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Appendix F
Gil Spills
Large oil spills are infrequent events, usually in different
locations. They occur, they are cleaned up as much as possible,
some restoration may be attempted, and over time, natural re-
covery may occur. Unless spills occur repeatedly in a location,
or are very large, their effects usually do not accumulate. On the
North Slope, there have been no major offshore oil spills or
large spills greater than 1,000 bbl (42,000 gallons) according
to the Minerals Management Service (MMS) definition asso-
ciated with exploration and production. Three large spills from
the Trans-Alaska Pipeline have occurred on the North Slope
(Table F-1~. There have been many small spills onshore, how-
ever, and the potential for future spills offshore (large and small)
exists. This appendix describes the history of spills, spill pre-
vention efforts, response to spills, and the fate and effects of oil
spilled on the North Slope.
OIL SPILLS
History of North Slope Oil Spills
Spills are unintentional, accidental releases of crude oil
or petroleum products. They have been analyzed statistically
for the Trans-Alaska Pipeline System (TAPS), divided into
four components (Maxim and Niebo 2001b):
Exploration and Production Facilities well pads,
Bowlines, gathering centers, base operation centers, power
stations, and pipelines that feed into TAPS.
2. TAPS pipeline, pump stations, storage tanks, and
associated facilities.
3. Valdez Marine Terminal storage tanks, pumps, con-
necting pipes, and tanker berths.
4. Marine Transport tankers carrying crude oil to
destination ports.
Here we focus on North Slope exploration and produc-
tion facilities and on TAPS pipeline from Pump Station 1 to
Atigun Pass.
Sources of Spills from North Slope Facilities and the
Trans-Alaska Pipeline to Atigun Pass
Oil is produced from wells on gravel pads onshore or
offshore on islands. In-field pipelines (flowlines) carry
TABLE F-1 Ten Largest Crude Oil Spills From TAPS, Pump Station 1 to Atigun Pass, 1977-2000 (Modified from Maxim
and Niebo 2001b)
Number Date Volume (bbl) Description
2
3
4
5
6
7
19 Jul 77
1 Jan 81
10 Jun 79
16 Aug 77
24 Nov 94
17 May 84
28 Oct 80
4 May 84
23 Aug 89
10 5Dec81
1,800
1,500
1,500
30
18
11
6
5
5
Heavy equipment accident caused leak at check valve 7, mile point 27.
Check valve 23 malfunctioned and leaked when a drain connection failed.
Pipe settlement at Atigun Pass caused a leak.
Sump at Pump Station 1 overflowed.
Valve left open after routine maintenance.
Broken drain plug at the Pump Station 3 tank farm.
Valve malfunction at Pump Station 2.
O-ring seal failed at Pump Station 4 manifold building.
Discharge relief valve stem failed, Pump Station 2.
Check valve leaked, metering building at Pump Station 1.
SOURCE: TAPS Owners 2001.
208
OCR for page 209
APPENDIX F
multiphase slurries containing oil, gas, and water from well-
head to CPFs (central processing facilities), sometimes
called flowstations. A CPF is the operational center of the
production activities. It typically includes processing equip-
ment, storage tanks for fuel and water, power generators,
maintenance facilities, living quarters, and communications
facilities. The processing equipment includes three-phase
separators. Oil, gas, and water are produced in varying pro-
portions from each well. Gas conditioning equipment re-
moves natural gas liquids from produced gas. Pipeline gath-
ering and pressure regulation systems and well monitoring
and control systems are also part of the CPF. Oil is filtered to
remove any sand or grit. After processing the oil (now called
sales oil) is routed through a sales meter and enters a feeder
pipeline (also called sales-oil pipeline) for delivery to a larger
diameter pipeline to Pump Station 1 of the Trans-Alaska
Pipeline.
Natural gas extracted during processing is further pro-
cessed to remove liquids, then compressed and reinfected
into the reservoir through service wells. Water is chemically
treated and also reinfected into the reservoir. Reinjection of
water and natural gas increases oil recovery by maintaining
reservoir pressure.
Pipelines that carry water, gas, crude oil, and diesel vary
in diameter and are normally installed above ground on ver-
tical support members. Above-ground pipelines are easier to
monitor, repair, and reconfigure when necessary. Offshore
pipelines are buried until they reach shore where they join
the pipeline system. Spills can potentially occur from pipe-
lines, pump stations, support facilities such as aboveground
and underground storage tanks, and support facilities such as
tanker trucks. Spills can occur at any place where crude oil
or products are handled, stored, used, or transported.
Spill Statistics
North Slope
Spills have been reported and recorded over the years of
operation of the oil fields and TAPS. The information dis-
cussed here is primarily from the analysis recently prepared
for the TAPS Owners (2001) in support of their application
for right-of-way renewal. The period covered is from 1977,
when the first oil flowed through TAPS, through 1999. The
data were compiled by IT Corporation from original source
documents with minor adjustments and corrections made
more recently by Niebo (2001; R. Niebo, Everest Consulting
Associates, personal communication, 2001) and Maxim and
Niebo (2001~. Table F-2 shows spills associated with explo-
ration and production activities on the North Slope; Table F-
3 shows spills associated with TAPS pipeline operations
from Pump Station 1 to Atigun Pass. Over the 23-year pe-
riod, there was an average of 70 crude oil and 234 products
spills per year associated with North Slope operations and
the North Slope segment of TAPS operations. The volume
209
TABLE F-2 Numbers and Volumes of North Slope
Crude Oil and Petroleum Products Spillsa
Crude oil
Year
number
volume (bbls)
Petroleum products
number Volume (bbls)
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
Totals
12
12
20
22
54
59
62
48
91
91
97
129
163
102
140
70
61
51
39
52
39
44
27
1.485
75.58
47.62
101.64
50.12
57.88
158.81
105.76
358.60
535.43
164.67
256.64
270.70
1,790.05
223.50
65.56
34.80
2,230.65
298.76
33.33
46.26
97.89
118.49
6.16
7,128.91
22
20
16
46
181
91
120
23
168
145
137
312
408
359
445
259
209
159
132
141
123
124
258
3,898
163.68
82.27
25.44
236.24
1,004.93
393.45
413.15
34.00
363.17
410.40
102.10
240.94
364.64
234.85
324.86
81.80
65.21
54.23
115.87
97.31
321.65
40.56
49.07
5,219.81
a Spills from exploration and production activities on the North Slope.
SOURCE: Modified from Neibo 2001b.
TABLE F-3 Numbers and Volumes of Crude Oil and
Petroleum Products Spillsa
Crude oil
Year number
volume (bbls)
Petroleum products
number Volume (bbls)
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
Totals
9
3
7
3
6
8
4
8
4
1
o
5
3
9
9
10
11
11
1
1
2
o
2
117
1,831.07
5.00
1,502.67
6.28
1,505.24
4.21
2.08
16.24
0.10
0.71
o
0.24
5.72
1.10
1.92
0.42
2.66
20.84
0.71
0.07
0.12
o
0.26
4,907.67
771
17
24
38
28
55
14
14
11
14
4
17
22
49
114
48
46
82
31
15
29
18
12
1,473
162.58
26.06
159.78
9.14
13.14
93.22
4.88
12.86
4.81
90.10
5.39
207.21
12.30
51.16
24.30
232.47
25.61
5.16
7.12
2.68
6.19
23.16
3.68
1,183.00
a Spills associated TAPS from Pump Station 1 to Atigun Pass.
SOURCE: Modified from Neibo 2001b.
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210
spilled amounts to a yearly average of 523 bbl (21,966 gal-
lons) of crude oil and 278 bbl (11,676 gallons) of products
(R. Niebo, Everest Consulting Associates, personal commu-
nication, 2001~.
Reported volumes of North Slope spills vary by more
than six orders of magnitude, from 0.006 to 925 bbl (0.336
to 38,850 gallons). The statistical distribution of the volumes
of crude and product spills on the North Slope are approxi-
mately lognormal. Relatively small spills are frequent, but
there is a long "tail" to the distnbution, with total volume
dominated by the relatively few larger spills (Maxim and
Niebo 2001b). This is typically plotted using a Lorenz dia-
gram (Figure F-1) that graphs the fraction of the spill vol-
ume (on the vertical axis) versus the fraction of the number
of spills (on the horizontal axis). First, spill data are sorted in
ascending order of spill volume. Next the cumulative frac-
tion of the total volume spilled (vertical axis) is plotted as a
function of the cumulative fraction of the number of spills
(honzontal axis). If all spills were exactly the same size, the
fraction of the spill volume would correspond exactly to the
fraction of the number of spills. The 45-degree line "AB"
depicts this situation. If some spills are larger than others
then the fraction of the spilled volume will be less than the
fraction of the number of spills, as shown in the curve "AB"
beneath the 45-degree line. The area between the curve and
the straight line (shaded) illustrates the degree of inequality
in spill size distnbution. Dividing the shaded area by the
area of the triangle "ABC" provides a normalized index or
coefficient, denoted L, of the variability in spill volumes. L
ranges from O (all spills the same size) to 1 (Maxim and
Niebo 2001b).
The diagram in Figure F-1 is hypothetical; its purpose is
to illustrate the concept. The actual curves for exploration
B
0.8
_ 0.6
. _
Q
In
o
~ 0.4
.o
Cal
IL
APPENDIX F
and production spills are more extreme. Figure F-2 is a
Lorenz plot for North Slope crude oil and products spills
over the period 1977-1999. There is substantial curvature in
these plots, and the computed Lorenz coefficients are 0.911
and 0.883 for crude and products spills, respectively (Maxim
and Niebo 2001b). Thus, a few relatively large spills account
for most of the spill volume, as is typical of most oil fields
(e.g., Smith et al. 1982, BLM/MMS 1998, MMS 2001a).
Fifty percent of North Slope crude spills were less than or
equal to 0.238 bbl (9.996 gallons). Fifty percent of the prod-
uct spills were less than or equal to 0.119 bbl (4.998 gal-
lons). The smallest 90% of crude spills accounted for ap-
proximately 13% of the total volume spilled in this segment
and the smallest 95% of the spills accounted for approxi-
mately 20% of the spilled volume. The corresponding per-
centages for products spills were 16% and 25%, respectively.
From an environmental standpoint, small spills are gen-
erally less significant than large spills because they are typi-
cally contained and cleaned up at the site of the spill (e.g.,
drill pad) and therefore are less likely to cause significant
adverse environmental effects. Contaminated gravel cannot
be reused before it has been cleaned; current regulations re-
quire such cleanup, or disposal, of contaminated gravel.
Small spills also account for only a small portion of the total
volume spilled.
TAPS: Pump Station 1 to Atigun Pass
Maxim and Niebo (2001) analyzed spills along the
Trans-Alaska Pipeline using the TAPS (2001) oil spill data-
base. There are 10,588 spill records in the entire database.
The North Slope segment from Pump Station 1 to Atigun
1
0.8 _
Curve with all
spills equal size
it'
E
g 0.6
._
Q
U)
0 0.4
c'
IL
~ Product
_ Crude ,
O-
A 0 0.2 0.4 0.6
Fraction of Spills
0.8 1 C
FIGURE F- 1 Hypothetical Lorenz diagram. SOURCE: Reprinted
with permission from Maxim and Niebo 2001b.
0.2 _
0.2 0.4 0.6
Fraction of Spills
0.8 1
FIGURE F-2 Actual Lorenz diagram for crude oil and products
spills associated with exploration and production activities on the
North Slope. SOURCE: Reprinted with permission from Maxim
and Niebo 2001b.
OCR for page 211
APPENDIX F
Pass contains 3,244 records; 232 are crude oil spills and
3,012 are products spills. To identify the spills from Atigun
Pass north, spill records were identified by mile marker num-
ber on the pipeline or Dalton Highway, pump station num-
ber, check valve number, material site number, access road
number, or landmark name. Using these cntena, 28 spill
records did not contain enough information to be positively
located north or south of Atigun Pass. Four of them were
crude oil spills totalling 303 bbl (12,726 gallons). One spill
was 300 bbl (12,600 gallons). The other 24 were products
spills totalling 147 bbl (6,174 gallons). These questionable
records were not considered part of North Slope segment of
TAPS (Maxim and Niebo 2001b).
Dunng the period from 1977 to 1999, 1,590 spills oc-
curred along the pipeline segment from Pump Station 1 to
Atigun Pass. Of these, 117 were crude oil spills, and 1,473
were products spills. The total volume of crude oil spilled
over the 23-year period was 4,908 bbl (206,136 gallons) and
1,183 bbl (49,686 gallons) of petroleum products, an annual
average of 69 spills per year with an annual volume of 265
bbl (11,130 gallons) spilled. For companson, operation of
the entire TAPS during the same period resulted in 3,244
crude oil and products spills totalling 32,092 bbl (1,347,864
gallons), an annual average of 141 spills with an annual vol-
ume of 1,395 bbl (58,590 gallons). Spills north of Atigun
Pass represent approximately 19% of all materials spilled
along TAPS. The volumetric spill rate (VSR) (i.e., barrels
spilled per million barrels of throughput) was 0.477 for the
period (Maxim and Niebo 2001b). Figure F-3 shows the an-
20
18
16
14
i_
Q
Q
~ 12
o
. _
Q
fir
=
Q
U'
10
8
6
4
2
o
:
211
nual VSR for this TAPS segment. The spill rate was highest
during the early years of the pipeline' s operation, dropped in
the early 1980s, and has remained relatively constant since
then.
Spill records in TAPS segment 1 vary in volume by
more than eight orders of magnitude, from 0.00001 bbl
(0.00042 gallons) to 1,800 bbl (75,600 gallons). The total
spill volume is dominated by a few relatively large spills
(Figure Fob. Fifty percent of both crude oil and products
spills in this pipeline segment were less than 0.07143 bbl (3
gallons). The smallest 90% of crude oil spills accounted for
approximately 0.5% of the total volume spilled, and the
smallest 95% of crude oil spills accounted for approximately
1.2% of the total volume. The corresponding percentages for
products spills were 9% and 11 %, respectively (Maxim and
Niebo 2001b).
Larger Volume Spills History
Because most oil is released in a few large spills, we
highlight the highest volume crude oil and products spills
that have occurred over the operating history of the fields,
including causes, effects, corrective actions, and counter-
measures.
Table F-4 is a list of the 10 largest North Slope crude oil
shills (120 to 925 bbl, or 5,040 to 38,850 gallons) during the
1977 to 1999 period. Causes (BLM/MMS 1998, MMS
2001a, Parametnx 1997) include leaks from or damage to
storage tanks, faulty valves and gauges, faulty connections,
1.0
0.8
~ V ~ -_
au
0.6
._
Q
U)
o
._
0.4
0.2 _
1 1 1 1 1 0.0 ~
1980 1985 1990 1995 2000 0.0
Year
FIGURE F-3 Volumetric spill rate (VSR) for crude oil and prod-
ucts spills associated with the Trans-Alaska Pipeline System from
Pump Station 1 to Atigun Pass. SOURCE: Reprinted with permis-
sion from Maxim and Niebo 2001b.
Crude
Refined
_ _—
0.2 0.4 0.6 0.8 1.0
Fraction of Spills
FIGURE F-4 Lorenz diagram of crude oil and products spills as-
sociated with the Trans-Alaska Pipeline System from Pump Station
1 to Atigun Pass. SOURCE: Reprinted with permission from
Maxim and Niebo 2001b.
OCR for page 212
212
TABLE F-4 Ten Largest Crude Oil Spills on the North Slope, 1977-2000
APPENDIX F
Number Date Volume (bbl) Description
1 28 Jul 89 925
2 26 Sep 93 650
7
30 Dec 93
10 Jun 93
24 Dec 93
8 Nov 89
10 Dec 90
15 Nov 85
5 Nov 84
10 25 Mar 87
375
300
180
180
176
175
125
120
Oil reserve tank overflowed into reserve pit. Alarm system failed.
Pump failure caused tank overflow. Inlet valve was closed and outlet valve opened, allowing oil
to spill into a containment dike. High winds carried some oil mist to snow outside containment
dike.
Wind-induced vibration caused a flowline to crack. Crude oil sprayed from crack. High winds
carried some oil away from the pad.
High-level alarm failed on drum.
Level monitor, high-level alarm, and automatic shutoff devices froze on a tank, allowing oil to
flow out of the overflow line. Crude oil flowed into the lined area surrounding the tank.
Break in temporary Bowline caused by internal erosion. Crude oil was released onto gravel pad.
Explosion and fire caused by fluid leaking from a vacuum truck. Oil was released onto pad.
Faulty valve allowed crude oil to be released into a holding pit.
Bleeder valve was stuck in open position. Oil?
Information pending.
SOURCE: Modified from Maxim and Niebo 2001b.
vent discharges, ruptured lines, seal failures, explosions, and
various human errors (e.g., tank overfill, failure to ensure
connections).
Table F-5 describes the 10 largest product spills (71 to
450 bbl, or 2,982 to 18,900 gallons) on the North Slope dur-
ing the same period. Causes include broken fuel lines, corro-
sion, faulty valves, and human errors (e.g., accidental over-
fill). The 10 largest crude oil and products spills from TAPS
Pump Station 1 to Atigun Pass are listed in Tables F-1 and F-
6; most were generally caused by equipment malfunction or
operator error (Maxim and Niebo 2001b).
Environmental impact statements contain hypothetical
scenarios featuring spills greater than 1,000 bbl (42,000 gal-
lons). Most large spill scenarios involve a "blowout," that is,
loss of well control, which can occur due to (1) a failure of a
rig's blowout prevention equipment resulting in a surface
TABLE F-5 Ten Largest Products Spills on the North Slope, 1977-2000
blowout, or (2) a failure in the well' s cemented casing result-
ing in a subsurface blowout (Mallary 1998~. Pipeline fail-
ures, accidents, or even vandalism also can result in large
spills.
Fairweather (2000) distinguished between and event
(uncontrolled flow of liquids or gas from the wellbore, at the
surface) and an incident (when the pressure on the formation
fluids exceeds the pressure of downhole drilling fluids, but
does not result in uncontrolled flow at the surface). Table F-
7 lists all reported events (5) and incidents (6) on the North
Slope between 1977 and 2001. The events resulted in the
release of either dry gas or gas condensate resulted in minor
environmental effects (Mallary 1998~. No oil spills or fires
resulted from any of the events or incidents. Over this period
4,965 wells were drilled or redrilled (AOGCC 1998) so the
event/incident frequency is 5/4,956, or approximately 1 per
Number Date Volume (bbl) Description
1
6
7
9
10
22 Aug 81
31 Oct 82
3 l9May97
19 Jun 83
5 21 Nov 80
16 Oct 86
7 Feb 77
22 May 85
31 Jul 91
8 Jun 81
450
200
180
114
102
100
100
95
75
71
Corrosion caused a connection to fail. Material was contained on the pad.
Diesel tank was overfilled, spilling diesel into a secondary containment dike.
Broken needle valve on the fill line of diesel storage tank. Diesel drained into a lined
containment area.
Differential settlement of a temporary holding tank. Released material was released into dike
below tank.
Broken fuel line.
Broken fuel line.
Broken fuel line.
Faulty connection on a diesel tank truck.
Spray from hole in annulus.
Liner cracked due to extreme temperatures. Fluid contained within it seeped into the ground on
Challenge Island.
SOURCE: Modified from Maxim and Niebo 2001b.
OCR for page 213
APPENDIX F
TABLE F-6 Ten Largest Products Spills from TAPS, Pump Station 1 to Atigun Pass, 1977-2000
213
Number Date Volume (bbl) Description
1
6
7
14 Oct 88
27 Sep 92
12 Oct 79
4 20 Jun 82
5 12 Sep 77
9 Jan 86
19 Dec 90
19 Jun 79
24 Jun 86
10 16 Oct 78
203
190
95
86
83
52
43
39
36
21
Truck overturned at mile point 258 of haul road, spilling diesel fuel.
Tank truck overturned just north of Atigun Pass, spilling turbine fuel.
Gasoline spilled at Ice-Cut Hill due to operator error.
Tank valve at Franklin Bluffs camp left partially open, causing diesel fuel leak.
Diesel fuel spill at Pump Station 3, operator error.
Overturned trailer at Atigun pass, diesel fuel spill.
Tanker jack-knifed at mile point 85, spilling diesel fuel.
Loader caused diesel spill after excavating and rupturing a fuel line near the metering building
at Pump Station 1.
Leak in underground gasoline storage tank at Pump Station 1.
Equipment malfunction at Pump Station 4 temporary camp caused a diesel fuel spill.
SOURCE: Modified from Maxim and Niebo 2001b, TAPS Owners 2001.
thousand wells drilled. This is comparable in order-of-mag-
nitude terms to rates in other areas (Mallary 1998, S.L. Ross
1998a). The conclusion of these analyses is that blowouts
that result in large spills are unlikely. This finding has been
affirmed in several recent environmental impact statements
and may be attributable in part to the strengthening of drill-
ing regulations following the Santa Barbara blowout in 1969
(BLM/MMS 1998, MMS 2001a, Parametrix 1997).
The environmental assessment for the Alpine field in-
cludes a well blowout as a "reasonable worst-case" oil spill
(Parametrix 1997~. Similar analyses were made for both
Northstar and Liberty developments (S.L. Ross 1998a). The
spill contingency plan for the Kuparuk oil field includes a
hypothetical loss of well control scenario (Alaska Clean Seas
1999~. The plan details include a description of the hypo-
thetical event (location, date, duration, type of spill, weather
conditions, quantity of oil spilled) as well as descriptions of
how the discharge would be stopped, how to prevent or con-
trol fire hazards, a well-control plan, methods for tracking
oil, spill control, containment, and recovery actions. These
contingency plan features are now required by the Alaska
Department of Environmental Conservation (ADEC).
TABLE F-7 Loss of Well Control Event and Incidents
on the North Slope, 1977-2000
Number Type WellName Year Operator
1
6
7
Event
Event
Event
4 Event
5 Event
Incident
Incident
Incident
Incident
Incident
Incident
10
11
CPF1-23
F-20
J-23
Cirque #1
1-53/Q-20
Tunalik Test well #1
DS 15-21
Challenge Isl. #1
L5-36
3F-19
lH-15
1979 ARCO AK
1986 BP AK
1987 BP AK
1992 ARCO AK
1994 BP AK
1978 USGS
1980 ARCO AK
1981 Sohio AK
1989 ARCO AK
1996 ARCO AK
1996 ARCO AK
SOURCE: Modified from Maxim and Niebo 2001b.
Table F-8 lists the five largest North Slope oil spills that
have actually contacted tundra soil and damaged tundra veg-
etation during the period from 1977 to 1999. An additional
crude oil/produced water spill occurred in 2001. The area of
tundra affected by these spills ranges from 125 to 1,700 m2
(1,350 to 18,300 ft2) (McKendrick 2000b), with a total area
of tundra affected by crude oil and products spills on the
North Slope of about 20 acres (8 hectares) (McKendrick
2002~.
AGRA (2000) developed a tundra spills database as part
of a contract for ADEC. It contains information on approxi-
mately 200 spills of various sizes. Some general conclusions
can be drawn from a review of the data. First, large spills
tend to cover between 0.1 and 0.4 ft2 (0.01 to 0.04 m2) of
tundra per gallon of spilled material. Smaller spills have a
greater proportional coverage. Second, area coverage and
environmental effects vary with season. Spills during sum-
mer generally result in greater effects on tundra vegetation.
Some spills result from pinhole leaks in pipelines. These may
spray oil over a broad area, but oil tends to remain on surface
vegetation. These spills have fewer long-lasting effects than
spills in which oil reaches sediments and plant root systems.
Approximately 65-80% of all crude oil and products
spills were confined to an individual pad (BLM/MMS 1998~.
Spills not confined to a pad are usually confined to an area
adjacent to the pad or roadbeds off the tundra surface. Spills
TABLE F-8 Five Largest Crude Oil or Mixed Crude Oil/
Water Spills That Affected Tundra Vegetation on the
North Slope, 1977-1999
Year
Oil Field
Containment Area (m)
Tundra Affected (m)
1989
1994
1972
1993
1985
Kuparuk
Kuparuk
Prudhoe
Kuparuk
Prudhoe
5,800
930
560
400
350
1,700
465
220
200
125
SOURCE: McKendrick 2000b.
OCR for page 214
214
that occur during winter, on snow, are almost completely
removed from frozen tundra by spill response activities
(BLM/MMS 1998).
Spill Trends
Time trends in the data can reveal if progress has been
made in spill prevention. They also provide a basis on which
to forecast future spill volumes. It makes most sense to ex-
amine the time trend in the volume of crude and product
spilled, rather than the number of spills, because the report-
ing threshold for spills has decreased over time, and spill
reporting has improved. Therefore, any trend in the number
of spills is confounded with changes in reporting conditions.
For North Slope oil activities the most appropriate exposure
variable is the volume of crude or product spilled per unit of
production or throughput, the volumetric spill rate (VSR)
(Maxim and Niebo 2001b).
Figure F-5 shows annual VSRs for the North Slope
from 1977 to 1999. The graph shows that there is a great
deal of year-to-year variability in VSRs (solid line). The
"bad" years result from a few larger spills, and "good" years
from the lack of large spills. The large inter-annual vari-
ability makes it difficult to detect trends, especially modest
trends, but the data suggest that VSRs have decreased over
the years since North Slope production began. The fitted
trend (semi-logarithmic) for these data is shown by the
dashed line in Figure F-5. The slope of this line is negative,
suggesting perhaps some progress in reducing spill rates.
However, the percentage variation explained by this regres-
sion (R2 = 0.117) is relatively low, and statistical analysis
10
-
Q
Q
-
Q
Q
Cd
1
=
. _
Q
cn
.O
~ -I ~
APPENDIX F
of the regression coefficient indicates that such a trend
might have occurred due to chance (P = 0.07) (Maxim and
Niebo 2001b).
Although the apparent time trend is not statistically sig-
nificant, numerous modifications made to North Slope fa-
cilities and operations practices have been designed to re-
duce spills. In addition, the accuracy of oil spill data may
have increased after 1985 (MMS 2001a) or 1989 after the
Exxon Valdez spill (BLM/MMS 1998) and subsequent legis-
lation and regulations. The reporting threshold for spills has
decreased over the years, as well. Therefore, by today's stan-
dards, spills were probably underreported in earlier years
(Maxim and Niebo 2001b).
The introduction of improved technologies, engineering
designs, or operations practices designed to reduce spills
have been both continuous processes and triggered by dis-
crete events. Major ("step") changes in technology or proce-
dures often result from specific events (e.g., a large spill or
other accident) and regulatory responses to such events. The
key event for both regulatory and industry initiatives was the
Exxon Valdez spill in 1989. The Oil Pollution Act of 1990
was implemented along with regulations aimed at both pre-
vention and response. At the same time, oil companies ex-
amined and strengthened internal prevention and response
programs. Figure F-6 shows VSR data with separate average
values (dashed lines) calculated for the time periods prior to
and after 1990. The average value for the post-1990 time
period is 31% lower than for the years 1977 to 1989.
The VSR for the TAPS segment from Pump Station 1 to
Atigun Pass (Figure F-7) shows a statistically significant re-
duction over time.
10
0.1
0.1
1975 1980 1985 1990 1995 2000 1975
Year
FIGURE F-5 Volumetric spill rates for crude oil and products
spills associated with exploration and production activities on the
North Slope. Year-to-year variability may mask significance of fit
(p = 0.07~. SOURCE: Reprinted with permission from Maxim and
Niebo 2001b.
1
1--~--
1980 1985 1990 1995 2000
Year
FIGURE F-6 Volumetric spill rates for crude oil and products
spills associated with exploration and production activities on the
North Slope. Average VSR FRP, 1990-1999 is 31% lower than for
1977-1990. SOURCE: Reprinted with permission from Maxim and
Niebo 2001b.
OCR for page 215
APPENDIX F
100 -
10 -
_`
-
o 1-
. _
.F
-
-
a)
~ 0.1-
Q
U)
0.01 -
0.001 -
l
A
\
1980 1985 1990 1995 2000
Year
FIGURE F-7 Volumetric spill rate for crude oil and products
spills associated with the Trans-Alaska Pipeline from Pump Station
1 to Atigun Pass (semi-log scale). SOURCE: Reprinted with per-
mission from Maxim and Niebo 2001b.
Spill Prevention
State and federal regulatory agencies and the oil indus-
try have studied each spill incident, to develop "lessons
learned" and measures to reduce the likelihood and effects
of future spills. For example, the 575 bbl (24,150 gallons)
crude oil spill that occurred on 30 December 1993 (Table F-
2) resulted when wind-induced vibration caused a crack in a
Bowline leading from a well house to the manifold building.
Although this failure mode was anticipated and "first gen-
eration" wind-induced vibration dampers had been devel-
oped, they were not installed on this pipeline. Immediately
following the spill, the pipeline was fitted with a vibration
damper, along with all other pipelines not already fitted. The
design was also improved as a result (Norris et al. 2000~.
Dampers are required only on pipelines less than 24 in. (61
cm) in diameter, oriented perpendicular to prevailing east-
west winds and having a specific weld type (Norris et al.
2000).
Prevention of spills can be approached in two ways. The
first is changing engineering design and equipment, and the
second is changing operating procedures and practices. Table
F-9 includes examples of both kinds of changes that have
been implemented on the North Slope. The following dis-
cussion is descriptive and does not quantitively evaluate the
success of those methods.
Changes in Engineering Design and Equipment
Changes in engineering design or equipment include
new "vertical loop" technology to replace block valves, im-
215
TABLE F-9 Spill Prevention on the North Slopea
Changes in Engineering Design and Equipment
· Redesign of a component system to reduce probability of leak
(e.g., "vertical loops" replace valves in common carrier sales
pipeline)
· Use extra thick steel walls, fusion-bonded epoxy coating, and
cathodic protection to minimize corrosion leaks in pipelines
· Improve "smart pigs"
· Siemens-developed leak detection and location system
.
- Use system control and data acquisition system (SCADA) to
improve leak detection (similar to TAPS)
· Construct secondary containment around tanks
· Double-wall storage tanks
· Change pad grading to create a low spot in the center of the pad
· Development of improved well cellar spill containment system
Changes in Operating Procedures and Practices
· Location of major facilities
Avoid environmentally sensitive areas
- Location of storage tanks
Avoid river crossings
Avoid sensitive wetlands
· Use revised inspection and maintenance procedures (e.g., smart
pigs, more frequent inspections)
· Double checking connections before beginning fluid transfer
· Stepped up monitoring for corrosion
· Use of corrosion inhibitors
· Use drip pans to collect oil leaks from vehicles
· More/improved training and classes
aAfter Cederquist 2000, Guilders and Cronin 2000, Maxim and Niebo
2001b, MMS 2001a, Pavlas et al. 2000.
proved leak detection systems, developing and installing
double-wall storage tanks and secondary containment struc-
tures, alternative design of well cellars, and the use of
"smart" pigs.
The Alpine pipeline uses "vertical loops" in place of
block valves (Cederquist 2000, Pavlas et al. 2000~. Vertical
loops are regular expansion loops of the pipeline with the
outboard run lifted to a predetermined elevation. The loops
form a terrace structure that, in the event of a leak, limits oil
spilled due to drain down effects caused by pipeline eleva-
tion differences. Seven 40 to 45 ft (12 to 14 m) high vertical
loops were built into the 34 mi (55 km), 12 in. (30 cm) crude
oil pipeline. This design was recommended by an oil spill
isolation strategy study that systematically evaluated alter-
natives, including use of conventional block valves through-
out. The analysis concluded that, if used with emergency
pressure letdown valves or divert valves, vertical loops
would contain drain down related spills as well or better than
block valves while offering operations and maintenance ef-
ficiencies. Use of this technology eliminates the need for
remote and manually operated valves that can fail and/or
introduce additional leak sources at flanges, valve stems, and
fittings. Use of vertical loops is limited to relatively flat ter-
rain, which makes them applicable on flatter areas of the
North Slope (Maxim and Niebo 2001b).
Rapid and accurate leak detection can reduce the quan-
tity of crude oil or product spilled. Systems for leak detec-
OCR for page 216
216
tion include volume balance and mass balance systems (e.g.,
pressure point analysis). The recently developed Leak De-
tection Location System (LEOS) for monitoring ethylene
pipelines (Comfort et al.2000; Intec Engineering, Inc.1999)
has been modified for crude oil pipelines. It detects leaks by
periodically sampling the vapor within a special, permeable
tube strapped to the pipeline. The gas in the tube is sampled
by pushing a column of air past a gas "sniffer" at constant
speed. The sensor measures vapor concentration and relative
distance along the length of the tube, allowing determination
of the size and location of the leak.
A well cellar is a cement-lined containment structure
surrounding each well. The design was modified to reduce
the possibility of subsidence caused by melting permafrost
as well as improved containment of leaks and drips from
valves or fittings. Each cellar contains a drip pan.
Pigs are mechanical devices that are pushed through a
pipeline by flowing crude oil or product. Over the years, pig
design has become very sophisticated, leading to various
types of "smart" pigs. These pigs are used to monitor the
condition of the pipeline, initially establishing a baseline
against which future pigging (monitoring) results may be
compared. Three types of pigs are used. All can provide early
warnings of weaknesses where leaks might occur (Maxim
and Niebo 2001b).
· Caliper pig used to measure internal deformation
such as dents or buckling.
· Geometry pig records configuration of the pipeline
system and determines displacement.
· Wall thickness pig measures thickness of pipeline
wall.
North Slope pipelines are insulated to reduce heat loss
and reduce the likelihood of corrosion and failure. Weld pack
insulation was redesigned, adding a special coating to repel
moisture (Maxim and Niebo 2001b).
Containment is one of the generic strategies for spill
prevention. Containment prevents further release of spilled
material and makes cleanup easier. Measures to maximize
containment include double-wall pipes, double-wall tanks,
and secondary containment structures such as berms and
dikes (Pekich, personal communication, 2001, as cited in
Maxim and Niebo 2001b).
Changes in Operating Procedures and Practices
Changes in operating procedures and practices include
locating storage tanks to avoid environmentally sensitive
areas like river crossings, using drip pans to collect leaks,
and more frequent inspections. Drip pans are required for all
equipment parked on ice pads and roads (including pickup
trucks). All stationary tanks greater than 660 gallons have
secondary containment (Pekich, personal communication,
2001, as cited in Maxim and Niebo 2001b).
APPENDIX F
Several spill prevention initiatives are designed to in-
crease spill awareness and reduce human error. These in-
clude formal and informal training ("tailgate" or "toolbox"
meetings), formation of task forces, appointment of spon-
sors for various initiatives, and the development and revi-
sion of SOPs (standard operating procedures) and checklists
(Maxim and Niebo 2001b). Table F-10 is a checklist de-
signed to reduce errors in fluid transfer and transportation
operations.
Spill Response
Response Countermeasures
Research and development on spill response equipment
and strategies began after the Santa Barbara spill in 1969.
TABLE F-10 Fluid Transfer Safety Task Assignment
(STA) Card Information
Portable Tank Fluid Transfer Guidelines
Foreman:
Date:
Location/Iob:_
Truck/Tank #-
Driver:_
Volume:
Fluid:
All lines closed and secured, capped/plugged? yes
Portable (or permanent) dikes under truck engine? yes
yes
yes
yes
yes
yes
yes
yes
yes
yes
yes
yes
yes
Portable dikes under all connections?
Camlock seal rings checked?
Camlock ears locked and wires closed?
Assessment of tank condition before transfer?
Bonding cables connected?
Fluid level checked before loading?
Vents and hatches in proper position?
Sumps and accumulators drained?
Will product foam?
Frequent straps during transfer?
Tank filled to less than 90% capacity?
Inspect location prior to departure?
Comments:
Transportation STA Card Information
Tank Tie-in and Rig Checklist
Date:
Location:
Employee Assigned:
Foreman:
no
no
no
no
no
no
no
no
no
no
no
no
no
no
Inspect and report any existing contamination at site
All hoses and hardline properly connected and diked
All needle valve bleeds closed and capped
Inspect tanks (valves closed/capped, demisters, etc.)
Drip pans beneath all connections
Orange cones placed along hose/piping connections
Pressure test all flowback piping
SOURCE: Modified from Maxim and Niebo 2001b.
OCR for page 217
APPENDIX F
TABLE F-11 Major Research and Development Programs for Spill Prevention and Response
217
PREVENTION
1. Corrosion control system (Colegrove, personal communication, 2001; Pekich, personal communication, 2001)
2. Vibration dampers (Carn, personal communication, 2001; Ford, personal communication, 2001; Henry, personal communication, 2001; Norris et al. 2000)
3. Leak detection and location system (Comfort et al. 2000, Intec Engineering 1999)
4. Expanded vertical loops/antisiphons (Cederquist 2000; Lipscomb, personal communication, 2001; Pavlas et al. 2000)
5. Honzontal directional drilling with remotely located wells (Baker 2000)
RESPONSE
1. Forward Looking Infrared (FLIR) (Colegrove, personal communication, 2001)
2. Oil recovery from broken ice (Dickins arid Buist 2000, D.F. Dickins Associates Ltd. et al. 2000)
3. In-situ burning (S.L. Ross Environmental Research 1998b)
Viscous oil pumping (Majors, personal communication, 2001, S.L. Ross Environmental Research 2001)
5. Oil emulsion breakers (S.L. Ross Environmental Research 2001)
6. Tundra flush programs (Schuyler, personal communication, 2001)
7. LORI stiff brush skimming system (Majors, personal communication, 2001; S.L. Ross/D.F. Dickins 2001)
8. Mutual aid drill (Majors, personal communication, 2001)
9. New trench and weir design (Alaska Clean Seas 1999)
10. Oil spill response barge for arctic work (McHale 1999)
SOURCE: Modified from Maxim and Niebo 2001b.
Containment booms, skimming devices, absorbent and ad-
sorbent materials were all developed in the 1970s and have
been improved since that time. Since the Oil Pollution Act of
1990 there has been improved design and use of many spill
response and logistical support systems. Some of these have
been designed or modified with arctic conditions in mind;
some may be used anywhere. They include skimmers, fire
booms, igniters, air-cushion vessels, airboats, oil/ice proces-
sors, oil/water separators, and chemical dispersants. Air-
borne systems include those that monitor spilled oil, apply
dispersants, and ignite oil slicks (Allen 2000~. Table F-11
lists major research and development programs for spill pre-
vention and response on the North Slope.
Much effort has gone into developing these systems,
but they are seldom tested or used in training with real oil.
Experimental spills have been conducted in other countries,
but very few have been permitted in the U.S. since the early
1980s. The effectiveness of that response would likely im-
prove if responders had the opportunity to practice and test
equipment on real oil (Allen 2000, Lindstedt-Siva 1995),
although broken ice remains a major challenge for response
in the Arctic Ocean.
Although all oil spills on the North Slope have been
onshore, preparedness is required for both onshore and off-
shore spills. Alaska Clean Seas, an industry-funded oil
cleanup cooperative, is designated as the sole entity respon-
sible for training, purchasing and maintaining equipment,
and spill response, including cleanup. Equipment is stored at
various locations across the North Slope. Training and drills
are held on a regular basis, including mutual assistance drills,
tabletop drills, full-scale spill drills, and safety training.
Onshore Spills
Tundra vegetation can hold large quantities of oil, which
prevents oil from spreading over large distances but pro-
duces heavy concentrations of oil in the area affected. Stan-
dard treatment is low pressure flushing to mobilize the oil
and remove it, along with removal of the most heavily con-
taminated soils. Scraping the surface is designed to leave
plant parts (roots, rhizomes) intact so that sprouting will oc-
cur the following spring (Cater et al. 1999~.
Bioremediation has also been attempted with some suc-
cess by adding nutrients to the soil and removing snow to
increase the growing season (Cater et al. 1999~. Most tundra
soils contain adequate numbers of hydrocarbon-degrading
microorganisms, making in-situ bioremediation possible
through addition of nutrients (AGRA 2000~.
Most spills during winter on snow have been a light
surface aerial spray from a small pinhole. The pressure and
wind blow the oil over a relatively large area, but the coating
is light and does not penetrate the snow's surface crust. Veg-
etation that penetrates through the snow is contaminated.
Cleanup is by scraping the snow surface and the affected
vegetation and removing contaminated material. Tundra
growth is usually normal the following spring, but there have
been minor vegetation effects (M. Joyce, Independent Con-
sultant, personal communication, 6/7/2001~. Cleanup while
the ground is still frozen may prevent contaminants from
soaking into soil or the tundra mat (AGRA 2000~.
Large volume spills on snow melt the snow for some
distance down drainage. The oil eventually cools and is ab-
sorbed by the snow. Cleanup involves making snow berms
to contain the oil. Most oil stays on the frozen tundra sur-
face, so scraping the surface is the common cleanup method.
The worst-case condition is when some of the oil gets below
the frozen surface while it is still warm and can melt the
ground and migrate down slope. This kind of spill is cleaned
up as if it were a summer condition spill. Down-slope flow is
stopped with sheet piling or another barrier. Once contained,
contaminated soil and vegetation are removed and re-
mediation takes place in spring. The impacts of such a spill
OCR for page 218
218
are similar to a spring/summer spill (M. Joyce, independent
consultant, personal communication, 6/7/2001~.
Burning onshore spills has been tested on tundra, both
during winter and the summer growing season. Burning dur-
ing summer damaged plant communities. Burning during
winter had less impact on plants and did not harm perma-
frost. It may be a viable approach to spill cleanup in winter
(McKendrick and Mitchell 1978~. Burning was tried recently
on a small spill on tundra that the committee observed dur-
ing a site visit. The spilled oil (from a pinhole leak in a pipe-
line) was sprayed over tundra and seemed to contaminate
surface vegetation more than soil. Contaminated vegetation
was burned.
Spills that flow into running or standing water are con-
tained and removed using booms, skimmers, and sorbent
materials (AGRA 2000~. Spills on gravel pads are cleaned
by removing contaminated gravel according to ADEC stan-
dards (ADEC 2001~. Contaminated gravel is removed to a
central storage location. Periodically this gravel is reme-
diated and reused. Contaminated gravel is rarely left in place
but contamination beneath buildings or other structures that
prevent immediate removal may remain (van der Wende,
unpublished material, 2002~.
Offshore Spills
Even though there have been no major offshore spills
on the North Slope, methods used to control offshore oil
spills have been used for 30 years, during which time they
have been improved and refined. They are: mechanical con-
tainment and recovery, in-situ burning, and chemical disper-
sion. The fate of oil spilled in the ocean is discussed later in
this appendix.
Mechanical Control
Mechanical containment and recovery equipment is
used to contain oil spilled on water and recover it from the
water surface. Containment booms are devices that float on
the water surface with an extension (skirt) below the surface.
Floating oil contacts the boom that holds it, and may thicken
it. Booms are often used in combination with skimmers of
various designs that remove oil concentrated within the
boom from the water surface. Booms may also be used to
deflect spilled oil from a sensitive area. Some booms have
been especially adapted for use in ice-infested waters
(Abdelnour et al. 2000~. The benefit of mechanical recovery
is that it removes the oil from the water surface. The disad-
vantage is that the containment and recovery process is slow,
and it usually removes only a small percentage of the spilled
oil (Allen 1999~.
In most areas of the U.S., mechanical containment and
recovery of spilled oil is the first choice of most regulatory
agencies. Logistical and efficiency problems increase under
the common adverse conditions in the arctic. During freeze-
APPENDIX F
up and break-up unstable ice conditions can significantly
reduce chances of reaching and recovering spilled oil safely
and effectively (Allen 2000~. Much research has been con-
ducted, and the design of skimmers, booms, and oil/water
separators has been improved (Abdelnour et al. 2000, Allen
2000, S.L. Ross Environmental Research 2001~.
In the fall of 2000 a series of exercises, using popcorn to
simulate oil, were held to evaluate the effectiveness of me-
chanical control and recovery techniques using equipment
and methods called for in North Slope contingency plans.
Broken ice conditions ranged from 30% to 70% ice coverage
(Robertson and DeCola 2001~. The aim of the exercise was
to establish realistic maximum response operational limits
(RMOL). A barge-based recovery system was tested and
RMOL's were determined to be (Robertson and DeCola
2001~:
0-1% in fall ice conditions
10% in spring ice conditions without ice management
~ 30% in spring ice conditions with extensive ice man-
agement
These numbers are only estimates, but they strongly suggest
that reliance on mechanical recovery to clean up spills on the
North Slope is unlikely to be successful.
Since recovery of spilled oil in broken ice conditions
remains a major challenge, development of such technology
has been a research and development priority (S.L. Ross
Environmental Research Ltd.1998a). North Slope operators
established a study team to examine options to deal with oil
spills during freeze-up and break-up and define the realistic
maximum response operating limitations. The main conclu-
sion of this study team was that "mechanical containment
and recovery techniques have limited application for a large
spill, especially one from an open-orifice blowout" (D.F.
Dickins Associates Ltd. et al. 2000~.
In-situ Burning
If oil is of sufficient thickness and has sufficient volatile
components, it can be ignited and burned. On open water,
this technique may involve special booms, igniting agents,
and methods to deliver them. There has been much research
and development on this technique because it is especially
applicable in the arctic (Allen 1999~. The benefits of burning
are that it removes the oil from the environment and it may
be more efficient than mechanical recovery, especially in
the arctic where a slick may be contained by ice. The disad-
vantage is that burning oil produces smoke plumes. Another
disadvantage is a limited "window of opportunity" when
burning is possible. Evaporation of the oil's most volatile
components or formation of a water-in-oil emulsion can ren-
der a slick not ignitable. S.L. Ross Environmental Research
(1998b) studied the "window of opportunity" for in-situ
burning of oil on water in the arctic. They found that apply-
ing chemical breakers to emulsions contained in fire resis-
OCR for page 219
APPENDIX F
tent booms can allow otherwise
successfully.
Chemical Dispersion
ignitable slicks to burn
Dispersants are applied to the surface of an oil slick.
They act at the oil-water interface, reducing interracial ten-
sion and breaking the slick into tiny droplets that disperse in
the water column (S.L. Ross 2000a). Dispersants are most
effective if used early, during a fairly narrow window of
opportunity. Dispersants are most effective on fresh, low-
viscosity oils (S.L. Ross 2000a). The benefits of dispersion
are that large slicks can be treated in a short time from the
air, and they remove the slick from the surface. Present day
dispersants are all less toxic than oil, and applied at lower
concentrations than oil. Therefore, dispersant toxicity is less
important than toxicity of the dispersed oil (NRC 1994~. The
disadvantage is that, if effective, dispersion introduces a
plume of dispersed oil into subsurface water where it may
affect water column and shallow benthic communities. This
is usually a very short-term exposure due to the effects of
dilution and currents. Disperseants are probably not appro-
priate for highly viscous oils (S.L. Ross 2000a). Regulatory
agencies generally have not made disnersants a crioritv for
North Slope spills.
Pumping Viscous Oils
Most North Slope crude oils form stable emulsions.
Weathered but unemulsified oils may have viscosities as
high as 10,000 centistokes (cSt). Emulsions formed from
these oils may have viscosities of 100,000 cSt or more. Such
high viscosities pose problems for spilled oil recovery ac-
tivities because pumping these oils is difficult. Solving this
problem is another research and development initiative. Sev-
eral possible techniques might be used to reduce the viscos-
ity of emulsified oils, including heating, use of chemical
additives to break the emulsion, and use of chemicals to serve
as drag reduction agents. Another technique that has been
proposed is annular water injection to reduce line pressures.
A relatively small volume of water is injected through a spe-
cifically designed flange. The flange causes the water to form
a thin layer that coats the inside wall of the hose or pipe,
lubricating the flow of fluid and reducing line pressure
(Maxim and Niebo 2001b).
Spill Monitoring
Forward Looking Infrared (FLIR) technology was origi-
nally developed by the military for reconnaissance and tar-
geting. Since FLIR became available for civilian application
it has been adapted for oil spill monitoring. It is carried in an
observation aircraft (e.g., DeHaviland Otters) to detect spills
along pipelines and pads. It is useful for both prevention and
response. It makes possible early detection, and therefore,
219
the ability to minimize the spill volume and extent (Maxim
and Niebo 2001b). It makes it possible to determine the loca-
tion and extent of a spill and to distinguish between oil and
other substances that may look like oil to the human eye.
The airborne FLIR can be used to monitor both onshore and
offshore spills.
Research and Development
Restoration and Remecliation
The most extensive remediation of a spill on moist-
sedge tundra was done following the 2U spill, which oc-
curred in August 1989. This was a spill of 600 bbl (25,200
gallons) of crude oil and produced water that leaked from a
valve in the Kuparuk oil field operated by ARCO Alaska.
The leak sprayed oil below the pipeline. It pooled and spread
downhill, contaminating 1.43 acres (0.60 hectares) of moist
and wet tundra, posing several cleanup and remediation chal-
lenges (Cater et al. 1999~. This was the first relatively large
spill on tundra in the Kuparuk oil field, so information was
lacking on long-term effects of oil spills on tundra, espe-
cially the effectiveness and effects of cleanup and reme-
diation methods. The ADEC set stringent standards for
remediation, the vegetation in the spill must return to "nor-
mal." Normal was to be measured by vascular plant ground
cover when compared to adjacent, uncontaminated tundra.
The ADEC standard for total petroleum hydrocarbons (TPH)
in soil was 500 ppm. After the spill, the most heavily con-
taminated areas near the pipeline had concentrations of
16,000 ppm TPH (Cater et al. 1999~.
During the cleanup, oil sorbents were spread over the
area. Low-pressure water flushing with warm and cold
water was used to remove oiled sorbent material, along
with raking and swabbing. Multiple, short flushes were
used to prevent damage to underlying permafrost. Ply-
wood boardwalks were used to prevent trampling. The
most severely contaminated soils were removed by scrap-
ing off the upper 2 to 5 cm (0.8 to 2 in.), leaving subsur-
face plant parts (e.g., rhizomes, roots, stem bases) intact.
Undisturbed or moderately contaminated areas were not
touched. Bioremediation using indigenous microorgan-
isms, adding nutrients, and keeping moisture stable was
also used to reduce oil concentrations in soil. Nutrients
and fertilizers were added to enhance indigenous commu-
nities of microorganisms. Snow was removed in spring to
lengthen the growing season and increase soil tempera-
ture. After two summers, the ADEC vegetation require-
ments were achieved. As of 1996, the hydrocarbon con-
centrations in the soil were 687 ppm, still exceeding
ADEC standards of 500 ppm TPH, although there was a
95% reduction from the post-spill concentrations (Cater
et al. 1999~. Since this was so close to the ADEC stan-
dard, the state approved the cleanup (M. Joyce, Indepen-
dent Consultant, personal communication, 6/7/2001~.
OCR for page 220
220
Concentrations of oil in soil decreased very rapidly over
the first four years, then very slowly after that (Jorgenson,
unpublished material, 2001~.
As a result of the 2U spill and cleanup, ADEC asked
ARCO Alaska to do some experiments using surfactants to
enhance oil removal from tundra vegetation and soil. Sev-
eral surfactants were tested, and it was found that small
amounts of Dawn(D liquid dishwashing detergent mixed with
water enhanced oil removal. Multiple, short flushes were
used to prevent damage to underlying permafrost. This
method greatly enhanced the recovery of spilled oil and had
no measurable effect on tundra vegetation (Cater et al. l999~.
(Dawn(D has also been used to clean oiled birds.)
Seeding has been used to reestablish plant cover in ar-
eas where tundra has been damaged by spills. Fertilizer is
also applied, with or without seeds. Fertilization acceler-
ated and improved recovery of mosses, grasses, fortes, and
shrubs. Seeding may enhance recolonization initially, but
natural stocks eventually replace introduced plants (AGRA
2000).
Estimates of Future Spills
Future spill volumes depend on projected values for the
VSR and future throughput, neither of which can be forecast
with certainty. One projection of future North Slope produc-
tion is that an additional 7 billion bbl (294 billion gallons) of
crude oil will be produced from 2004 to 2034, the antici-
pated period of the TAPS right-of-way renewal (TAPS Own-
ers 2001~. If there is no improvement in the volumetric spill
rate (VSR, barrels spilled per million barrels produced), the
future value will be equal to the 1977 to 1999 average, ap-
proximately 0.86 bbl/million bbl. This amounts to approxi-
mately 6,000 bbl (252,000 gallons), an average of approxi-
mately 200 bbl (84,000 gallons) per year during the period
2004 to 2034. If the apparent trend is valid, the spill volumes
would be lower by 31 %. If North Slope production increases,
spill volumes will increase accordingly.
An alternate method of forecasting spill volumes is used
by MMS (Amstutz and Samuels 1984; Anderson and
LaBelle 1994; LaBelle and Anderson 1985; MMS 1987a,b,
1990a,b, 1996, and 2001a; Smith et al. 1982~. This method
calculates the frequency of large spills (greater than 1,000
bbl) per billion barrels of oil produced. Since no large spills
(according to the MMS definition) have occurred on the
North Slope, the threshold was reduced to 500 bbl (21,000
gallons) for spill projections for the Liberty field (MMS
2001a). There have been two crude oil spills greater than
500 bbl (21,000 gallons) during the period from 1977 to
1999. Barrels of oil produced over the period were 12.76
billion (535.92 billion gallons), therefore the spill rate is 0.16
spills per billion barrels. MMS (2001a) estimated that there
would be 2.74 large spills during the period from 2004 to
2034. These are conservative estimates because they make
no allowance for improvement (Maxim and Niebo 2001b).
APPENDIX F
FATE OF OIL LIKELY TO BE SPILLED
ON THE NORTH SLOPE
When oil is spilled into the environment, the fate and
effects are determined by the amount and type of oil spilled,
the time of year, the environment into which it is spilled, and
to some extent, the control and cleanup/restoration methods
used. Oil composition and physical characteristics govern its
movement, weathering process, and the impacts it has on
affected environments. When oil is spilled, it begins to natu-
rally degrade, both physically and chemically. This process
is known as weathering and includes spreading, evapora-
tion, dispersion, emulsification, microbial degradation, and
photo-oxidation. The weathering process is also affected by
winds, waves, and currents (BLM/MMS 1998, MMS 2001a,
USACE 1999~.
BEHAVIOR OF OIL IN THE BEAUFORT SEA
Oil spilled during the summer season of open water will
spread and weather like other spills in cold waters, influ-
enced primarily by winds and currents. During freeze-up,
winter, and break-up, oil will interact with ice and its fate
and behavior will be modified accordingly (D.F. Dickins
Associates Ltd. et al. 2000~.
Freeze-up
Oil/ice interactions during freeze-up vary with the stage
of ice development and ice form (frazil, grease, slush, pan-
cakes, nilas, etc.) as well as the properties of the spilled oil
(density, viscosity). All varieties of ice may exist simulta-
neously and may change from one form to another rapidly.
The progression from less to more mature ice types may be
fairly linear at nearshore sites like Endicott and West Dock
but can be nonlinear at locations like Northstar. At nearshore
sites, freeze-up progresses from frazil and grease ice to stable
new ice in less than a week. Farther offshore, this process
may take three weeks or more (D.F. Dickins Associates Ltd.
et al. 2000~.
The main factors influencing the degree of oil incorpo-
ration into porous developing ice forms (slush, grease, frazil)
are oil density and turbulence in the upper water column.
The breakdown of oil into suspended particles is also con-
trolled by oil viscosity. Heavier Bunker products are more
likely to be break into larger particles, and are less likely to
rise to the surface. Most of the oils found in the study area
are of lower density and therefore will surface due to buoy-
ant forces (i.e., the density difference between oil and the
ice/water mixture). In most situations in the nearshore Beau-
fort, the turbulent mixing energy in the developing ice field
is low compared to open water. Oil droplets or particles of
fresh North Slope crude oils will be small enough to rise
freely through developing ice (D.F. Dickins Associates Ltd.
et al. 2000~.
OCR for page 221
APPENDIX F
There have been opportunities to observe oil in devel-
oping and broken ice during spills of opportunity and field
experiments. D.F. Dickins Associates Ltd. and colleagues
(2000) describe several of these that, in their opinion, are
most applicable to Beaufort Sea conditions. Their general
observations and conclusions follow (D.F. Dickins Associ-
ates Ltd. et al. 2000~:
1. Landfast ice, when present, provided a protective bar-
rier preventing shoreline contamination.
2. Oil released from under the ice surfaced in leads as
they opened.
3. Rough ice such as rubble and rafting ice led to thick
oil pools and limited spreading.
4. Crude oil migrated to the surface of slush ice.
5. Barriers of snow and slush in a refreezing lead pre-
vented further oil spreading.
6. Oil continued to evaporate after being mixed or cov-
ered by snow.
7. Wind herding created thicker oil layers at the down-
wind edge of leads.
8. Oil mixed with slush ice and stopped spreading.
9. Most of the spilled oil remained at or near the surface.
10. There is no redistribution of substantial amounts of
oil from water onto the surface of ice pancakes or small
floes.
11. Oil falling on new or young broken ice under freez-
ing conditions will remain on the ice surface, effectively
sorbed by the briny, damp, developing ice and/or snow. In
spring, however, a portion of the oil spilled onto melting ice
floes may run off the surface into surrounding water.
12. Most oil spilled subsurface into a developing ice
field will be held in concentrated pockets on the underside of
the ice. Trapped oil will move with the ice except where
there are localized openings in the ice cover or leads where
oil can spread on the water surface in the absence of slush.
These conditions are short-lived at freeze-up. Open water is
unlikely to persist for long at low temperatures.
~ ~ O *__
In the absence of wave action, evaporation is the only
significant weathering process that will affect a spill during
freeze-up. Evaporation occurs more slowly in the arctic than
in temperate climates. However, in a few days to a week, sur-
face oil will lose about the same volume as it would in warmer
situations. The result is an increase in density, viscosity, pour
point, and fire point of the spilled oil. If pour point exceeds the
ambient temperature, the oil will gel. The most likely form of
spilled oil remaining after freeze-up is a relatively thick, snow-
filled, weathered slick at the ice surface, covered by snow
(D.F. Dickins Associates Ltd. et al. 2000~.
Winter
If oil is spilled under stable, land-fast ice in winter, ini-
tial spreading will probably be limited to hundreds of meters
221
from the spill source, based on currents and ice storage ca-
pacity (D.F. Dickins Associates Ltd. et al. 2000~. Cox and
Schultz (1980) found that minimum currents that would
move crude oil under a smooth ice sheet were approximately
0.15 m per second (0.50 ft per second), increasing to ap-
proximately 0.21 m per second (0.70 ft per second) under
the slightly rougher ice representative of midwinter condi-
tions. Under-ice currents in the Beaufort are typically very
low (D.F. Dickins Associates Ltd. et al. 2000~.
Another typical phenomenon is encapsulation of
spilled oil beneath growing ice that may occur when new
ice forms beneath oil trapped under ice. Encapsulation by
new ice immobilized the spill quickly, typically within 12
to 72 hr. depending on the time of year. A number of stud-
ies have observed this in every month of the ice-growth
period from October to May (Dickins and Buist 1981,
NORCOR 1975~.
Oil spilled under ice from a chronic leak may not be-
come encapsulated in the manner described as long as there
is a continued source of fresh oil. Although there are no di-
rect observations, it seems likely that frazil present in the
water beneath the ice will continue to form and float up into
the oil pool as it deepens. At the same time, surrounding
unoiled ice will continue to grow and contain the oil from
spreading beyond the initial area of oiling. Calculations
based on typical ice growth rates show that leaks on the or-
der of 60 bbl (2,500 gallons) per day will be contained in an
area approximately 91 m (300 ft) in diameter via this mecha-
nism. The slush/oil mixture will remain a viscous fluid,
gradually deepening over time as the cumulative volume in-
creases (BP 1998c).
Normal variations in first-year ice thickness provide
natural "reservoirs" that may confine spilled oil to a smaller
area compared with an identical volume of oil spilled on
open water (D.F. Dickins Associates Ltd. et al. 2000~.
Oil spilled on the ice surface in winter does not spread
rapidly due to the presence of snow and natural small-scale
ice roughness features. Very little oil is likely to remain un-
der or in the ice at this time.
Vertical migration of oil starts when the expulsion of
brine from the warming ice opens pathways to the surface
(Dickins and Buist 1981, NORCOR 1975~. Beginning as
early as April, and accelerating through May and June, oil
will rise to the surface from wherever it is trapped within or
beneath the ice. The rate of oil migration increases once
daily air temperatures consistently remain above freezing
(D.F. Dickins Associates Ltd. et al. 2000~. The rate of oil
migration through an ice sheet is affected by the depth
of the oil lens trapped within the sheet (small, isolated oil
particles take longer to surface) and the viscosity of the
oil (heavier or emulsified oils take longer to rise though
brine channels) (Buist et al. 1983, Dickins and Buist 1981,
NORCOR 1975~.
Oil weathering in winter depends primarily on whether
or not the spilled oil is exposed to atmosphere. Oil spilled
OCR for page 222
222
under an ice sheet will not evaporate, but oil spilled on top of
ice or into leads does (Dickins and Buist 1981, Nelson and
Allen 1982, NORCOR 1975~.
Oil spilled under ice in winter will be encapsulated into
the downward-growing ice sheet. As this process occurs,
some oil components may dissolve into underlying water.
As is typical, this amounts to only about 1 % of the total oil
(D.F. Dickins Associates Ltd. et al.2000~. No further weath-
ering of encapsulated oil occurs until it is exposed to the
atmosphere when it appears on the ice surface the following
spnng.
The formation of water-in-oil emulsion is unlikely with
oil spilled under ice since the mixing energy needed to form
an emulsion is not present. For the same reason, natural dis-
persion is expected to be negligible as well (D.F. Dickins
Associates Ltd. et al. 2000~.
Break-Up
First ice breakup and the appearance of open water takes
place in late May and early June, extending to final breakup
in July. The rapid disappearance of nearshore ice in early
June is triggered by river overflood (D.F. Dickins Associ-
ates Ltd. et al. 2000~. Ice concentrations are highly variable
and changeable.
If oil is spilled under ice, it will surface on floes or in
leads as ice melts. As the rotting floes fracture and break into
progressively smaller ice features any oil on the surface or in
the porous structure of the ice will gradually enter the water
and create localized sheens and patches. Throughout break-
up, both residual oil trapped in porous ice and oil on the
surface of melting floes will gradually be released to water
as sheens and broken thin films. Some oiled floes can strand
on shorelines or along barrier islands. The ice will most
likely melt in place and release oil into beach sediments (D.F.
Dickins Associates Ltd. et al. 2000~.
There is an important difference between oil among bro-
ken ice during break-up and freeze-up. There is no slush in
the water at break-up. This plus extended daylight, warming
temperatures, and decreasing ice concentrations and thick-
ness all combine to make spill response more likely to be
effective during break-up (D.F. Dickins Associates Ltd. et
al. 2000~.
Once the encapsulated oil is exposed to the atmosphere,
it will begin to weather. Evaporation of light components is
the dominant process until the ice sheet breaks up at this
time wave action can cause emulsification and natural dis-
persion of slicks on water (D.F. Dickins Associates Ltd. et
al. 2000~.
Oil in meltpools is herded by wind against the edges of
the pools. Such slicks may reach approximately 10 mm
(0.40 in.) in thickness. Thicker oil will evaporate more
slowly than thin slicks and films but will eventually achieve
approximately the same degree of evaporation as slicks on
open water. Emulsification of oil in meltpools is not ex-
APPENDIX F
pected to be significant because most are too small to allow
generation of wind waves of sufficient size. Rainfall
may cause some emulsification, but it is likely to be tempo-
rary and unstable (D.F. Dickins Associates Ltd. et al.
2000~.
When an ice sheet deteriorates and breaks into floes, oil
remaining in meltpools will be discharged onto water be-
tween floes primarily in the form of thin sheens trailing from
drifting, rotting ice. Once exposed to significant wave ac-
tion, fluid oil will begin to emulsify and naturally disperse.
Weathering occurs more rapidly as temperatures increase
(D.F. Dickins Associates Ltd. et al. 2000~.
The implications of these findings for responses to
spills are from D.F. Dickins Associates Ltd. and colleagues
(2000~.
· Fresh crude oil from both surface and subsurface spills
will reside naturally at or near the surface in newly forming
ice (grease, nilas).
· Ice acts as natural containment, restricting further
spreading from the point where oil contacts the ice surface.
However, the presence of ice does not necessarily result in
thick films or act to thicken oil once it has spilled.
· All aspects of spill behavior, including spreading and
weathering, are greatly affected by the presence of ice. In
many cases, the overall effect is to slow or prevent normal
weathering and to limit the area of contamination.
· Snow covering oil on ice slows, but does not stop,
evaporation.
· Emulsification and dispersion are reduced to almost
zero in the presence of any substantial ice cover.
· Attempts at mechanical recovery operations during
freeze-up will result in fracturing of the ice and mixing of oil
and ice. This would reduce opportunities to recover or burn
oil after ice has stabilized.
· Slush or grease ice at freeze-up effectively stops oil
from spreading.
· Lack of slush between floes at break-up means the oil
is more accessible for recovery and/or burning.
· If the pour point of spilled oil exceeds the ambient
temperature, oil on the ice surface will gel. The likely form
of most spilled oil remaining after freeze-up is a relatively
thick, snow-filled, weathered slick at the ice surface, cov-
ered by snow.
· Oil that is spilled under solid, growing ice from freeze-
up until April is quickly encapsulated by a new ice layer,
which grows beneath the oil.
· Oil trapped in ice does not weather (frozen emulsions
do not break).
· Oil encapsulated within an ice sheet from a winter spill
will naturally rise to the surface beginning in May (excep-
tions are viscous crudes and emulsions).
· Oil remaining on the ice surface at the downwind edges
of meltpools in June and July will be naturally concentrated
by wind herding. This facilitates in-situ burning.
OCR for page 223
APPENDIX F
Summer
In summer when there is open water, more response
options exist. Depending on wind and wave conditions,
booming and skimming operations may be effective. In-situ
burning using fire booms to concentrate oil is also an option.
In some cases, application of chemical dispersants may also
be effective, although that does not seem to be a primary
strategy on the North Slope.
Offshore
Oil spilled on water spreads due to its relatively low
density and forms an oil slick. The spreading rate and thick-
ness of a slick is influenced by currents, wave action, and the
temperature of the water (S.L. Ross Environmental Research
2001, USACE 1999~. Temperature has an important effect
on spreading and weathering. At low temperatures, oil is
thick and viscous and does not spread as readily as oil spilled
in more temperate waters. Viscosity increases as oil weath-
ers, and that can influence the rate of dispersion and emulsi-
fication as well (MMS 2001a, USACE 1999~.
Evaporation weathers oil by preferentially degrading the
lighter hydrocarbons, reducing the overall volume of the
spilled oil, and increasing its viscosity. Evaporation varies
linearly with temperature faster in warm temperatures,
slower in cold temperatures (BLM/MMS 19981.Oil slicks in
broken ice or on ice evaporate slowly, while oil encapsu-
lated in ice does not evaporate until it is released during the
melting process (BLM/MMS 1998, USACE 1999~. Fresh-
water ice and multiyear ice may not melt during spring thaw
and could keep oil from evaporating for years. (The benefit
is that the oil is contained and the opportunity exists for a
removal project.) For Prudhoe Bay oil, it is estimated that
20% of the oil would evaporate within 30 days following a
summer spill or a spring thaw of ice containing a winter spill
(BLM/MMS 19981. Similarly, 25-30% of Northstar crude
oil released to surface waters would evaporate within the
first 30 days based on average temperatures (USACE 1999~.
The Liberty EIS (MMS 2001a) conservatively estimates that
13-16% of this oil spilled to open water or broken ice will
have evaporated. Liberty oil contains more wax and is more
viscous than other oils produce on the North Slope (MMS
2001a). Evaporation decreases the toxicity of spilled crude
oil as the lighter, more toxic hydrocarbons dissipate. The
remaining heavier components may persist in soils and sedi-
ments. Even though they are less toxic they may cause
chronic, sublethal effects in some instances.
Dispersion and dissolution occurs when oil and water
are mixed either by waves, wind, or currents and oil becomes
mixed into the water column. Dispersion may also occur
when grinding occurs in broken ice conditions forcing wa-
ter, oil, and ice to mix (MMS 2001a).
Emulsification occurs when water and ice are mixed to
form a mousse. This creates two problems regarding spill
223
cleanup. First, emulsification increases the volume of fluid
that must be handled, and second, the viscosity of the result-
ing emulsion can be as much as 1,000 times that of the parent
oil, challenging conventional removal and pumping tech-
niques (S.L. Ross Environmental Research 2000a). Emul-
sification is greatly enhanced in broken ice conditions
where grinding ice may form mousse an order of magnitude
more rapidly than in open water (BLM/MMS 1998, MMS
2001a).
Microbial degradation may account for a substantial
portion of spilled oil removal from marine sediments and
shorelines (USACE 1999~. Although microbial degradation
played a significant role during the Exxon Valdez spill, it is
uncertain if it will be as significant in colder North Slope
environments. Lower temperatures, limited populations of
hydrocarbon utilizing microorganisms, lack of available nu-
trients, and poor water circulation on the North Slope may
hinder microbial degradation of spilled oil (USACE 1999~.
Sedimentation and photo-oxidation are other, less sig-
nificant ways that oil can naturally degrade. Sedimentation
occurs when oil particles adsorb to suspended particulate
matter and sink to the sea floor. This process can trap oil in
seafloor sediments where it may persist (USACE 1999~.
Based on their specific gravities and viscosities, none of
the crude oils produced on the North Slope will sink natu-
rally, but will remain at the surface when spilled (S.L. Ross
Environmental Research 2000b). Sinking could occur if oil
adsorbs to sediment particles. This has happened in the
nearshore waters where there is a high sediment load and
mixing energy. It can also result from cleanup activities that
mobilize oil that then flows into the nearshore area.
Onshore
Oil spills on tundra are not expected to spread over large
areas. The relatively flat coastal summer tundra has a dead-
storage capacity of 1.3 to 5.8 cm (0.5 to 2.3 in.), which would
retain 74,000 to 370,000 bbl (3.1 million to 15.5 million gal-
lons) of oil per km2 (BLM/MMS 1998~. When oil is spilled
on snow-covered tundra, oil spreading is limited because
snow acts as a natural barrier. However, if a pressurized pipe-
line ruptures and oil sprays into the air, it can become widely
dispersed on tundra or snow. The nearly constant wind on
the North Slope may carry the sprayed oil downwind, depos-
iting it over a large area. BLM/MMS (1998) reported that a
spill of 1 to 4 bbl (42 to 168 gallons) of crude oil sprayed
mist oil over 100 to 150 acres (40 to 60 hectares).
To better understand the effects of crude oil spills in the
arctic, a small amount of oil was intentionally released in a
small pond on the North Slope in the summer of 1970. The
spill was intended to simulate and average sized spill to a
water body during summer. The pond was monitored for
nearly a decade. The spill began spreading and evaporating
almost immediately. After 24 hr the oil slick had thickened
and was pushed by wind to the down-wind side of the pond.
OCR for page 224
224
Over time the oil spread into vegetation on the down-wind
side of the pond and at the end of the first summer was con-
fined to the pond-bottom and vegetation surrounding the
down-wind margins. An estimated 50% of the oil evaporated
or degraded within a year. During subsequent years, some
pond-margin plants were unable to sprout through the oil film
there and subsequently died. Additionally, there were measur-
able, long-term (several year) effects to zooplankton, phy-
toplankton, and insect populations, plus shorter-term effects
on benthic algae and microbe populations (BLM/MMS 1998~.
SCENARIOS OF OIL SPILLS
Beaufort Spill Scenarios
Oil field operators are required to prepare spill scenarios.
Each scenario describes spill location, volume, and cause;
type of oil; sea, wind, and ice conditions; weather; and spill
trajectory. Countermeasures are detailed as well. Scenarios
range from small spills to the "realistic maximum oil dis-
charge." The scenarios reviewed were in Oil Discharge Pre-
vention and Contingency Plans required the by Alaska state
government.
Pipeline Leak
This scenario is a catastrophic subsea pipeline failure
during freeze-up. Spill volume is 2,150 bbl (90,300 gallons).
Landfall of the spill on barrier islands is predicted, along
with possible impacts on culturally important sites. Shore-
line cleanup will be necessary. Some oil will be entrapped in
ice. Both mechanical recovery and in-situ burning are rec-
ommended spill control measures.
Well Blowout
This scenario is a well blowout during summer, result-
ing in a 15,000 bbl (630,000 gallons) spill, 1,000 bbl (42,000
gallons) per day over 15 days. Most of the oil (12,800 bbl
[540,000 gallons]) spills on tundra. Tundra ponds are also
contaminated. Tundra cleanup and rehabilitation are imple-
mented, along with oil recovery from ponds using booms
and sorbent materials. Effects on birds are expected, and a
bird rescue and rehabilitation program is implemented. The
ocean is also contaminated and spill control measures are
implemented there. Shoreline cleanup will probably also be
necessary.
APPENDIX F
Chuichi Spill Scenarios
Additional scenarios were prepared for the Chukchi Sea
based on assumptions of offshore drill rigs and subsea pipe-
lines (Lewbell and Galloway 1984~.
Pipeline Rupture
This scenario is a ruptured subsea pipeline in late sum-
mer spilling 5,000 bbl (210,000 gallons) of crude oil in 24
hr. It is assumed the pipeline leak is stopped after that time.
There is a 61% chance that landfall of oil will occur be-
tween Point Franklin and Point Barrow. Within 30 days, of
the oil remaining at sea, 40% would still be on the water
surface, 40% dispersed in the water column, and 20%
evaporated.
Another pipeline rupture scenario, a 500 bbl (2,100 gal-
lons) spill during spring, assumes trapping of some oil under
ice and freezing in place. There is a 61% chance of oil com-
ing ashore within 10 days. Oil trapped in ice could move as
far as 480 to 800 km (300 to 500 mi) northwestward.
Well Blowout
This scenario is a June blowout from a wellhead under
a drillship, spilling 1,000 bbl (42,000 gallons) per day for
75 days. Landfall of oil is predicted in 33 hr. Under most
expected conditions, most of the oil would be transported
seaward to the northeast. It could travel 350 km (220 mi) in
75 days.
All of the above scenarios predict oil concentrations in
the water column of 1 to 7 ppb (Lewbel and Galloway 1984~.
If a spill should occur nearshore, along the Barrow Arch,
during winter, the oil might become incorporated within the
new ice forming at the edge of the coastal polynya, advected
within the polynya, or incorporated into ridges when the
polynya closes. Depending on which way the ice is moving
at the time, the oil could either be moved offshore with the
ice (most likely) or onshore to be released at breakup. The
exposure of various portions of the Barrow Arch coastline to
spilled oil depends on the site of the spill and the weather at
the time. Open coastal areas are more likely to be contami-
nated by spills than areas protected by barrier islands. Sea-
ward sides of barrier islands are as vulnerable as open coasts.
Most lagoons behind barrier islands are protected from oil
contamination by these islands. Some lagoons are more vul-
nerable (Lewbel and Galloway 1984~.
OCR for page 225
APPENDIX F
225
North Slope Oil Spill Events Timeline
1977-1984
(Modified from Maxim and Niebo 2001b)
Years 1977 to 1979
1980 to 1984
General 1968 Pru&oe Bay discovery announced
Events 1974 Pru&oe Bay to Yukon River road construction
completed
1975 First pipe laid at Tonsina River
1976 to 1979 the Petroleum Reserve explored by USGS
1977 Pipeline completed
1977 Oil production at Pru&oe Bay begins.
1977 1,800 bbl spill at TAPS check valve 7
1977 30 bbl crude oil spill at TAPS Pump Station 1
1977 One 100 bbl products spill, North Slope
1977 83 bbl diesel fuel spill at Pump Station 3
1978 21 bbl diesel fuel spill at Pump Station 4
1979 1,500 bbl crude oil spill at Atigun Pass
1979 95 bbl gasoline spill at Ice-cut Hill
1979 39 bbl diesel fuel spill at Pump Station I
Technological
Advances
Regulatory
Events
1980 to 1985 U.S. Fish and Wildlife conducts
biodiversity assay in the Arctic National Wildlife Refuge
1980 One 102 bbl product spill, North Slope
1980 6 bbl crude oil spill at TAPS Pump Station 2
1981 Oil production begins at Lisburne oil field; oil
discovered 1967
1981 Oil production begins at the Kuparuk oil field; oil
discovered 1969
1981 1,500 bbl crude oil spill at TAPS check valve 23
1981 5 bbl crude oil spill at TAPS Pump Station 1
1981 71 bbl product spill, North Slope
1982 200 bbl product spill, North Slope
1982 86 bbl diesel fuel spill at Franklin Bluffs camp
1983 to 1984 U.S. Department of Energy develops new
studies to assess impacts of Arctic Energy
development (R&D program)
1984 August 22, 1984; largest NS product spill (450 bbl)
1984 11 bbl crude oil spill at TAPS Pump Station 3
1984 5 bbl crude oil spill at TAPS Pump station 4
1983 Oil companies hold six oil spill cleanup training
exercises/demonstrations
1983 ABSRB changes name to Alaska Clean Seas
~
1979 Alaska Beaufort Sea Response body (ABSRB)
is formed as the precursor to Alaska Clean Seas
to operate as ANS spill response equipment co-op
1979 "Smart Pigs" are developed as a spill
prevention tool
1969 TAPS files for pipeline right-of-way permits
1970 Lawsuits filed to stop pipeline construction
1973 Trans-Alaska Pipeline Authorization Act
becomes law
1974 State right-of-way lease issued
1979 As a spill prevention policy, the State of
Alaska limits seasonal exploratory drilling
operations to winter months when the Beaufort
Sea is covered by sea ice
1982 Original 1979 seasonal drilling laws are revised
into two tiers to facilitate exploratory drilling
1984 State of Alaska finds:
(1) In-situ burning is the most important component of
spill response in broken ice.
(2) Volume of oil expected to be recovered by
mechanical means is secondary to in-situ burning
(3) Igniting surface well blowouts can remove the
majority of the oil at the wellhead
(4) Seasonal restrictions impact Alaska economy
(5) Lessees participate in 5-year oil spill research and
development program
(6) Increased training for drilling personnel is required
(7) Lessees must be capable of in-situ burning operations
(8) Drilling is restricted past barrier islands during
bowhead whale migration
(continued)
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226
APPENDIX F
North Slope Oil Spill Events Timeline (continued)
1985-1994
Years 1985 to 1989
1990 to 1994
General 1984 One 125 bbl crude oil spill, North Slope
Events 1985 Oil production begins at Milne Point; oil was
discovered there in 1969
1986 One 175 bbl crude oil spill, North Slope
1986 52 bbl diesel fuel spill at Atigun Pass
1986 36 bbl gasoline spill, underground storage tank
at Pump Station I
1987 Oil production begins at Endicott oil field
1987 One 120 crude oil spill, North Slope
1987 Scientific investigation of petroleum
development in the Arctic Refuge is done with
regard to impact on specific species
1988 203 bbl diesel fuel spill, mile point 258 of haul road
1989 Exxon Valdez spill
1989 July 28, 925 bbl crude oil spill at Milne Point
Central Processing Flowstation; largest NS
crude oil spill
1989 Mixed oil and water spill from production Bowline
at 2U impacts tundra; clean-up and remediation
1989 5 bbl crude oil spill at TAPS Pump Station 2
1989 Industry conducts first mutual assistance drill
Technological
Advances
Regulatory
Events
1990 One 75 bbl products spill, North Slope
1990 43 bbl diesel fuel spill at mile point 85, near Pump
Station 3
1991 Oil is discovered at the Badami oil field
1992 190 bbl turbine fuel spill just north of Atigun Pass
1993 Oil production begins at Point McIntyre; oil was
discovered there in 1988
1993 Four crude oil spills totaling 1,470 bbls, North
Slope
1994 Oil production begins at Niakuk oil field; oil was
discovered there in 1985
1994 18 bbl crude oil spill at Pump Station 1
1985 to 1989 Alaska Clean Seas focuses on oil in ice
spill response
1989 Detergent flushing schemes are used on the
North Slope to enhance spilled oil recovery
1989 First use of wind-induced vibration dampers
for spill prevention
1990 to 1993 Industry upgrades spill response capability
in the state; state focuses attention on shipping in
Prince William Sound
1993 Wind-induced vibration dampers are installed on
some short intra-pad Bowlines for leak prevention
1990 Alaska Clean Seas charged with slope-wide spill
response training and equipment maintenance and
inventory
Mixed oil and water spill from lYlR Flowline; clean-up
response incorporates lessons learned
Aggressive corrosion control programs are developed
Pipeline weld insulation designs are improved
Drip pans are used to prevent small spills
1990 State of Alaska passes oil spill statutes
1990 Oil Pollution Act of 1990 passed
1991 State of Alaska reiterates Tier II drilling restrictions
1991 Cessation of exploratory drilling in the Canadian
Beaufort
1993 ADEC promulgates new regulations based on oil
spill statutes:
(1) Establish a response planning standard of being
able to contain and cleanup the worst-case
discharge in 72 hr
(2) Primary response option is identified as
mechanical containment and recovery
(3) In-situ burning is a response option only if
mechanical C&R is not viable
(continued)
OCR for page 227
APPENDIX F
227
North Slope Oil Spill Events Timeline
1995 Present
Years 1995 to Present
General 1996 Projects to develop the Alpine field are announced
Events 1996 Northstar development begins and issues of response capability in the Arctic offshore during periods of broken ice are
reconsidered
1997 Oil is discovered at Sourdough
1997 One 180 bbl product spill, North Slope
1998 Northstar oil spill contingency plan submitted
1998 Oil is discovered in the Sambucca and Midnight Sun Prudhoe Bay satellite oil fields
Technological 1997 Extended vertical loops and antisyphons are used on the in place of check valves; this reduces the potential
Advances for leaks
1999 LEOS system is installed on Northstar to aid in pipeline leak detection
Second generation of wind-induced vibration damper is developed
FUR first used on Alaska North Slope
2000 The use of HDD to lay pipe below the Colville River is nominated for ASCE 2000 Outstanding Civil Engineering
Achievement of the year
2000 Research and development on spills in broken ice leads to tactics for responders
2000 Studies show that historical loss of well control has lead to no oil spills and minor environmental impacts
2000 By 2000, approximately 30,000 pipeline segments are fitted with wind-induced vibration dampers as a spill prevention
technique
2001 Well cellar designs which reduce the potential for spills to the environment are developed
Regulatory
Events
1997 Joint industry and agency task force is set up to consider North Slope oil spill response issues
1997 ADEC identifies oil spills in broken ice as a major issue
1999 Northstar oil spill plan approved by ADEC
1999 Fall testing program conducted as part of Northstar, Endicott, and Pru&oe Bay contingency plan conditions of approval
Representative terms from entire chapter:
crude oil
