow from the
clarifier is processed in a rotary filter to produce a
sludge with a moisture content of about 60 percent. The
sludge is treated to prevent subsequent leaching by addition
of chemicals in a mixing tank and is then trucked to a
permanent disposal site. The treated or "fixed" sludge
forms a stabilized fill material that can support vegetation
and subsequent development.
The basis for process design determines the sizing and
sparing of the equipment used in the limestone process. The
design rationale used in this study is presented in Appendix
E.
Seawater Scrubbing - The seawater scrubbing system
utilizes the natural alkalinity of seawater for absorption
of S02« The sulfur dioxide reacts with bicarbonate and
hydroxyl ions to form sulfite ions. The sulfite ions, which
may be oxidized to sulfate ions, are returned to the sea
after the scrubbing process.
As in the limestone process, flue gases from the boiler
enter the absorber tower near the base and are quenched with
water before ascending through the absorber. The sulfur
dioxide is removed in a countercurrent absorber. Sulfur
dioxide removal efficiencies, which are a function of the
-------
seawater circulation rate are normally greater than 8 5
percent. The scrubbed flue gases pass through a demistar
aad_ are reheated prior to discharge to the atmosphere t
Seawater is drawn into the plant through an inlet pipe
from the ocean. The seawater makes a single pass through
the absorber and is discharged into a water treatment
facility in the ocean. A clarifier may be installed after
the absorber to reduce suspended solid levels. If chemical
oxidation demand (COD) reduction is required, the scrubber
effluent is aerated in a pond.
Since the scrubber effluent is blended into.the con-
denser cooling water discharge, total dissolved solids
content is increased by only about 1 percent. Sludge dis-
posal, if required, will handle the.small portion of re-
action products, unburned oil, and metals in the oil.
Sludge stabilized with fixation chemicals is trucked to a
permanent disposal site.
The process design basis is presented in Appendix E.
6.2.2 Retrofit Plan
Figure 6.2 and 6.3 illustrate possible locations for
major system components for wet limestone and seawater
scrubbing as applicable to Cabras and Tanguisson plants.
The retrofit equipment layout is based on preliminary-obser-
vations at both plants and discussions with plant personnel.
A detailed engineering study would be required for design
optimization.
-------
PRE5£«T PARKING AREA
limestone stokage silos
ooo
LIMESTONE
STORAGE PILE
ball mill
AND
LIMESTONE
SLURRY AREA
FUEL OIL LINES
STACKS'
UNIT 1
UKIT ?
• THIS EQUIPMENT IS NOT REQUIRED
FOR THE SEA WATER SCRUBBING SYSTEM
Figure 6.2 Retrofit plan for flue gas desulfurization
system on Cabras Units 1 and 2.
-------
;//i
VACUUM
FILTER
AREA *'
INTAKE CANAL
J L
ROAD
LIMESTONE STORAGE SILOS*
*
V\lCLARIFIER—CD-BALL MILL AND LIMESTONE
\jl! r^^sCRUBBERS SLURRY AREA
( ^
<1
¦NEW STACKS f
UNIT 1 * SUB"
UNIT 2
jsTATIONJ
DIESEL FUEL
FUEL OIL TANKS
) ,
I!
4.
o
X>
ll
* THIS EQUIPMENT IS NOT REQUIRED
FOR THE SEA WATER SCRUBBING SYSTEM.
Figure 6.3 Retrofit plan for flue gas desulfurization
system on Tanguisson Units 1 and 2.
-------
For the Cabras plant, one scrubbing train of the re-
quired flue gas capacity would be required for each boiler
in both the limestone and seawater systems. These scrubbing
trains, together with their associated booster fans, would
be installed in the area on the northwest side of the plant.
For the limestone system, the proposed location of the
limestone storage and grinding facilities would be to the
north of the scrubbing train on Unit 1. Since this area is
now used as a parking lot, it would be necessary to relocate
that facility. The limestone slurry at 60 percent moisture
concentration would be pumped some 100 feet to the scrubbing
modules.
Spent limestone liquor from the scrubbing trains would
be pumped about 150 feet to the clarifier located northwest
of the scrubbing trains. Clarifier sludge would then be
pumped to the vacuum filtration area located about 40 feet
southwest of the clarifier. In this area would be located
the vacuum filters to dewater the sludge and fixation
equipment to stabilize the sludge before disposal. The
sludge would be trucked to an off-plant landfill disposal
site. About 70 acre-feet per year of a landfill material
would be generated.
Installation of a wet limestone scrubbing system on
both boilers at the Cabras plant would require approximately
30 months, assuming an expeditious program of design, con-
struction, and installation. Bringing the boilers off-line
-------
for tie-in of the FGD system will be of critical importance.
By proper scheduling, it may be possible either to tie-in
the FGD system or to modify ducting to facilitate future
system tie-in by only slightly extending the scheduled
annual or semiannual boiler/turbine outages.
The seawater scrubbing system would require only a
clarifier in addition to the scrubbing trains. The small
amount of sludge collected in the clarifier would be sta-
bilized and trucked to a landfill site Liquid effluent
would be diluted with plant cooling water before discharge
into the ocean.
Installation of seawater scrubbers would require
approximately 24 months, assuming an expeditious program of
design, construction, and installation. As with the lime-
stone scrubbing system, bringing the boilers off-line for
tie-in of the scrubbing system is critical and should be
scheduled during a boiler/turbine maintenance outage.
For the Tanguisson plant, one scrubbing train of the
required flue gas capacity would be required for each boiler
in both the wet limestone and seawater scrubbing systems.
These scrubbing trains, with their associated booster fans,
would.be installed northeast of the plant building. A new
stack would replace the existing stacks.
For the limestone system, two options were considered.
In the first, the Tanguisson system is self-contained and
requires limestone storage, grinding, and a slurry process
-------
area. The limestone storage silos would be located north-
east of the plant near the entrance gate. Directly between
the silos and the plant proper would be the grinding and
slurry area. The slurry would be pumped about 60 feet to
the scrubbing modules.
In the second option, facilities for limestone storage,
grinding, and slurry would be located at the Cabras plant.
Slurry would be trucked from the Cabras plant and stored in
small clay tanks at Tanguisson.
Soent limestone liquor from the scrubbing trains would
be pumped about 30 feet to the clarifier located northeast
of the scrubbing trains. Underflow from the clarifier would
be pumped to the vacuum filtration area located about 40
feet northeast of the clarifier. Vacuum filters and sludge
fixation equipment would also be located in this area. The
sludge would be trucked to an off-site landfill. The system
would generate about 21 acre-feet of stabilized landfill per
year.
Installation of a wet limestone scrubbing system on
both boilers at the Tanguisson plant would require approxi-
mately 30 months, assuming an expeditious program of design,
construction, and installation. Again, bringing the boilers
off-line for tie-in of the system would be of critical
importance.
The seawater scrubbing system in the Tanguisson plant
would require only a clarifier in addition to the scrubbing
-------
trains. The small amount of sludge collected in the clar-
ifier would be trucked to a landfill site. The treated
liquid effluent would be diluted with plant cooling water
before discharge into the ocean.
6.2.3 Cost Estimates
Cost estimates were prepared by standard engineering
procedures. Verbal quotations from vendors were obtained for
such major equipment items as pumps, storage tanks, ab-
sorbers, fans, ball mills, classifiers, vibrating feeders,
and vacuum filters. Costs are modified to include freight
rates to Guam and labor productivity on Guam.
Capital and annualized costs estimates for Tanguisson
and Cabras plants are shown in Table 6.4, which also shows
the anticipated increase in costs to the average residential
consumers.
6.3 LOW-SULFUR COAL
Low-sulfur coal that would enable the plants to meet
Guam regulations and NSPS is available from Australian mines
located in Queensland about 90 miles from the coast in the
Great Dividing Range. The average fuel analysis of the
Blair-Athol, one of the Queensland mines, is shown in Table
6.5.
-------
Table 6.4 FLUE GAS DESULFURIZATION CAPITAL AND ANNUALIZED OPERATING COSTS
Costs
Increase
in average
Plant
emission control
Capital
Annualized operating
monthly residential bill
alternative
MM §
$/KW
MM $
mills/KWH
$
1
Cobras Units 1
and 2
limestone
9.22
69.81
3.65
4.21
4.21
7.4
Cabras Units 1
and 2
seawater
5.38
40.74
1.85
2.13
2.13
3.7
Tanguisson Units
1 and 2
limestone
6.24
117.81
1.96
7.02
7.02
12.3
Tanguisson Units
1 and 2
seawater
3.18
59.91
1.06
3.82
3.82
6.7
Cabras Units 1
and 2 and
Tanguisson Units
1 and 2
limestone
13.28
71.78
5.18
4.52
4.52
-------
Table 6.5 AVERAGE ANALYSIS OF BLAIR-ATHOL COAL
Analysis
Composition
GHV, BTU/lb
Moisture, %
Ash, %
Sulfur, %
Ash fusion-liquid, °C
11,000
13.0
8.2
0.3
1,560
This coal is used as an extender for American coals in the
manufacture of coke in Japan. During the current slump in
the Japanese economy, this coal is available on Guam at a
price equivalent to approximately $6.00/BBL oil. The
Australian government, however, has proposed an export tax
on coal which would raise the price of coal and lower the
economic incentive to burn coal on Guam. The Blair-Athol
Coal Company has recently reneged on some long-term con-
tracts in which the price of coal was very low. it appears
that on a long-term basis the price of Australian coal may
equilibrate with that of OPEC oil.
The boilers for the-^Cabras plant were designed for high
thermal efficiencies in burning oil. Using coal in these
boilers would derate the units by 60 percent. Because of
this large derating and the additional cost of equipment for
coal firing, coal handling, and ash handling, it would be
uneconomical to convert the Cabras 1 and 2 Units to coal.
If the price of Australian coal could be guaranteed at
or near the $6.00/BBL oil equivalent, then serious consid-
-------
eration should be given to designing Cabras Units 3 and 4
for coal firing.
6.4 SOLID WASTE
Municipal refuse provides a viable source of energy in
some localities. Table 6.6 presents data on the quantities
of wastes generated by various segments of the Guam popula-
tion.
Table 6.6 GUAM REFUSE INVENTORY
Segment
Refuse generated
tons/year
Refuse type
Civilian
50,000 to 63,500
. General refuse
U.S. Air Force
2,700
General refuse and
military supplies
U.S. Navy
N.A.
General refuse and
military supplies
The Guam Environmental Protection Agency has estimated
that 140,000 TPY of waste were generated in 1970. If the
waste tonnage has increased with the population, the tonnage
in 1974 should be approximately 200,000 TPY.
If this quantity of refuse was collected and converted
to fuel, it would only supply enough fuel for approximately
10 MW of capacity. Although this would only partially ease
fuel requirements, it could alleviate a growing solid waste
disposal burden on the Island. Further study is required to
determine the feasibility of burning municipal refuse in GPA
or Navy boilers. These units were designed for oil firing
-------
and do not have bottom ash collection systems. Furnace
volume may be insufficient for burning significant quan-
tities of refuse to supplement existing fuel. Furthermore
the units are not equipped with particulate emission control
equipment, which would be essential if refuse was fired, in
addition to these power plant related questions, the adequacy
of the refuse collection and transfer operations for pro-
viding a relatively constant supply of refuse, would have to
be assessed.
-------
7.0 ANALYSIS OF SUPPLEMENTAL EMISSION CONTROL SYSTEMS
A supplemental control system (SCS) is designed to
enable a plant to meet air quality standards by adjusting
SO2 emission rates to reflect the continually changing
dispersive capacity of the atmosphere. The SO2 emissions
from fossil-fuel-fired electric generating plants may be
adjusted by two methods: (1) burning fuel of a lower sulfur
content and (2) reducing the generating load on a particular
plant and picking up the lost capacity at another plant in
the system (load shifting). A third alternative is load
shedding, which entails cutting power to certain consumers.
Since this obviously impairs the reliability of electrical
service, load shedding, usually is not included as a viable
alternative in SCS design.
In addition to the adjusting of emission rates, stack
heights may be increased to enhance dispersion of SOj and
reduce concentrations at ground level. Use of tall stacks
reduces the frequency of potential violations of ambient air
quality standards and hence the frequency of fuel switching
or load reduction.
If it is to be effective in maintaining ambient air
quality standards, an SCS must include all sources of sulfur
-------
dioxide. This is particularly true of the Guam power plants,
since they are the major sources of sulfur dioxide on the
island and several are in close proximity to one another.
The most effective and reliable SCS will allow some
flexibility in the methods of reducing S02 emissions. The
ideal system would include use o'f tall stacks to minimize
periods for which S02 emission reductions will be necessary
and the capability for use of various means of reducing S02
emissions. A system that provides a choice of burning low-
sulfur fuel or shifting load is more reliable than one
limited to a single method, since a situation may occur that
precludes the use of that method. This is especially true
of load shifting for the Guam power plants, since all the
plants might be required to reduce emissions during the same
period and load shifting would be ineffective.
The following sections describe a supplemental control
system for the Guam power plants. The system is based on
preliminary data for these plants and environs and does not
represent a detailed engineering evaluation. Much more
detailed meteorological data is necessary for a refined
design of a supplemental control system.
7.1 OPERATING PLAN FOR SUPPLEMENTAL CONTROL SYSTEM
Three types of SCS may be employed? (1) open loop based
on diffusion modeling, (2} closed loop, based on air quality
monitoring, (3) closed loop, based on diffusion modeling
upgraded by emissions data. Because most models do not
-------
effectively account for unusual topographic conditions, a
closed-loop system is probably the most reliable for the
Guam power plants.
The SCS should employ three complementary operations.
Each emission source would first look at meteorological
predictions, then apply a diffusion model and adjust its
emission output accordingly (e.g., switch to low-sulfur
fuels). If that adjustment were not sufficient, as in-
dicated by air quality monitoring, procedures for further
emission reduction would be activated. Records of the
emissions, measured concentrations, and meteorological
conditions would be analyzed periodically to determine
whether the prediction accuracy of the model could be im-
proved. Any improvements would then be incorporated into
the model.
The advantage of a combined closed-loop system is that
each of the loops performs a different function. The model
allows lead time for performance of control operations.
This is desirable in that time is required for switching
fuel or curtailing generation. Furthermore, the lead time
associated with the model provides valuable compensation for
the lag between emission of pollutants and registration of
their effects at the monitors. Even if all control functions
were instantaneous, this lag could result in unacceptably
high concentrations at the monitoring siteCs) for limited
time periods.
-------
The air quality loop firmly establishes the connection
between air quality and emissions from the plant. During
the initial operation of a combined system, when the operating
model is tentative and the dependency of air quality on
local meteorology is only partially known, the air quality
loop might often be the controlling one. As time goes on
and data are accumulated, it should be possible to improve
the operating model so that the air quality loop is acti-
vated less and less frequently and overall SCS operation
becomes smoother and more predictable.
One factor that would limit application of.an SCS to
the Guam plants is the short- stacks at the Piti plant. For
most of the meteorological conditions in Guam, the Piti
plant produces ground-level concentrations of SOj in excess
of the standards. Taller stacks for the Piti plant would be
a necessary part of any effective SCS applied to the Guam
plants.
The equipment, personnel, and services required to
establish a closed-loop SCS for the Guam power plants are
listed in Table 7.1.
-------
Table 7.1 EQUIPMENT AND SERVICES NEEDED IN AN SCS
FOR THE GUAM POWER PLANTS
Equipment/service
Number required and
applicability
Tall stack(s)
200 ft at Piti Plant
Emission rate monitoring
equipment
1 at each plant
Meteorological monitoring
equipment
2 sets: 1 for Tanguisson
1 for Piti, Cabras, Inductance
Air quality monitoring
equipment
13 monitors
Computer/modeling services
1
Technical/scientific
personnel
4-8 additional
Alternate fuel system
Low-sulfur oil for each plant
The emission rate monitoring equipment refers to a
precombustion sulfur analysis of the fuel on a frequent
basis and allows application of emission factors to predict
S02 emissions from the stacks of each plant. Alternatively,
the stacks could be equipped with continuous SOj flue gas
monitors to provide emission rates for input to the dis-
persion model.
Meteorological monitoring equipment would consist
primarily of devices to collect data for vertical wind and
temperature profiles The devices may be affixed to pilot
balloons mounted on fixed-wing aircraft. A ground-based
network may also be established to record wind direction,
-------
wind speed, and temperature gradient or atmospheric sta-
bility.
The air quality monitoring equipment would be housed in
a number of sampling stations around each source to provide
coverage of the impact areas where maximum ground-level
concentrations may occur. The monitors should be located so
that the impact may be measured under prevailing conditions,
on Guam. Available data on air quality indicate that
adequate coverage for each plant would be as follows:
1. Cabras - two monitors to the west of the plant and
one to the east.
2. Piti - three monitors to the west and two to the
east.
3. Inductance - one monitor to the east and one to
the west.
4. Tanguisson - two monitors at beach level on each
side of the plant and one mbnitor on the cliff
behind the plant.
The sampling stations should be equipped with logging
devices that provide machine-readable data to facilitate
data handling and interpretation. Telemetry for real-time
recording of the network data at a central station may be
desirable.
Computer and modeling services will be required to
implement the SCS. The computer will analyze the data
collected by the air monitoring equipment and will use these
values and current meteorological data to update the dis-
persion model developed for the sources. The dispersion
model should have the capability to predict accurately any
-------
periods in which'standards might be exceeded and to identify
the plants that must switch fuels, and for what time period,
to avoid violation of the standards. Development of a
reliable model for the Guam plants may require extensive
effort because the meteorology and topography that influence
dispersion patterns are complex.
It is estimated that the personnel required to initiate
and operate the SCS are an electrical engineer, two in-
strument mechanics, a meteorologist, a pilot baloon oper-
ator, one surface vehicle operator, a mathematician (com-
puter programmer), and supporting clerical staff.
7.2 ANALYSIS OF FUEL SWITCHING POTENTIAL
All of the Guam power plants can burn low-sulfur oil
with no problems. Each must add a storage tank and lines to
handle the low-sulfur oil.
Additional storage is needed for the low-sulfur oil.
A central tank would be located at the Cabras plant with a
capacity equal to a 30-day supply of oil for all plants.
This tank would hold approximately 16,300,000 gallons. Each
of the other plants would have a tank holding a 12-day
supply of oil. The Piti plant would require a 2,100,000-
gallon tank; the Tanguisson plant a 1,200,000-gallon tank;
and the Inductance a 710,000-gallon tank.
Earlier modeling studies indicate that the low—sulfur
oil should have a sulfur content of 0.75 percent or less
assuming that 200-foot stacks are installed on the Piti
-------
plant. If not, the Piti Plant must burn fuel having 0.3
percent sulfur or less almost constantly to avoid exceeding
the standards.
More detailed meteorological data and analysis would be
necessary to determine the amount of low-sulfur oil required
annually to operate the SCS. It is probable that ambient
air standards would be exceeded at times, even with the
capability of using low-sulfur oil. More extensive and
detailed data are necessary to predict the number of days
standards would be exceeded.
7.3 ANALYSIS OF THE POTENTIAL OF LOAD SHIFTING
The location and topography of the power plants on Guam
severly limit the use of load shifting as a means of re-
ducing S02 emissions. The Cabras, Piti, and Inductance
plants are in the same general area- and adverse meteorolog-
ical conditions would affect all of these plants? therefore,
load switching among these units would not effectively
reduce ground-level concentrations. Another limiting factor
is that the Tanguisson plant is located on the same side of
the island as the other plants and probably is affected by
the same meteorological conditions. This further limits the
potential for effective shifting of loads among the Guam
power plants to prevent violation of ambient air standards.
7.4 ANALYSIS OF THE POTENTIAL FOR USE OF TALL STACKS
The purpose of a tall stack is to ensure that the plume
remains clear of turbulent regions created by obstructions
-------
around the source. Two of the Guam plants, Piti and Tan-
guisson, have stacks that are too short to allow the plumes
escape these turbulent regions.
Modeling studies conducted by NCEL for the Piti Plant
show that the 24-hour ambient S02 standards could be met by
installing two 200-foot-high stacks and burning 3.0 percent
sulfur fuel oil. Topographical effects were not included in
the model, however, and the validity of the prediction is
therefore questionable. The EPA modeling effort indicated
that short-term (4-hour) standards would be exceeded with
the 200-foot stacks unless the sulfur content of the fuel
were 0.75 percent or less. But the meteorological con-
ditions assumed for this model were the worst theoretically
possible, and it was assumed that these conditions would
persist over the 4-hour period. This would be em infrequent
occurrence, predictable by an effective SCS. Therefore any
operable SCS should include installation of 200 foot stacks
at the Piti plant. The stacks must be designed to with-
stand high-speed typhoon winds (up to 155 mph) and seismic
loading. Such conditions are within present stack tech-
nology and are economically feasible.
The Tanguisson plant presents a difficult problem. The
downwash affecting this plant results from the prevailing
winds as they leave the plateau at the level of the 350-foot
cliff above the plant and spiral down to the plant level.
Enabling the plume to escape this effect would probably
-------
require a stack height of around 750 feet. A stack of this
height would present a problem with winds from the west,
since the plume would then produce high S02 levels on the
plateau. Also, the economics of building a stack this high
with sufficient structural strength to withstand 155-mph
winds and Guam's seismic load would be prohibitive. For
these reasons, use of a fuel of lower sulfur content is the
best method by which the Tanguisson plant can avoid ex-
ceeding air quality levels. A detailed and exhaustive
analysis would be required to determine the optimum com-
bination of fuel sulfur content and stack height for Tan-
guisson.
-------
8.0 GPA PROGRAM FOR COMPLYING WITH EMISSION STANDARDS
GPA proposed to comply with the New Source Performance
Standards by burning low-sulfur fuel oil. They were twice
unable to procure such fuel oil, however, when they re-
quested bids. Furthermore, GPA is concerned with reducing
the high cost of electric power on Guam. Even if low-sulfur
fuel is available, they do not propose to burn it if it is
more costly than the fuels now used.
GPA requested bids for sale of low-sulfur fuel oil on
October 1, 1973, and July 1, 1974. They have made no other,
official requests for bids for low-sulfur fuel. A summary
of the bid invitations and their responses is presented in
Table 8.1. Only two companies responded to the first bid;
neither offered low-sulfur fuel, and both bids were refused.
On the second invitation to bid, only GORCO responded. No
bid was received in the second round for low-sulfur oil.
(Table 8.1 is incomplete, but includes all the relevant data
provided by GPA).
The first invitation to bid was for a three year
contract and the second was for a one year contract. The
bid specifications required maintenance of a supply of oil
-------
Table 8.1 SUMMARY OF GPA FUEL OIL BID RESPONSES
October 1, 1973 Bid
July 1, 1974 Bid
Sul
cur Content (I)
Comment
Sulfur Content (1)
Comment
0.54
0.80
3.25
0.80
3.25
1. Mr. K. H. Parke, Secretary
British Petroleum Co., Ltd.
Britanic House, Moor Lane
London E.C.2, United Kingdom
2. Caltex Petroleum Corp.
380 Hadison Avenue
New York, New York 10017
)> Mr. Fred Cochrane
Guam Oil fc Refinery Co., Inc.
P.O. Box 3190
Agana, Guam 96910
4. Mr. B. C. Sholton
Marketing Coordinator
Gulf Oil Corporation
Gulf Building
P.O. Box 1166
Pittsburg, Pennsylvania 15230
5. Mr. Lawrence King, Jr.
Mobil oil Corporation
Manager, Government Sales
150 E. 42nd Street
New York, New York 10017
S. Nippon Oil Company, Ltd.
3-12, 1-Chome, Nishi Shimbashi
Minator-ku, Tokyo 105, Japan
7. Mr. J. W. Sheehan, Vice President
Shell Oil Company
SO West 50th Street
New York, New York 10020
1. Standard Oil Company Of Calif.
Chevron Oil Trading Co.
555 Market Street
8an Francisco, Calif. 94105
Available
for one.
Subject
to change
3.99
Declined to
bid on low
sulfur fuel
3.5% sulfur
oil
Declined to
bid. Suggested
spot market
Declined to
bid. Asked
for 60 days
extension.
Declined to
bid
Declined to
bid
10.78
Declined to
bid
3.51 sulfur
Declined to
-------
Table 8.1 SUMMARY OF GPA FUEL OIL, BID RESPONSES (continued)
0.54
0.B0
3.25
Comment
o.ao
3.25
Coanent
t. Standard Oil Co. (New Jersey)
Esso International, Inc..
15 West 51st Street
New York, New York 10019
10. Hr. J. it. Pipkin
Executive Vice President
Texaco, Inc.
135 East 42nd Street
New York, New York 10017
11. Mr. Yoshi Akagi, Asst. Mgr.
C. Itoh i Co., Ltd.
Import Fuel Oil Section
4, 2-Chome, Mon-Cho
Kiho nbashi, Chuo-ku, Japan
12. Asiatic Petroleum Corp.
One Rockefeller Plaza
New York, New York 10020
13. Mr. Lionel Bevis
Manager, Pacific Area
Shell Oil Company
Melbourne, Victoria 3000
Australia
14 Mr. Paul Dubrule
Mobil Petroleum Co., Inc.
General Manager
P.O. Box EU
Agana, Guam 96910
IS. Daikyo Oil Company
Bridgestone Building
1-1 Kyobashi
Chuo-ku, Tokyo, Japan
$4.97
Declined to
bid
-------
Table 8.1 SUMMARY OF GPA FUEL OIL BID RESPONSES (continued)
0.54
0. SO
3.25
Comment
0.80
3.25
Comnent
16. Nippon Oil Company
4-1-Chome Taraura-Cho
Shiba, Minato-ku
Tokyo, Japan
17. Idemitsu Kosan
10, 1-Chome, Marunouchi
Chiyoda-ku, Tokyo, Japan
18. Maruzen Oil Company
1-3 Nagahoribashi-Suji
Hinami-ku, Osaka, Japan
19. Mr. B. Austin, General Mgr.
Pacific Gulf Oil
P.O. Box 43
Atasaka, Tokyo, Japan
20. Arabian Oil Company
1-6 Ohtemachi
Chiyoda-ku, Tokyo, Japan
21. Koa Oil Company
Eiraku Building
1-2 Marunouchi
Chiyoda-ku, Tokyo, Japan
22. Mr. Frank R. Power
General Manager
Aminoil, Inc.
Shin-Tokyo Building
3-1 Marunouchi, 3-Chome
Chiyoda-ku, Tokyo, Japan
23. Esso Standard Eastern, Inc.
P.O. Box 3160
Agana, Guam 96910
Declined to
-------
on Guam, 500,000 BBL in the first invitation and 185,000 BBL
in the second; this supply provision required either that
the successful bidder obtain tankage from GORCO, an unlikely
event, or construct storage tanks.
-------
9.0 ECONOMIC IMPACT OF EMISSION ON THE RESIDENTIAL CONSUMER
This section briefly analyzes the primary economic
impact, namely increased electricity costs, on the resi-
dential consumer as a result of controlling SO2 emisisons
from the Cabras plant. Secondary impacts, for example,
increased cost of goods and services due to higher elec-
tricity costs, were not analyzed.
The average (mean) residential usage is approximately
100 KWH per month. The average residential rate is 5.7
mills/KWH for an average residential bill of $57 per month.
However the median usage is less than 1000 KWH per month.
As shown by the residential amount statistics in Table 9.1,
approximately 66% of the residential consumers use less than
1000 KWH per month.
Table 9.1 RESIDENTIAL ACCOUNTS STATISTICS (1974)
KWH usage Percentage in category
0 - 500 36
501 - 1000 30
1001 - 1500 15
1501 - over 19
Thus the median consumer pays a lower monthly bill and
in absolute dollars would pay less per month for emission
-------
control expenditures than average (mean) figures would
indicate.
The four alternatives available for meeting the NSPS
emission limitations for Cabras One are:
(1) Shut Cabras 1 down
(2) Burn low sulfur fuel oil
(3) Use a limestone based flue gas desulfurization
system; and
(4) Use a seawater based flje gas desulfurization
system
The monthly electricity bill under each of these
alternatives and the difference between it and the current
bill are presented in Table 9.2 for four different monthly
consumption rates. For purposes of comparison, monthly
bills under existing conditions are also presented. It is
emphasized that these calculations are based upon average
cost pass through provisions and do not necessarily reflect
the procedures used by GPA to convert capital expenditures
and operating and maintenance costs into revenue require-
ments. Any differences in procedure, however, should have
only slight impact on the computed values.
The above analysis covers residential rates only.
Since residential consumption is only 25% of the total
consumption, commercial and governmental groups will pay a
greater percentage for compliance. Over half the load is
for Federal and military facilities. This group will pay
the most for compliance with sulfur dioxide regulations.
-------
Table 9.2 IMPACT ON THE RESIDENTIAL CONSUMER ALTERNATIVES
FOR S02 EMISSION CONTROL
250 KHH
750 KHH
Change
in
Change
in
Change
in
Change
in
Compliance option
Monthly
bill,
$
monthly
bill,
$
monthly
bill,
1
Monthly
bill,
$
monthly
bill,
$
monthly
bill,
t
Existing conditions
17.73
0.00
0.00
44.08
0.00
0.00
•hut down Cabras 1
IS. 65
1.92
10.83
49.83
5.75
13.04
Um sulfur fuel oil
Immediate switch®
17.81
0.08
0.45
44.32
0.24
0.54
Long tern impact*3
-
0.97
-
-
2.90
-
Limestone FGD system0
18.06
0.33
1.86
46.35
1.00
2.27
Seawater FGD.system0
17.54
(0.19)
(1.06)
43.52
(0.56)
(1.27)
1250 KHH
1750 KWH
Change
in
Change
in
Change
in
Change
in
Compliance option
Monthly
bill,
$
monthly
bill,
$
monthly
bill,
»
Monthly
bill,
$
monthly
bill,
$
monthly
bill,
%
existing conditions
69.93
0.00
0.00
95.78
0.00
0.00
Shut down Cabras 1
79.51
9.58
13.70
109.18
13.40
13.99
Low sulfur fuel oil
Immediate switch®
70.33
0.40
0.57
96.34
0.56
0.58
Long term impact13
-
4.84
-
-
6.77
-
Limestone FGD system0
71.59
1.66
2.37
98.11
2.33
2.43
Seawater FGD system0
68.99
(0.94)
(1.34)
94.47
(1.31)
(1.37)
* Immediate switch refers to the conversion from existing fuel oil supplies to Arabian low
sulfur oil which can be purchased at only a slight increase in cost.
^ Long term impact refers to an expected incremental cost of 51.50/barrel between low and
high sulfur oils. Actual monthly consumer bills were not calculated since this long
term differential may still result in total costs less than or equal to present costs.
c Costs include credit for using a lower priced, high sulfur fuel oil ($10.75/bbl) in con-
junction with the PCD system.
-------
Although the study scope did not permit a complete
evaluation, there were other areas which could possibly
reduce electric bills on Guam. These areas include: lower
debt coverage; lower purchase prices for Navy land and
generation facilities; lower voltage transmission lines (for
planned expansion); no fuel oil storage facilities; and
smaller generation units (for planned expansions).
-------
OMB No. 138o V 4 0 2 J
POWER PLANT SURVEY FORM
COMPANY INFORMATION:
1. COMPANY NAME: Guam Power Authority
2. MAILING ADDRESS: P.O. Box 2977, Agana, Guam 96910
3. RESPONSIBLE OFFICER: P. E. Cavote
4. POSITION: Asst. General Manager
5. PLANT NAME: Cabras
6. PLANT LOCATION: Piti-Lot 257
7. RESPONSIBLE OFFICER AT PLANT LOCATION: Lewis Knudson
8. POSITION: Plant Manager
9. POWER POOL Guam Power Pool
Island Wide Power System
DATE INFORMATION GATHERED: December 11, 1975
PARTICIPANTS IN MEETING:
Cabras Plant (GPA)
Lewis Knudson, Pit. Mgr.
Joe Chesnutt, Pit. Chemist
John Smith
Ed Yau
Geoffrey Burke
Tim Devitt
Tom Ponder
Guam Power Authority
Guam Power Authority
Guam Power Authority
U.S. Navy
Guam Environmental Protection Agency
PEDCo-Environmental Specialists, Inc
PEDCo-Environmental Specialists, Inc
Don Hendricks
-------
ATMOSPHERIC EMISSIONS
Boiler number
1
2
1
1. PARTICULATE EMISSIONS3
LB/MM BTU
0.094
0.094
GRAINS/ACF
0.039
0.039
LB/HR (FULL LOAD)
60.6 *
60.6 *
TONS/YEAR ( )
2. APPLICABLE PARTICULATE EMISSION
REGULATION
a) CURRENT REQUIREMENT
AQCR PRIORITY CLASSIFICATION
REGULATION & SECTION NO.
LB/MM BTU
0.1
0.1
b) FUTURE REQUIREMENT (DATE: )
REGULATION & SECTION NO.
LB/MM BTU
3. S02 EMISSIONS3
LB/M*; BTU
3.3
3.3
LB/HR (FULL LOAD)
2154 *
2154 *
TONS/YEAR ( )
4. APPLICABLE S02 EMISSION REGULATION
a) CURRENT REQUIREMENT
REGULATION & SECTION HO.
LB/MM BTU
0.8
0.8
b) FUTURE REQUIREMENT (DATE: )
REGULATION & SECTION NO.
LB/MM BTU
* Values calculated at nameplate rating
of 66 MW
-------
C. SITE DATA
1. U.T.M. COORDINATES
2. ELEVATION ABOVE MEAN SEA LEVEL (FT) 8-12'
3. SOIL DATA: BEARING VALUE Floating concrete mat 41 Thick.
. PILING NECESSARY
4. DRAWINGS REQUIRED
PLOT PLAN OF SITE (CONTOUR)
EQUIPMENT LAYOUT AND ELEVATION
AERIAL PHOTOGRAPHS OF SITE INCLUDING POWER PLANT,
COAL STORAGE AND ASH DISPOSAL AREA
5. HEIGHT OF TALLEST BUILDING AT PLANT SITE OR
IN CLOSE PROXIMITY TO STACK (FT. ABOVE GRADE) 99'
-------
BOILER DATA
Boiler nuinber
1
2
1. SERVICE: BASE LOAD
STANDBY, FLOATING, PEAK
Floating
Base
Floating
Base
2. TOTAL KOL'RS OPERATION (19 ) startup
8/18/74
May 1975
3. AVERAGE CAPACITY FACTOR (19 )
75%
75%
4. SERVED BY STACK NO.
1
2
5. BOILER MANUFACTURER
B&W
B&W
6. YEAR BOILER PLACED IN SERVICE
1974
1975
7. REMAINING LIFE OF UNIT
30
30
8. GENERATING CAPACITY (MW)
RATED (Nampplate)
66 MW
66 MW
MAXIMUM CONTINUOUS
66 MW
66 MW
PEAK
72 MW
72 MW
9. FUEL CONSUMPTION:
OIL RATED
(GPH) MAXIMUM CONTINUOUS
4370
4370
PEAK
10. ACTUAL FUEL CONSUMPTION
CCAL (TPY) (19 )
OIL (1975 ) BBLS
534,446
105.079
11. WET OR DRY BOTTOM
N. A.
N.A.
12. FLY ASH REINJECTION (YES OR NO)
N.A.
N.A.
13. STACK KG? ABOVE GRADE
200
200'
14 - I.D. OF STACK AT TOP
6.5'
6.5'
-------
15.
FLUE GAS CLEANING EQUIPMENT
a) MECHANICAL COLLECTORS
MANUFACTURER
Boiler nurnber
NO
CONTROL
EQUIPMENT
NO
CONTROL
EQUIPMENT
TYPE
EFFICIENCY: DESIGN/ACTUAL (%)
MASS EMISSION RATE
(GR/ACF)
(#/HR)
(S/MM BTU)
b) ELECTROSTATIC PRECIPITATOR
MANUFACTURER
TYPE
EFFICIENCY: DESIGN/ACTUAL (%) a)
MASS EMISSION RATE
(GR/ACF)
(5/HR)
(S/>!M BTU)
NO. OF IND. BUS SECTIONS
TOTAL PLATE AREA (FT )
FLUE GAS TEMPERATURE
@ INLET ESP § 100% LOAD (°F)
16. EXCESS AIR: DESIGN/ACTUAL (%)
10
10
i) ESP desioned for «per cent sulfur coal
-------
Boiler number
17-
FLUE GAS RATE (ACFM)*
SCFM
§ 100% LOAD g 70°F, 14.7 psla
121,000
121,000
@ 75% LOAD
@ 50% LOAD
18. STACK GAS EXIT TEMPERATURE (°F)a
@ 100% LOAD
334
9 75% LOAD
327
334
327
@ 50% LOAD
310
310
19.
EXIT GAS STACK VELOCITY (FPS)a
0 100% LOAD
N.A.
N. A,
@ 75% LOAD
@ 50% LOAD
20. FLY ASH: TOTAL COLLECTED (TONS/YEAR)
DISPOSAL METHOD
N.A.
N. A.
DISPOSAL COST ($/TON)
21.
BOTTOM ASH: TOTAL COLLECTED(TONS/
DISPOSAL METHOD YEAR)
N.A.
DISPOSAL COST ($/TON)
N.A.
22. EXHAUST DUCT DIMENSIONS 3 STACK 11' x 7
23. ELEVATION OF TIE IN POINT TO STACK 5 3.6'
11' x 7'
53.6'
24. SCHEDULED MAINTENAMCE SHUTDOWN
(ATTACH PROJECTED SCHEDULE)
a) Identify source of values (test or estimate)
-------
E. F.P. FAN DATA
1. MAXIMUM STATIC HEAD (IN
2~. WORKING STATIC HEAD (IN
Notes: * at maximum load
>
i
Boiler nurabe
r
1
2
W.G. )
W.G. )
24.7 *
24.7 *
-------
F. FLY ASH DISPOSAL A It CAS
1. AREAS AVAILABLE (ACRES)
2. YEARS STORAGE (ASH ONLY)
3. DISTANCE FROM STACK (FT.)
4. DOES Ti!IS PLANT HAVE PONDING
PROBLEMS? DESCRIBE IN ATTACHMENT
G. COAL DATA
1. COAL SEAM, MINE, MINE LOCATION
a .
b .
c.
d .
2. QUANTITY USED BY SEAM AND/OR MINE
a .
b .
c.
d .
T. ANALYSIS (average and range)
GUV (BTU/LB)
S (%)
ASH J_%)
MOISTURE (%)
4 . ESP PERFORMANCE EXPERIENCED WITH LOW
S FUELS (DESCRIBE IN ATTACHMENT)
H. full OIL data (average and range)
1. TYPE No. 6 or Navy Special Fuel Oil
2j 5 CONTENT (%) Q.5 to 3.1, 3.5% max.
T. asn"content (%) o.oi to o.i
4. SPECIFIC GRAVITY 0.938
5. G1IV .(BTU/GAL) 18746 BTU/lb
COST DATA
ELECTRICITY
WATER
STEAM
J• PLANT SUBSTATION CAPACITY
APPROXIMATELY WHAT PERCENTAGE OF RATED
STATION CAPACITY CAN PLANT SUBSTATION
PROVIDE? 90 MW excess capacity
NORMAL LOAD ON PLANT SUBSTATION?
VOI.TAf.E AT WHICH POWKH TS: AVAT115 volts - 4130
-------
OMB No. 15 8S 74023
POWER PLANT SURVEY FORM
COMPANY INFORMATION:
1. COMPANY NAME: Public Works Center U.S. Navy
2. MAIN'OFFICE: Apra Harbor
3. RESPONSIBLE OFFICER: Captain Wolf
4. POSITION: Commanding Officer
5. PLANT NAME: Piti Power Plant
6. PLANT LOCATION: Piti Village
7. RESPONSIBLE OFFICER AT PLANT LOCATION: R.L. Duncan
8. POSITION: General Foreman
9. POWER POOL Guam Power Pool
Island Wide Power System
DATE INFORMATION GATHERED: December 11, 1974
PARTICIPANTS IN MEETING:
Bob Duncan
U.S. Public Works Center
Ed Yau
Geoffrey Burke
Tim Devitt
Tom Ponder
Don Hendricks
U.S. Navy
Guam Environmental Protection Agency
PEDCo-Environmental Specialists, Inc
PEDC--Environmental Specialists, Inc
U.S. Environmental Protection Agency
-------
ATMOSPHERIC EMISSIONS
Boiler number
1
2
3
4 t 5
1. PARTICULATE EMISSIONS3
LB/MM BTU
0.054
0.054
0.054
0.054
0. 054
GRAINS/ACF
0.018
0.018
0.018
0. 028
0.028
LB/HR (FULL LOAD)
9.1
9.1
9.1
15.6
15.6
TONS/YEAR ( )
2. APPLICABLE PARTICULATE EMISSION
REGULATION
a) CURRENT REQUIREMENT
AQCR PRIORITY CLASSIFICATION
REGULATION & SECTION NO.
LB/MM BTU
0.1
0.1
0.1
0.1
o
•
|
b) FUTURE REQUIREMENT (DATE: )
REGULATION & SECTION NO.
LB/MM BTU
3. S02 EMISSIONS**
LB/MM BTU
3.3
3.3
3. 3
3.3
3.3
LB/HR (FULL LOAD)
5S7
552
552
946
946
TONS/YEAR ( )
4. APPLICABLE S02 EMISSION REGULATION
a) CURRENT REQUIREMENT
REGULATION & SECTION NO.
LB/MM BTU
CO
•
o
o
•
00
0.8
0.8
0.8
b) FUTURE REQUIREMENT (DATE:july l)
REGULATION & SECTION NO. 1975
LB/MM BTU
Particulate and SO? emissions are es
^imates
-------
C. SITE DATA
1. U.T.M. COORDINATES
2. ELEVATION ABOVE MEAN SEA LEVEL (FT) 9.Q'
3. SOIL DATA: BEARING VALUE
PILING NECESSARY 60' Piling
4. DRAWINGS REQUIRED
PLOT PLAN OF SITE (CONTOUR)
EQUIPMENT LAYOUT AND ELEVATION
AERIAL PHOTOGRAPHS OF SITE INCLUDING POWER PLANT,
COAL STORAGE AND ASH DISPOSAL AREA
5. HEIGHT OF TALLEST BUILDING AT PLANT SITE OR
IN CLOSE PROXIMITY TO STACK (FT. ABOVE GRADE) 60'
6. HEIGHT OF COOLING TOWERS (FT. ABOVE GRADE): N.A.
-------
BOILER DATA
Boiler nurier
1 1 2 1 3 1 4
5
1. SERVICE: BASE LOAD
STAND3Y, FLOATINGPEAK
Floating
Floating
Floating
Floating
Floating
2. TOTAL HCJF.5 OPERATION (19 )
N. A.
N.A.
N.A.
N.A.
N.A.
3. AVERAGE CAPACITY FACTOR (19 )
N. A.
N.A.
N.A.
N.A.
N.A.
4. SERVED BY STACK NO.
1
2
3
4
5
5. BOILER MANUFACTURER
C-E
C-E
C-E C-E
C-E
6. YEAR 3GILER PLACED IN SERVICE
1951
1951
1953 1964
1965
7. re:iaining life of unit
6
6
6
20
20
8. GENERATING CAPACITY (MW)
RATED
11.5
11.5
11.5
22.5
22.5
MAXIMUM CONTINUOUS
11.5
11.5
11.5
22.5
22.5
PEAK
13.0
13.0
25.0
25.0
9. FUEL CONSUMPTION:
Oil RATED
(G?H) MAXIMUM CONTINUOUS
1134
1134
1134
1945
1945
PEAK
L0. ACTUAL FUEL CONSUMPTION
CCAL (T?i) (19 )
N. A.
N.A.
N.A.
N.A.
N.A.
OIL (G?Y) (19 }
N.A.
N.A.
N.A.
N.A.
N.A.
LI. VJZT OP. DRY BOTTOM
N.A.
N.A.
N.A.
N.A.
N .A.
L2. FLY AS:; P.E INJECTION (YES OR NO)
N.A.
N.A.
N.A.
N.A.
N.A.
L3. STACK HGT ABOVE GRADE
88' 8"
88'8"
88' 8"
75* 7"
75* 7"
L4. I.D. O? STACK AT TOP
7' 11"
7* 11"
7' 11"
7' 6"
7' 6"
es. Units 1, 2, and 3 each 200,000 lb./hr. steam @ 635 psig & 825°F
Units 4 and 5 each 220,000 lb./hr. steam § 875 psig and 905°F
-------
FLUE GAS CLEANING EQUIPMENT
a) MECHANICAL COLLECTORS
MANUFACTURER
Boiler number
1
2
3
4 1 5
No
Control
Equipment
No
Control
Equipment
No
Control
Equipment
No
Control
Equipment
No
Control
Equipment
TYPE
EFFICIENCY: DESIGN/ACTUAL (%)
MASS EMISSION RATE:
(GR/ACF)
(S/HR)
(#/MM BTU)
b) ELECTROSTATIC PRECIPITATOR
MANUFACTURER
TYPE
EFFICIENCY: DESIGN/ACTUAL (%),»)
MASS EMISSION RATE
(GR/ACF)
(#/HR)
(~/MM BTU)
NO. OF IND. BUS SECTIONS
TOTAL PLATE AREA (FT")
FLUE GAS TEMPERATURE
§ INLET ESP 8 100% LOAD (°F)
EXCESS AIR: DESIGN/ACTUAL (%)
N.A.
N.A.
N.A.
15
15
a) ESP desioned for «per cent sulfur coal
-------
17. FLUE GAS RATE (ACFM)b
@ 100% LOAD
Boiler numbe:
58200
58200
58200
65500
65500
@ 7 5 % LOAD
@ 501 LOAD
18.
STACK GAS EXIT TEMPERATURE (°F)a
@ 100% LOAD
322
322
322
3 75% LOAD
324
324
@ 50% LOAD
19.
EXIT GAS STACK VELOCITY
@ 100% LOAD
(FPS)a
N. A.
N.A.
N.A.
N.A.
N.A.
@ 75% LOAD
@ 50% LOAD
20. FLY ASH: TOTAL COLLECTED (TONS/YEAR)
DISPOSAL METHOD
N.A.
N.A.
N.A.
DISPOSAL COST ($/TON)
N.A.
N.A.
21. BOTTOM ASH: TOTAL COLLECTED(TONS/
DISPOSAL METHOD YEAR>
N.A.
N.A.
N.A.
N.A.
N.A.
DISPOSAL COST ($/TON)
22. EXHAUST DUCT DIMENSIONS 9 STACK FT,
8.0
8.0
8.0
4.5 x 8.3
4.5 x 8.3
23. ELEVATION OF TIE IN POINT TO STACK
21'
21'•
21'
8'11 3/4"
8'11 3/4"
24. SCHEDULED MAINTENANCE SHUTDOWN
(ATTACH PROJECTED SCHEDULE)
2 weeks
2 weeks
2 weeks
3 weeks
3 weeks
a) Identify source of values (test or estimate)
Notes: Air preheater
210°F - 220°F
-------
E. I.D. FAN DATA
1. MAXIMUM STATIC HEAD (IN
2. WORKING STATIC HEAD (IN
Notes:
to
i
•vl
Boiler number
W.G.)
W.G.)
-------
FLY ASH DISPOSAL AULAS
1. AREAS AVAILABLE (ACRES)
2. YEARS STORAGE (ASH ONLY)
DISTANCE FROM STACK (FT.)
DOES THIS PLANT HAVE PONDING
PROBLEMS? DESCRIBE IN ATTACHMENT
COAL DATA
COAL SEAM, MINE, MINE LOCATION
a.
b.
c.
d.
QUANTITY USED BY SEAM AND/OR MINE
a.
b.
c.
d .
ANALYSIS (average and range)
GHV (BTU/LB)
S (%)
ASH (%)
MOISTURE (%)
4. ESP PERFORMANCE EXPERIENCED WITH LOW
S FUELS (DESCRIBE IN ATTACHMENT)
full oil data (average and range)
TYPE No. 6 or Navy Special Fuel Oil
2. S CONTENT (%) 0.5 to 3.1, 3.5% max.
3. ASH CONTENT (%) 0.01 to 0.10
4. SPECIFIC GRAVITY 0.938
5. GHV (BTU/GAL) 18,740 BTU/lb
COST DATA
ELECTRICITY
WATER
STEAM
PLANT SUBSTATION CAPACITY
APPROXIMATELY WHAT PERCENTAGE OF RATED
STATION CAPACITY CAN PLANT SUBSTATION
PROVIDE?
Adequate
NORMAL LOAD ON PLANT SUBSTATION?
VOl.TAfJF. AT WHICH POWER Tn~*AVATTAIMF?
-------
POWER PLANT SURVEY FORM
COMPANY INFORMATION:
1. COMPANY NAME: Guam Power Authority
2. MAIN OFFICE: P.O. Box 2977, Agana, Guam 96910
3. RESPONSIBLE OFFICER: p.£. Cavote
4. POSITION; Asst. General Manager
5. PLANT NAME: Tanguisson
6. PLANT LOCATION: Parcel 1, Estate 103, Dededo, Guam
7. RESPONSIBLE OFFICER AT PLANT LOCATION: Dave Knight
8. POSITION: Plant Manager
9. POWER POOL Guam Power Pool
Island Wide Power System
DATE INFORMATION GATHERED: December 12, 19 74
PARTICIPANTS IN MEETING:
Dave Knight, Pit. Mgr.
Frank Melder, Results
Engineer
John Smith ¦
Geoffrey Burke
Ed Yau
Tim Devitt
Tom Ponder
Don Hendricks
Guam Power Authority
Guam Power Authority
Guam Power authority
Guam Environmental Protection
Agency
U.S. Navy
PEDCo-Environmental Specialists
Inc.
PEDCo-Environmental Specialists
Inc.
U.S. Environmental Protection
-------
ATMOSPHERIC EMISSIONS
Boiler n'JT^er
1
2
1
1. PARTICULATE EMISSIONS3
LB/MM BTU
0.094
0.094
GRAIXS/ACF
0.04
0.04
LB/HR (FULL LOAD)
20. 3
i
TON'S/YEAR ( )
2. APPLICABLE PARTICULATE EMISSION
REGULATION
a) CURRENT REQUIREMENT
ACCR PRIORITY CLASSIFICATION
REGULATION & SECTION NO.
LB/MM BTU
0.1
0.1
b) FUTURE REQUIREMENT (DATE:
REGULATION & SECTION NO.
LB/MM BTU
3. S02 EMISSIONS3,
lb/:"; BTU
3.3
3.3
LB/HP. (FULL LOAD)
1004.4
1004.4
TONS/YEAR ( )
4. APPLICABLE S02 EMISSION REGULATION
a) CURRENT REQUIREMENT
REGULATION & SECTION NO.
00
O
1
o
CO
LB/MM BTU
b) FUTURE REQUIREMENT (DATE:
REGULATION & SECTION NO.
LB/MM BTU
-------
C. SITE DATA
1. U.T.M. COORDINATES
2. ELEVATION ABOVE MEAN SEA LEVEL (FT) 20J
3. SOIL DATA: BEARING VALUE N. A.
. PILING NECESSARY
4. DRAWINGS REQUIRED
PLOT PLAN OF SITE (CONTOUR)
EQUIPMENT LAYOUT AND ELEVATION
AERIAL PHOTOGRAPHS OF SITE INCLUDING POWER PLANT,
COAL STORAGE AND ASH DISPOSAL AREA
5. HEIGHT OF TALLEST BUILDING AT PLANT SITE OR
IN CLOSE PROXIMITY TO STACK (FT. ABOVE GRADE; 56'
6. HEIGHT OF COOLING TOWERS (FT. ABOVE GRADE) : N.A.
-------
BOILER DATA
1. SERVICE: BASE LOAD
STANDBY, FLOATING, PEAK
Boiler number
Base
load
Base
load
2. TOTAL HOURS OPERATION (19 )
NfAt
N.A.
3. AVERAGE CAPACITY FACTOR (19 75)
60%
60%
4. SERVED BY STACK NO.
5. BOILER MANUFACTURER
C-E
C-E
YEAR BOILER PLACED IN SERVICE
9-1-71
12-28-72
O
«
.u
7. REMAINING LIFE OF UNIT
30
30
8. GENERATING CAPACITY (MW)
RATED
26.5
26.5
MAXIMUM CONTINUOUS
PEAi
9- FUEL CONSUMPTION:
OIL RATED
(GFK) MAXIMUM CONTINUOUS
2050
2050
PEAK MINIMUM
673
673
10. ACTUAL FUEL CONSUMPTION
CCAL (TPY) (19 )
OIL
(1975)
BBLS
312,000
11. WET OR DRY BOTTOM
N.A.
N.A.
12. FLY ASH REINJECTION (YES OR NO)
N.A.
N.A.
13. STACK KGT ABOVE GRADE
14. I.D. OF STACK AT TOP
131
131
4'8"
4 ' 8"
-------
FLUE GAS CLEANING EQUIPMENT
a) MECHANICAL COLLECTORS
MANUFACTURER
Boiler number
1
1
NO
CONTROL
EQUIPMENT
NO
CONTROL
EQUIPMENT
TYPE
EFFICIENCY: DESIGN/ACTUAL (%)
MASS EMISSION RATE:
(GR/ACF)
-
(S/HR)
(3 /MM BT'J)
b) ELECTROSTATIC PRECIPITATOR
MANUFACTURER
TYPE
EFFICIENCY: DESIGN/ACTUAL (%) a)
MASS EMISSION RATE
(GR/ACF)
(VHR)
(#/MM BTU)
NO. OF IND. BUS SECTIONS
TOTAL PLATE AREA (FT^)
FLUE GAS TEMPERATURE
0 INLET ESP 8 100% LOAD (°F)
EXCESS AIR: DESIGN/ACTUAL (%}
15
15
a) ESP designed for
Notes:
-------
17.
FLUE GAS RATE (ACFM)
@ 100% LOAD
Boiler number
99,748
99,748
@ 75% LOAD
18.
@ 50% LOAD
STACK GAS EXIT TEMPERATURE (°F)a
@ 100% LOAD
310
310
9 75% LOAD
@ 50% LOAD
19.
EXIT GAS STACK VELOCITY
@ 100% LOAD
(FPS)a
99.4
99.4
@ 75% LOAD
20,
@ 50% LOAD
FLY ASH: TOTAL COLLECTED (TONS/YEAR)
DISPOSAL METHOD
N.A.
N. A.
DISPOSAL COST ($/TON)
21. BOTTOM ASH: TOTAL COLLECTED(TONS/
YEAR)
DISPOSAL METHOD
N.A.
N.A.
DISPOSAL COST ($/TON)
22. EXHAUST DUCT DIMENSIONS !? STACK
23. ELEVATION OF TIE IN POINT TO STACK
24. SCHEDULED MAINTENANCE SHUTDOWN
(ATTACH PROJECTED SCHEDULE)
21 days
per year
21 days
per year
a) Identify source of values (test or estimate)
-------
E. I.D. FAN DATA
1. MAXIMUM STATIC HEAD (IN
2. WORKING STATIC HEAD (IN
Notes:
n
i
Boiler number
W.G.)
-------
F. FLY ASH DISPOSAL AREAS
1. AREAS AVAI LADLE (ACRES)
2. YEARS STORAGE (ASH ONLY)
3. DISTANCE FROM STACK (FT.)
4. DOES THIS PLANT HAVE PONDING
PROBLEMS? DESCRIBE IN ATTACHMENT
G. COAL DATA
1. COAL SEAM, MINE, MINE LOCATION
a.
b_.
c .
d.
2. QUANTITY USED BY SEAM AND/OR MINE
a .
b .
c.
d .
7 ANALYSIS (average and range)
GUV (BTU/LB)
S (%)
ASH (%)
MOISTURE (%)
4 . ESP PERFORMANCE EXPERIENCED WITH LOW
S FUELS (DESCRIBE IN ATTACHMENT)
H. FUEL OIL DATA (average and range)
1. TYPE No. 6 or Navy Special Fuel Oil
2. S CONTENt'u) 0,5 to 3.1 , 3.5% max.
3_. ASH content m 0.01 to 0.10
4_. SPECIFIC GRAVITY 0.938
5. G1IV (BTU/GAL) 18,740 BTU/lb
1 * COS']' DATA
ELECTRICITY
WATER
STEAM
J. PLANT SUBSTATION CAPACITY
APPROXIMATELY WHAT PERCENTAGE OF RATED
STATION CAPACITY CAN PLANT SUBSTATION
PROVIDE?
NORMAL LOAO ON PLANT SUBSTATION?
VOI.TAGE AT WHICH POWER TS AVA "J I.AMI.F?
-------
UM13 No. 1 jtiS 7 4 02 3
POWER PLANT SURVEY FORM
A. COMPANY INFQRMATION:
1. COMPANY NAME: Guam Power Authority
2. MAIN OFFICE: P.O. Box 2977, Agana, Guam 96910
3. RESPONSIBLE OFFICER: p. e. Cavote
4. POSITION: AsstGeneral Manager
5. PLANT NAME: Power Barge Inductance
6. PLANT LOCATION: Polaris Point, Inner Harbor
7. RESPONSIBLE OFFICER AT PLANT LOCATION: jjj-. Arnaiz
8. POSITION: Plant Manager
9. POWER POOL Guam Power Pool
Island Wide Power System
DATE INFORMATION GATHERED: ,.December 11# 1974
PARTICIPANTS IN MEETING:
Inductance Plant (GPA)
A.B. Annaiz, Pit. Mgr.
John Smith
Geoffrey Burke
Tim Devitt
Tom Ponder
Don Hendricks
Guam Power Authority
Guam Power Authority
Guam Environmental Protection Agency
PEDCo-Environmental Specialists, Inc.
PEDCo-Environmental Specialists, Inc.
U. S. Environmental Protection Agency
-------
ATMOSPHERIC EMISSIONS
Boiler nurr.csr
1
2
1
1. PARTICULATE EMISSIONS3
LB/MM BTU
0.066
0. 066
GRAINS/ACr
0.047
0.047
LB/HR (FULL LOAD)
12
12
TOKS/YEAR ( )
2. APPLICABLE PARTICULATE EMISSION
REGULATION
a) CURRENT REQUIREMENT
AOCR PRIORITY CLASSIFICATION
REGULATION & SECTION NO.
LB/MM BTU
0.1
0.1
b) FUTURE REQUIREMENT (DATE: )
REGULATION & SECTION NO.
LB/MM BTU
3. S02 EMISSIONS3
LB/MM BTU
3.3
3.3
LB/HR (FULL LOAD)
600
600
TONS/YEAR ( )
4. APPLICABLE S02 EMISSION REGULATION
a) CURRENT REQUIREMENT
REGULATION & SECTION NO.
LB/MM BTU
0.8
o
• |
0°
b) FUTURE REQUIREMENT (DATE:July l)
REGULATION & SECTION NO. 1975
LB/MM BTU
-------
C. SITE DATA
1. U.T.M. COORDINATES
2. ELEVATION ABOVE MEAN SEA LEVEL (FT) 7 n ' 1-np HppIc
3. SOIL DATA: BEARING VALUE N a
PILING NECESSARY
4. DRAWINGS REQUIRED
PLOT PLAN OF SITE (CONTOUR)
EQUIPMENT LAYOUT AND ELEVATION
AERIAL PHOTOGRAPHS OF SITE INCLUDING POWER PLANT,
COAL STORAGE AND ASH DISPOSAL AREA
5. HEIGHT OF TALLEST BUILDING AT PLANT SJTE OR 20' above
IN CLOSE PROXIMITY TO STACK (FT. ABOVE GRADE) top deck
6. HEIGHT OF COOLING TOWERS (FT. ABOVE GRADE) : n.A.
-------
BOILER DATA
1. SERVICE: BASE LOAD
STANDBY, FLOATING, PEAK
Boiler nur?.bsr |
1
2
Peak
Peak
2. TOTAL HOURS OPERATION (19 )
N. A.
N.A.
3. AVERAGE CAPACITY FACTOR (19 )
30%
30%
4. SERVED BY STACK NO.
1
2
5. BOILER MANUFACTURER
B&W
B&W
6. YEAR BOILER PLACED IN SERVICE
1971
1971
7. REMAINING LIFE OF UNIT Built 1943
3
3
8. GENERATING CAPACITY (MW)
RATED
14 MW
14 MW
MAXIMUM CONTINUOUS
PEAK
9. FUEL CONSUMPTION:
OIL RATED
(G?K) MAXIMUM CONTINUOUS
1230
1230
PEAK
10. ACTUAL FUEL CONSUMPTION
COAL (TPY) (19 )
OIL (1975) BBLS
167.358 BB
LS for the
two units
11. WET OR DRY BOTTOM
N.A.
N.A.
12. FLY ASH REIKJECTION (YES OR NO)
N.A.
N.A.
13. STACK KGT ABOVE GRADE
64'
64 '
14. I.D. OF STACK AT TOP
6' 2"
6' 2"
-------
in
15.
FLUE GAS CLEANING EQUIPMENT
a) MECHANICAL COLLECTORS
MANUFACTURER
TYPE
EFFICIENCY: DESIGN/ACTUAL (%)
MASS EMISSION RATE:
(GR/ACF)
U/HR)
(5 3TU)
b) ELECTROSTATIC PRECIPITATOR
MANUFACTURER
TYPE
EFFICIENCY: DESIGN/ACTUAL (%) a)
MASS EMISSION RATE
(GR/ACF)
(S/HR)
( # /r-'J-l BTU)
NO. OF IN'D. BUS SECTIONS
TOTAL PLATE AREA (FT )
FLUE GAS TEMPERATURE
@ INLET ESP 9 100% LOAD (°F)
Boiler number
No
Control
Equipment
No
Control
Equipment
16. EXCESS AIR: DESIGN/ACTUAL- (%)
15
15
a) ESP desinned for ^per cent sulfur coal
-------
17. FLUE GAS RATE (ACFM)
@ 100% LOAD
Boiler nunber
1
2
1
60,000
60,000
8 75% LOAD
@ 50% LOAD
18. STACK GAS EXIT TEMPERATURE (°F)a
@ 100% LOAD
380
380
§ 7 5% LOAD
@ 50% LOAD
320
320
19. EXIT GAS STACK VELOCITY (FPS)a
@ 100% LOAD
20
20
@ 75% LOAD
@ 50% LOAD
20. FLY ASH: TOTAL COLLECTED (TONS/YEAR)
DISPOSAL METHOD
N.A.
N.A.
DISPOSAL COST ($/TON)
21. BOTTOM ASH: TOTAL COLLECTED(TONS/
DISPOSAL METHOD YEAR)
N.A.
N.A.
DISPOSAL COST ($/TON)
22. EXHAUST DUCT DIMENSIONS 3 STACK
= 6 1
~6'
23. ELEVATION OF TIE IN POINT TO STACK
= 6'
~6'
24. SCHEDULED MAINTENANCE SHUTDOWN
(ATTACH PROJECTED SCHEDULE)
Every i
> months
a) Identify source of values (test or estimate)
-------
E. I.D. FAN DATA
1. MAXIMUM STATIC HEAD (IN
2. WORKING STATIC HEAD (IN
Notes:
V
I
Boiler number
W.G.)
-------
FLY ASH DISPOSAL AULAS
1. AREAS AVAILABLE (ACRES)
2. YEARS STORAGE (ASH ONLY)
3. DISTANCE FROM STACK (FT.)
DOES THIS PLANT HAVE PONDING
PROBLEMS? DESCRIBE IN ATTACHMENT
COAX. DATA
1. COAL SEAM, MINE, MINE LOCATION
a.
b.
c.
d.
2. QUANTITY USED BY SEAM AND/OR MINE
a.
b.
c.
d .
3. ANALYSIS (average and range)
GUV (BTU/LB)
S (%:
ASH (%)
MOISTURE (%)
4. ESP PERFORMANCE EXPERIENCED WITH LOW
S FUELS (DESCRIBE IN ATTACHMENT)
fuel OIL data (average and range)
No. 6 or Navv Special Fuel Oil
2. S CONTENT m Q.5 to 3.i. 3t5%
max.
3. ASH CONTENT (%) 0.01 to 0.1
4. SPECIFIC GRAVITY Q.938
5. G11V .(BTU/GAL) 18,740 BTU/lb.
COS']' DATA
ELECTRICITY
WATER
STEAM
PLANT SUBSTATION CAPACITY
APPROXIMATELY WHAT PERCENTAGE OF RATED
STATION CAPACITY CAN PLANT SUBSTATION
™«VIP1! 2 Jl. J*5Q_Q_.JKVA jea.qh
NORMAL LOAD ON PLANT SUBSTATION? about_6S
VOLTAGE AT WHICH POWER IS AVAILABLE? 13800 - 440
-------
APPENDIX E
BASIS OF PROCESS DESIGN
The process design basis for the wet limestone system and
the seawater scrubbing system used in this study was determined
after review of process designs used or proposed for use at
various installations and discussions with control system
manufacturers.
Values of the major overall design parameters for the
Cabras and Tanquisson plants are tabulated below:
A. Cabras Plant
° Flue gas temperature: Units 1-2: 334°F
° Flue gas pressure: atmospheric
° Average inlet SO, concentration: 3.30 lb/MM BTU
(3.1% S oil)
° Outlet SOj concentration: (aver.) 3.30 lb/MM BTU
(present)
° Outlet SO2 concentration: 0.8 lb/MM BTU (allowable)
0 Reheat: 50°F above dew point (from 125 to 175°F)
1. Wet Limestone System
Two cases were evaluated. In Case 1 the Cabras plant
system is completely separate from the Tanquisson plant system.
In Case 2 the limestone storage, grinding, and slurrying
facilities for both plants is located at Cabras. The actual
scrubbing system remains the same for both cases.
a. Design Values
Limestone Consumption: 130% stoichiometric
Limestone Handling, Slurrying 5ystem
Case 1
Unloading Hopper: 25 ton capacity
-------
Dead Storage Pile: 30 days storage
Feeders, Conveyors: Capacity = 5.8 x Maximum Limestone Flow
Live Storage Silos: 3 days storage
Ball Mills: 2-2 tons/h capacity units
Limestone Slurry Storage Tank: 24 hours storage
Limestone Slurry Feed Pumps: 1 pump/train with 1 spare for
each 2 operating pumps.
Raw Water Pumps: 2
Case 2
Unloading Hopper: 25 ton capacity
Dead Storage Pile: 30 days storage (both plants)
Feeders, Conveyors: Capacity = 5.8 x Maximum Limestone
Flow (both plants)
Live Storage Silos: 3 days storage (both plants)
Ball Mills: 2-3 tons/h capacity units
Limestone Slurry Storage Tank: 24 hours storage (both plants)
Limestone Slurry Feed Pumps: 1 pump/train with 1 spare for
each 2 operating pumps.
Raw Water Pumps: 2
Sludge System
Clarifier: 1 unit
Sludge Pond: Proposed disposal sites are abondoned barrow
pits on Cabras Island and Nimitz Hill, and are of sufficient
size to accommodate the required 70 acre-feet per year for
the remaining plant life of 30 years.
Scrubbing System (Each Train)
Fan: 1-100% unit
Type - Double inlet centrifugal
AP ¦ 16.4" H20
Absorber: Type - TCA with 2 beds
AP - 7" H^O
L/G * 65 GPM/AMCFM (inlet gas to absorber scrubber)
-------
Slurry Concentration = 8% (wt.)
SO2 Removal = 80%+
Gas Velocity = 10 FPS
Circulating Tank - 10 minutes retention
Pumps = 3/unit plus 1 spare pump for every 2 units
Entrainment Separator: Chevron vane-type
Number passes = 2
AP = 2" H2O
Gas Velocity = 7 FPS
Reheater: Type - indirect tubular
AT = 50°F (inlet temperature = 125°F;
outlet temperature = 175°F)
Heating Medium - low pressure steam
b. Design Rationale
The design rationale used in the study are listed below:
0 The unloading hopper was sized to hold 25 tons in order
to accommodate unloading of trucks.
0 The limestone dead storage pile was sized for 30 days
to allow the plant to continue operating in the event
of an interruption in the supply of limestone.
0 The live storage silos were sized for 3 days storage.
0 The feeders and conveyors were sized at 5.8 times the
maximum limestone flow to allow the unloading of lime-
stone during a 4 0 hour week while the plant operates
continuously..
0 For Case 1, 2-2 tons/h capacity ball mills were provided
and sized to allow the power plant to generate at
maximum capacity while burning high sulfur content oil.
In the event 1 mill was out of service, the other mill
could keep the plant operating for 56 hours.
0 For Case 1, the limestone slurry storage tank was sized
for 24 hours storage to allow the scrubbing trains to
continue operating for 56 hours with 1 mill out of
service or for 24 hours if maintenance required complete
shutdown of the 2 ball mills.
0 For Case 2, 2-3 ton/h capacity ball mills were provided
and sized to allow both plants to generate at maximum
capacity while burning high sulfur content oil. In the
event 1 mill was out of service, the other mill could
keep the plants operating for 82 hours.
0 For Case 2, the limestone slurry storage tank was sized
for 24 hours storage (both plants) to allow the scrubbing
trains to continue operating for 82 hours with 1 mill
-------
out of service or for 30.5 hours with both mills out of
service. In addition there is a twenty-four storage at
Tanquissor.
0 In general, all pumps in the process are provided with
spares.
0 1 thickener to concentrate the effluent slurry from 15%
solids to 30% solids and then discharge the 30% effluent
slurry to the vacuum filtration unit (1 unit at a rate
capacity of 10 tons/hour). The effluent leaves the
filtration unit as a slurry 60% by weight and then enters
a mixing tank where the fixation additives are stirred
in with the slurry and then trucked to the barrow pits
for disposal.
0 A UOP* Turbulent Contact Absorber (TCA) was selected for
removal of the bulk of the SC^. This unit has 2 beds
of hollow plastic spheres which move randomly between
support grids and provide the contact area necessary
for mass transfer of S02 from the gas to the liquid
phase. The absorber is designed for an L/G of 65 GPM/
MACFM (inlet gas to the absorber) and a pressure drop
of 7" H20. Slurry concentration will be 8%; gas
velocity in the unit will be 10 FPS; and SO2 removal is
specified to be about 80% plus. The size of the turbulent
contact absorber will be 15' x 16' approximately for units
1 & 2 in cross-section and will treat 121,000 ACFM,
respectively of saturated gas (corresponding to about
66 MW nominal).
0 Each absorber has a circulating tank sized to provide
a 10-minute retention time based on the slurry circula-
ting rate. This retention time is essentially the same
as that reported by others and should provide sufficient
time for desupersaturation and thus reduce scaling
potential.
However, if long retention times are required, the
incremental cost would be small since the circulating
tanks do not represent large cost items, but space
limitations may require locating a secondary tank some
distance away and require additional piping.
0 The Chevron vane-type entrainment separator was selected
to remove mist which is carried over in the gas from
the absorber. This unit contains two stages of Chevron
vanes which are washed continuously with water. Super-
ficial gas velocity through the unit is 7 FPS and the
pressure drop is expected to be about 2" H2O. Design
of the unit is based on information from C-E, Chemico
and UOP.
-------
° The gas leaving the entrainment separator must be
reheated to desaturate it and provide buoyancy for it
for adequate atmospheric dispersion. The number of
degrees of reheat necessary is variable and dependent on
a number of factors such as stack height, local weather
conditions, population density, terrain of the area,
maximum allowable SO? ground level concentration, etc.
For this study, a reheat AT of 50°F was used; this is
believed to be about the minimum acceptable value.
Obviously, the lowest acceptable reheat AT should be
chosen since each increase of 50°F of the flue gas
temperature requires about 1.5% of the gross heat
input to the plant.
An indirect finned tubular heat exchanger was selected
for the reheater. The first 33% of the rows of tubes
are constructed of Alloy 20 for corrosion resistance to
the gas which enters at it's dew point. The remaining
67% of the rows are constructed of carbon steel. Heating
medium for the unit is low pressure saturated steam.
Pressure drop through the reheater is calculated to be
about 4" H2O.
0 Based on experience at Will County, a retractable B & W
type soot blower is used for each 25 ft2 of scrubber
exit duct cross-section for the heat exchanger. Half
of the soot blowers will be on the entry side, the
remainder on the exit side of the heat exchanger.
2. Seawater
a. Design Values
Scrubbing System (Each train)
Raw Water Pumps: 2
Fan: 1-100% unit
Type - Double inlet centrifugal
AP - 16.4" H2O
Absorber: Type - TCA with 2 beds
AP - 7" H20
L/P — 65 GPM/MACFM (inlet gas to absorber scrubber)
SO2 Removal = 80%+
Gas Velocity = 10 FPS
Pumps = 3/unit plus 1 spare pump for every 2 units
Entrainment Separator: Chevron vane-type
Number passes » 2
AP - 2" H20
Gas Velocity » 7 FPS
-------
Reheater: Type - indirect tubular
AT = 50°F (inlet temperature = 125°F;
outlet temperature = 175°F)
Heating Medium - low pressure steam
Effluent Treatment
Clarifier: 1 unit
b. Design Rationale
The design rationale used in the study are listed below:
0 In general, all pumps in the process are provided with
spares.
0 1 clarifier is utilized to remove suspended solids
(heavy metals for oil) from the effluent. Note that
no provision has been made to aerate the effluent
though this could be necessary. The clarifier discharge
is diluted with condenser cooling water before discharge
into the ocean.
° A UOP* Turbulent Contact Absorber (TCA) was selected for
removal of the bulk of the SO2. This unit has 2 beds
of hollow plastic spheres which move randomly between
support grids and provide the contact area necessary for
mass transfer of SCK from the gas to the liquid phase.
The absorber is designed for an L/C of 65 GPM/MACFM
(inlet gas to the absorber) and a pressure drop of 7"
H20. Gas velocity in the unit will be 10 FPS; and SO2
removal is specified to be about 80% plus. The size
of the turbulent contact absorber will be 15' x 16'
approximately for units 1 and 2 in cross-section and will
treat 121,000 ACFM, respectively of saturated gas
(corresponding to about 66 MW nominal).
0 The Chevron vane-type entrainment separator was selected
to remove mist which is carried over in the gas from
the absorber. This unit contains two stages of Chevron
vanes which are washed continuously with water. Superficial
gas velocity through the unit is 7 FPS and the pressure
drop is expected to be about 2" H2O. Design of the unit
is based on information from C-E, Chemico and UOP.
0 The gas leaving the entrainment separator must be
reheated to desaturate it and provide buoyancy for
adequate atmospheric dispersion. The number of degrees
of reheat necessary is variable and dependent on a
number of factors such as stack height, local weather
conditions, population density, terrain of the area,
maximum allowable SOj ground level concentration, etc.
* Universal Oil Products Company (Air Correction Division).
-------
For this study, a reheat AT of 50°F was used; this is
believed to be about the minimum acceptable value.
Obviously, the lowest acceptable reheat AT should be
chosen since each increase of 50°F of the flue gas
temperature requires about 1.5% of the gross heat input
to the plant.
An indirect finned tubular heat exchanger was selected
for the reheater. The first 33% of the rows of tubes
are constructed of Alloy 20 for corrosion resistance
to the gas which enters at it's dew point. The remaining
67% of the rows are constructed of carbon steel. Heating
medium for the unit is low pressure saturated steam.
Pressure drop through the reheater is calculated to be
about 4" H2O.
0 Based on experience at Will County, a retractable B & W
type soot blower is used for each 25 ft2 of scrubber
exit duct cross-section for the heat exchanger. Half of
the soot blowers will be on the entry side, the remainder
on the exit side of the heat exchanger.
B. Tanguisson Plant
0 Flue gas temperature: units 1-2: 310°F
0 Flue gas pressure: atmospheric
0 Average inlet SO- concentration: 3.30 lb/MM BTU
(3.1% S Oil)
0 Outlet S02 concentration: (aver.) 3.30 lb/MM BTU
(present)
0 Outlet SO2 concentration: 0.8 lb/MM BTU (allowable)
0 Reheat: 50°F above dew point (from 125 to 175°F)
1. Wet Limestone System
Two cases as described under the Cabras Plant are evaluated.:
For Case 1, the Tanguisson Plant has separated limestone slurrying
facilities, while for Case 2, it has none.
a. Design Values
0 Limestone consumption = 130% stoichiometric
Limestone Handling, Slurrying System
Case 1
Unloading Hopper: 25 ton capacity
-------
Dead Storage Pile: 30 days storage
Feeders, Conveyors: Capacity = 5.8 x Maximum Limestone Flow
Live Storage Silos: 3 days storage
Ball Mills: 1-3 tons/h capacity unit
Limestone Slurry Storage Tank: 24 hours storage
Limestone Slurry Feed Pumps: 1 pump/train with 1 spare for
each 2 operating pumps
Raw Water Pumps: 2
Case 2
Limestone Slurry Storage Tank: 24 hours
Limestone Slurry Feed Pumps: 1 pump/train with 1 spare for
each 2 operating pumps.
Sludge System
Clarifier: 1 unit
Sludge pond: proposed disposal sites are abandoned barrow
pits near Dededo that are of sufficient size to accommodate
the required 21 acre-feet per year for the remaining plant
life of 30 years.
Scrubbing System (Each Train)
Fan: 1-100% unit
Type - Double inlet centrifugal
AP « 16.4" h20 for units 1-2
Absorber: Type - TCA with 2 beds
AP = 7" H20
L/G = 65 GPM/MACFM (inlet gas to absorber scrubber)
Slurry Concentration = 8% (wt.)
SO2 Removal = 80%+
Gas Velocity ® 10 FPS
Circulating Tank - 10 minutes retention
Pumps = 3/unit plus 1 spare pump for every 2 units
Entrainment Separator: Chevron vane-type
Number passes * 2
AP - 2" H20
Gas Velocity - 7 FPS
Reheater: Type - indirect tubular
AP » 50°F (inlet temperature = 125°F;
outlet temperature = 175°F)
Heating Medium - low pressure steam
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b. Design Rationale
The design rationale used in the study are listed below:
° The unloading hopper was sized to hold 25 tons in order
to accommodate unloading of trucks.
0 The limestone dead storage pile was sized for 30 days
storage to allow the plant to continue operating in the
event of an interruption in the supply of limestone.
° The live storage silos were sized for 3 days storage.
° The feeders and conveyors were sized at 5.8 times the
maximum limestone flow to allow the unloading of lime-
stone to take place during a 40 hour week while the
plant operates continuously.
° For Case 1, the 3 tons/h ball mill was provided and
sized to allow the power plant to generate at maximum
capacity while burning high sulfur content oil.
0 For Case 1, the limestone slurry storage tank was sized
for 24 hours storage to allow the scrubbing trains to
continue operating far 24 hours with the mill out of
service.
° For Case 2, the limestone slurry storage tank was sized
for 24 hours storage to allow the scrubbing trains to
continue operating for 82 hours with 1 ball mill out of
service at the Cabras Plant or for 30.5 hours with both
ball mills at Cabras out of service.
0 In general, all pumps in the process are provided with
spares.
° 1 thickener to concentrate the effluent slurry from 15%
solids to 30% solids and then discharge the 30% effluent
slurry to the vacuum filtration unit (1 unit at a rated
capacity of 4 tons/hour). The effluent leaves the
filtration unit as a slurry 601 by weight and then enters
a mixing tank where the fixation additives are stirred
in with the slurry and then trucked to the barrow pit
for disposal.
° A UOP* Turbulent Contact Absorber (TCA) was selected for
removal of the bulk of the SO-. This unit has 2 beds
of hollow plastic spheres which move randomly between
support grids and provide the contact area necessary
for mass transfer of SO2 from the gas to the liquid
phase. The absorber is designed for an L/G of 65 GPM/
* Universal Oil Products Company (Air Correction Division).
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0 A UOP* Turbulent Contact Absorber (TCA) was selected for
removal of the bulk of the SC^. This unit has 2 beds of
hollow plastic spheres which move randomly between support
grids and provide the contact area necessary for mass
transfer of SOj from the gas to the liquid phase. The
absorber is designed for an L/G of 65 GPM/MACFM (inlet
gas to the absorber) and a pressure drop of 7" HjO.
Gas velocity in the unit will be 10 FPS; and SO2 removal
is specified to be about 80% plus. The size of the
turbulent contact absorber will be 15' x 11' approximately
for both units in cross-section and will treat 100,000
ACFM, respectively of saturated gas (corresponding to
about 26.5 MW nominal).
0 The Chevron vane-type entrainment separator was selected
to remove mist which is carried over in the gas from the
absorber. This unit contains two stages of Chevron vanes
which are washed continuously with water. Superficial gas
velocity through the unit is 7 FPS and the pressure drop
is expected to be about 2" H2O. Design of the unit is
based on information from C-E, Chemico and UOP.
0 The gas leaving the entrainment separator must be reheated
to desaturate it and provide buoyancy for it for adequate
atmospheric dispersion. The number of degrees of reheat
necessary is variable and dependent on a number of factors
such as stack height, local weather conditions, population
density, terrain of the area, maximum allowable SO2 ground
level concentration, etc. For this study, a reheat AT of
50°F was used; this is believed to be about the minimum
acceptable value. Obviously, the lowest acceptable
reheat AT should be chosed since each increase of 50°F
of the flue gas temperature requires about 1.5% of the
gross heat input to the plant.
An indirect finned tubular heat exchanger was selected
for the reheater. The first 33% of the rows of tubes
are constructed of Alloy 20 for corrosion resistance
to the gas which enters at it's dew point. The remaining
67% of the rows are constructed of carbon steel. Heating
medium for the unit is low pressure saturated steam.
Pressure drop through the reheater is calculated to be
about 4" H20.
0 Based on experience at Will County, a retractable B & W
type soot blower is used for each 25 ft^ of scrubber exit
cross-section for the heat exchanger. Half of the soot
blowers will be on the entry side, the remainder on the
exit side of the heat exchanger.
* Universal Oil Products Company (Air Correction Division).
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