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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
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.
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.
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.
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.
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.
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.
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-
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.
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
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-
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~.
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~.
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
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.
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.
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~.
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)
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)
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