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Oil in the Sea III: Inputs, Fates, and Effects D Oil and Gas Extraction ACCIDENTAL DISCHARGE FROM PLATFORMS Volumes of petroleum hydrocarbons introduced into North American waters from accidental discharge on offshore platforms are relatively well known for the U.S. Outer Continental Shelf and Canada, but data from offshore Mexico and coastal waters in the United States are generally lacking. Data bases used in this report include the Minerals Management Service Spill Data Base, the 1999 PEMEX Safety, Health and Environmental Report, Canadian Environmental Report, and data on pipeline spills in coastal waters are from the U.S. Coast Guard (see detailed discussion of spill data used, available at http://www4.nationalacademies.org/dels/oilannex.nsf). Table D-1 lists the amount of petroleum hydrocarbons spilled into the sea in the offshore waters from 1990 to 1999. A total of 149 spills occurred during this ten year period, discharging some 556 tonnes into marine waters. Of the 556 tonnes spilled in the past ten years, eighteen accidental spills in 1995 account for nearly a third of the total. The average annual amount discharged in offshore waters, based on the MMS data base, is 55.6 tonnes per year. Removing a few non-hydrocarbon spills from this data base and adding additional spills from the U.S. Coast Guard data base resulted in an average calculated discharge of 57.0 tonnes per year. Platform discharges in other North American waters were somewhat more difficult to obtain as data bases were not systematically collected during the past decade. In Canadian east coast waters, a total of 280 tonnes has been spilled into the sea during the period 1990 through 1999 (Table D-2), resulting in an average annual discharge of 28.0 tonnes TABLE D-1 Summary of Outer Continental Shelf (U.S.) Data Base of Oil and Gas Facilities Spill Data, 1990-1999 Annual Oil Spillage From Offshore Platforms in US Waters (1990-1999) Year Number Spills (>100 gal) Tonnes Spilled Gallons Spilled Avg. Spill Size (Tonnes) Avg. Spill Size (Gallons) 1990 18 26.66 7,510 1.48 417 1991 17 72.75 19,996 4.28 1,176 1992 12 36.45 10,500 3.04 875 1993 6 5.40 1,470 0.90 245 1994 18 50.39 14,083 2.80 782 1995 18 175.73 54,696 9.76 3,039 1996 20 52.95 15,038 2.65 752 1997 12 44.47 13,291 3.71 1,108 1998 16 46.25 12,865 2.89 804 1999 12 45.15 12,983 3.76 1,082 Total 149 556.20 162,432 3.53 1,028 SOURCE: Minerals Management Service; Analysis by Environmental Research Consulting
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Oil in the Sea III: Inputs, Fates, and Effects TABLE D-2 Summary of Oil and Gas Facilities Spill Data for the East Coast of Canada, 1990-1999 Total Spillage Year Tonnes U.S. Gallons 1990 0.0 0 1991 0.0 0 1992 13.4 3,948 1993 2.6 756 1994 2.9 840 1995 248.5 7,308 1996 1.6 462 1997 4.0 1,176 1998 6.4 1,890 1999 1.0 294 Ave. 28.0 1,667.4 Max. 248.5 7,308 Min. 0.0 0.0 (8,200 gallons). The number of platforms existing in offshore Mexican waters is relatively small, but in U.S. coastal waters, there are a significant number of shallow-water platforms, especially in the northern Gulf of Mexico. Approximately 877 petroleum facilities were located in U.S. coastal waters in 1992 (Federal Register, December 16, 1996, p.66089). Using scattered data bases from the U.S. Coast Guard, several state reports, and estimating the number of offshore platforms in Mexican waters (130 platforms), a calculated volume of 61.0 tonnes (18,000 gallons) appear to be a reasonable estimate of discharge from these facilities. Thus, in North American coastal waters, a total annual load discharged is calculated at 89.0 tonnes per year (28.0 tonnes in Canadian waters plus 61.0 tonnes in other coastal waters). Thus, an estimated total of 146.0 tonnes have been discharged annually into North American waters by accidental spills and blowouts from offshore oil and gas facilities in U.S.offshore., U.S. coastal waters, Canadian and Mexican waters. Tables 2-2 through 2-6 includes annual average petroleum hydrocarbon load from accidental discharges, reported between 1990 and 1999, from offshore oil and gas facilities in the four zones where reliable data was available. These average annual loads were calculated from accidental discharges reported in a known latitude and longitude (and thus represent a subset of the numbers reported in Table D-3). Note that in Tables 2-2 through 2-6, that approximately 90% of the total discharges from production facilities occurred in Zone G (central and western Gulf of Mexico) and of that amount, nearly 50% was within coastal waters. SPILLS FROM OFFSHORE PIPELINES Pipeline spill data for North American waters were obtained from two data sets: U.S. Coast Guard and the Minerals Management Service. Table D-4 shows the total and average pipeline spills from 1990 through 1999 in offshore North American waters (MMS data base). Additional spills, as determined from the U.S. Coast Guard data base, resulted in a calculated annual volume of discharged petroleum hydrocarbons in offshore waters to be 59.0 tonnes. In coastal waters, the only reliable data was from the U.S. Coat Guard data base (Table D-5). The data base, however, included spills from facilities and contained non-crude spills. These were removed, and a calculated volume of 1,100 tonnes per year was calculated. It is estimated that there are 23,236 miles of pipelines in offshore North American waters (DeLuca and Leblanc, 1997), thus the average accidental discharge per mile of pipeline would be 0.074 tonnes per pipeline mile. These calculations do not include spills from pipelines in Mexico as the data was not available. The number and length of pipelines in Mexico are relatively small when compared to those in the United States and it is though that the volume spilled is proportionate. Canadian data was available, but no discharges were reported. Using these scattered data bases, an annual total discharge into Norh American waters by accidental spills from pipelines is calculated to be 1,690 tonnes per year. Offshore Oil and Gas Production and Pipeline Spill Summary Thus, the total documented average volume of petroleum hydrocarbons accidentally discharged from offshore facilities (platforms and pipelines) per year into North American waters during the past decade is 1,836 tonnes (Tables D-3 and Tables 2-2 through 2-6). INTERNATIONAL SPILLS FROM PLATFORMS AND PIPELINES Internationally, the amount of petroleum introduced to the sea from oil/gas production and pipeline spills and blow TABLE D-3 Summary of Calculated Inputs from Offshore Oil and Gas Facilities for North American and Worldwide Waters North American Waters Other Waters Worldwide Total Oil/Gas Production Facilities 146.0 tonnes 144.0 tonnes 290.0 tonnes Pipeline Spills 1,690.0 tonnes 4,410.0 tonnes 6,100.0 tonnes Total 1,836.0 tonnes 4,554.0 tonnes 6,390.0 tonnes
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Oil in the Sea III: Inputs, Fates, and Effects TABLE D-4 Summary of Offshore Pipeline Spill Data for North American Waters, 1990-1999 Annual Oil Spillage From Offshore Pipelines in US Waters (1990-1999) Year Number Spills (>100 gal) Tonnes Spilled Gallons Spilled Avg. Spill Size (Tonnes) Avg. Spill Size (Gallons) 1990 9 2,621.15 779,882 291 86,654 1991 19 22.89 6,300 1 332 1992 9 319.97 86,730 36 9,637 1993 7 13.72 3,780 2 540 1994 2 599.74 190,684 300 95,342 1995 4 4.96 1,344 1 336 1996 4 25.65 6,952 6 1,738 1997 8 6.11 1,693 1 212 1998 6 1,559.60 430,214 260 71,702 1999 7 500.34 135,611 71 19,373 Total 75 5674.13 1,643,190 97 28,587 SOURCE: Minerals Management Service; Analysis by Environmental Research Consulting outs is even harder to estimate as data is even more difficult to acquire. As of 1993, there were 3,182 additional offshore oil and gas facilities located in non-North American waters (International Association of Oil and Gas Producers, 2000). If it assumed that the average amount of petroleum hydrocarbons spilled by these platforms was similar to those found in North American waters, the estimated additional average spill volume would be 115.0 tonnes per year (0.036 tonnes per platform per year). Comparison of this calculation with scattered data from the North Sea and offshore Africa tended to indicate that the computed figure was extremely low. Using the data cited above, an average of 0.045 tonnes per platform (reflecting a 25 percent increase in the per platform release rate1) was used to compute the volume discharged into the sea by non-North American platforms. The resulting computed value is 144.0 tonnes per year. It is the opinion of the committee that this number is still low, but until more systematic data is collected worldwide on discharges from platforms, a more precise volume is lacking. Thus, on an annual basis, an estimated 290.0 tonnes are spilled into the world’s oceans by all offshore oil and gas platforms (Table D-3). DeLuca and LeBlanc (1997) estimate that there are 59,512 miles of offshore oil and gas pipelines in the major oil producing countries of the world (North America not included). Again, this number is probably too low by as much as 30%, but these are the only published figures available. If it is assumed that the average amount of petroleum hydrocarbons discharged per mile of pipeline in North America is (0.074 tonnes per year per pipeline mile), then an additional 4,410 tonnes are discharged into the other world’s oceans by non-North American pipelines. Thus, on an annual basis, TABLE D-5 Summary of Pipeline Spill Data in North American Coastal Waters, 1990-1999 Tonnes U.S. Gallons Year No. Spills Total Ave./Spill Total Ave./Spill 1990 25 2,919.99 116.80 791,317 31,653 1991 5 1,095.85 219.17 296,975 59,395 1992 22 1,010.06 45.91 273,726 12,442 1993 11 1,438.91 130.81 389,945 35,450 1994 22 11,344.55 515.66 3,074,373 139,744 1995 13 53.97 4.15 14,626 1,125 1996 19 3,670.65 193.19 994,746 52,355 1997 10 1,401.77 140.18 379,880 37,988 1998-1999 17 530.14 31.18 143,668 8,451 Total 144 23,465.89 6,359,256 Ave./Year 16 2,607.32 706,584 1 Assuming that non-North American platforms release 25 percent more petroleum per year is a somewhat subjective figure, but reflects the lack of worldwide standards. In other words, while some regions set standards as high as North American producers operate under, these standards are not uniformly applied worldwide. Thus, the adjustment is conservative in that it reflects the assumption that less regulated operations are more prone to release petroleum.
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Oil in the Sea III: Inputs, Fates, and Effects 6,100 tonnes per year of petroleum hydrocarbons are discharged into the world’s oceans by pipeline spills. Using the estimates cited above, the total amount of petroleum hydrocarbons discharged into the world’s oceans by offshore oil and gas facilities is 6,390 tonnes per year (290.0 tonnes—platforms; 6,100.0 tonnes—pipelines; Table D-3). ESTIMATES OF VOLATILE ORGANIC COMPOUND Introduction During the production, transport, and refining of hydrocarbons, volatile compounds escape to the atmosphere. Some, like methane, are light and rise or degrade rapidly. Heavier compounds, like hexadecane, react or rise more slowly. These heavier hydrocarbons are labeled as volatile organic compounds (VOC) and are defined in the U.S. Clean Air Act to include all volatile hydrocarbons except methane, ethane, a wide range of chlorofluorocarbons (CFC), hydrochloroflourocarbons (HCFC), and a few others, e.g., acetone. A complete listing of the constituents is given in Table D-6. Unfortunately the definition provides no exact ratio of carbon to compound. As a practical definition, the list contains most compounds above propane (C3H8, 82 percent carbon) and below hexadecane (C16H34, 85 percent carbon). The focus of this section is on estimating the amount of VOC generated from offshore production platforms. Sections B and C include estimates of VOC generated during tanker transport and marine terminal loading. The estimates exclude other potential sources of VOC released from coastal or near-river refineries, storage tanks, etc. Prior to 1990, VOC from production platforms received little attention and no estimates were provided by NRC (1985, 1975) or GESAMP (1993). One reason is that VOC data just started to appear in the late 1980s. Another reason is that the overall contribution to the sea was thought to be small. That’s in part because the scavenging of VOC from the atmosphere to the sea is inefficient and highly dispersed. At most a few percent of VOC ever make it to the sea, and these are spread over a large area compared to the scale of the generation source. General Methodology While data collection on VOC has improved, it remains crude and sparse on a worldwide basis. Regulators have made estimates for the U.S. Gulf of Mexico (offshore) and California. These estimates are not actual measurements but are calculated usually from an inventory of equipment multiplied by an estimated VOC emission rate for each piece of equipment. Producers have made estimates for the Mexican Gulf of Mexico and the producing basins of the northeast Atlantic (North Sea, Norwegian Sea, etc.), but documentation of their methods could not be found. In all cases, there is no information on the uncertainty in their estimates or speciation (percent occurrence of each compound) of the VOC, an important factor when considering how much of the VOC might make it back to the sea or what its toxic effect might be. Still, the situation in the above regions is better then the other offshore producing areas where no estimates were found. Oil and Gas Producers (1994) describes four methods for estimating VOC (and other emissions) from offshore operations. The simplest, Tier 1, estimate is based on total production volume and tends to be conservative. Developing the higher tier estimates requires details concerning platform-specific oil types, fuel consumption, equipment, etc. Since there are thousands of offshore facilities and no central databases, it would be a daunting task to apply these higher tier methods on a worldwide basis or even for North America. MMS has required the Gulf of Mexico operators to provide a Tier 3 estimate by the summer of 2001 but not in time for this report. For the reasons cited above, the Tier 1 method was used in this report. It requires an estimate of the production volume and a VOC rate per unit produced. E&P Forum (1994) provides estimates based on the information available at the time but a review of the literature revealed more recent and detailed information. Table D-6 shows the VOC rate for the four regions where VOC estimates have been made. The source of these numbers is given in later discussions. The average of the rates is given in the last row. Mexico (Pemex, 2000) has reported the lowest rate, which was roughly five times lower then in the northeast Atlantic and nearly three times lower then in the U.S. Gulf of Mexico. The smallness of the Mexican number was surprising especially when compared to the U.S. Gulf numbers where oil types were similar and production methods are likely to be at least as clean. Unfortunately no insight was offered into how the Mexican number was calculated so it was difficult to determine the source of the difference. Consequently we took the Mexican rate at face value. It is of some interest to compare the E&P Forum (1994) VOC rates to those in Tables 2-2 through 2-6. The E&P rate for the N. E. Atlantic of 1.1 × 10−3 (based on an average of the E&P values for Norway and the U. K.) compares well to the 1.17 × 10−3 developed in this study. The only other common region is the Gulf of Mexico. Here the E&P estimate of 2.2 × 10−3 is about four times larger then developed in this study. The source of the discrepancy is fairly obvious: E&P based their estimates on an EPA estimate that was not as recent as the MMS estimates used in this study. E&P also provides estimates for Canada but these are based on onshore fields in Alberta, not a particularly good basis. The lowest VOC rate in Tables 2-2 through 2-6 was used to estimate the lower bound estimate of VOC for each region, and the highest VOC rate was used to estimate the upper bound estimate. For regions where no VOC were published, the best estimate of VOC emissions was calculated by multiplying the average in Tables 2-2 through 2-6 by the
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Oil in the Sea III: Inputs, Fates, and Effects TABLE D-6 Hydrocarbon Compounds Considered VOC by the EPA Interpretation of the U.S. Clean Air Act (40 CFR 51.100) (s) Volatile organic compound (VOC) means any compound of carbon, excluding carbon monoxide, carbon dioxide, carbonic acid, metallic carbides or carbonates, and ammonium carbonate, which participates in atmospheric photochemical reactions. 1.) This includes any such organic compound other than the following, which have been determined to have negligible photochemical reactivity: -methane -ethane -methylene chloride (dichloromethane) -1,1-trichloro-ethane (methyl chloroform) -1,1,2-trichloro-1,2,2-trifluoroethane (CFC− 113) -trichlorofluoromethane (CFC−11) -dichlorodifluoromethane (CFC−12) -chlorodifluoromethane (HCFC−22) -trifluoromethane (HFC−23) -1,2-dichloro 1,1,2,2-tetrafluoroethane (CFC−114) -chloropentafluoroethane (CFC−115) -1,1,1-trifluoro 2,2-dichloroethane (HCFC−123) -1,1,1,2-tetrafluoroethane (HFC−134a) -1,1-dichloro 1-fluoroethane (HCFC−141b) -1-chloro 1,1-difluoroethane (HCFC−142b) -2-chloro-1,1,1,2-tetrafluoroethane (HCFC−124) -pentafluoroethane (HFC−125) -1,1,2,2-tetrafluoroethane (HFC−134) -1,1,1-trifluoroethane (HFC−143a) -1,1-difluoroethane (HFC−152a) -parachlorobenzotrifluoride (PCBTF) -cyclic, branched, or linear completely methylated siloxanes -acetone -perchloroethylene -tetrachloroethylene -3,3-dichloro-1,1,1,2,2-pentafluoropropane (HCFC− 225ca) -1,3-dichloro-1,1,2,2,3-pentafluoropropane (HCFC−225cb) -1,1,1,2,3,4,4,5,5,5-decafluoropentane (HFC 43−10mee) -difluoromethane (HFC−32) -ethylfluoride (HFC−161) -1,1,1,3,3,3-hexafluoropropane (HFC−236fa) -1,1,2,2,3-pentafluoropropane (HFC−245ca) -1,1,2,3,3-pentafluoropropane (HFC−245ea) -1,1,1,2,3-pentafluoropropane (HFC− 245eb) -1,1,1,3,3-pentafluoropropane (HFC−245fa) -1,1,1,2,3,3-hexafluoropropane (HFC−236ea) -1,1,1,3,3-pentafluorobutane (HFC−365mfc) -chlorofluoromethane (HCFC−31) -1 chloro-1-fluoroethane (HCFC−151a) -1,2-dichloro-1,1,2-trifluoroethane (HCFC−123a) -1,1,1,2,2,3,3,4,4-nonafluoro-4-methoxy-butane (C4F9OCH3) -2-difluoromethoxymethyl-1,1,1,2,3,3,3-heptafluoropropane (Cf3)2CFCF2OCH3) -1-ethoxy-1,1,2,2,3,3,4,4,4-nonafluorobutane (C4F9OC2H5) -2-(ethoxydifluoromethyl)-1,1,1,2,3,3,3-heptafluoropropane (CF3)2CFCF2OC2H5) -methyl acetate -perfluorocarbon compounds that fall into these classes: i.) Cyclic, branched, or linear, completely fluorinated alkanes; ii.) Cyclic, branched, or linear, completely fluorinated ethers with no unsaturations; iii.) Cyclic, branched, or linear, completely fluorinated tertiary amines with no unsaturations; and iv.) Sulfur containing perfluorocarbons with no unsaturations and with sulfur bonds only to carbon and fluorine. 2.) For purposes of determining compliance with emissions limits, VOC will be measured by the test methods in the approved state implementation plan (SIP) or 40 CFR, part 60, Appendix A, as applicable. Where such a method also measures compounds with negligible photochemical reactivity, these negligibly reactive compounds may be excluded as VOC if the amount of such compounds is accurately quantified, and the enforcement authority approves such exclusion. 3.) As a precondition to excluding these compounds as VOC or at any time thereafter, the enforcement authority may require an owner or operator to provide monitoring or testing methods and results demonstrating, to the satisfaction of the enforcement authority, the amount of negligibly reactive compounds in the source’s emissions. 4.) For purposes of federal enforcement for a specific source, the EPA shall use the test methods specified in the applicable EPA-approved SIP, in a permit issued pursuant to a program approved or promulgated under title V of the Act, or under 40 CFR, part 51, Subpart I or Appendix S, or under 40 CFR, parts 52 or 60. The EPA shall not be bound by any state determination as to appropriate methods for testing or monitoring negligibly reactive compounds if such determination is not reflected in any of the above provisions. 5.) As discussed more fully in Appendix H, ignoring the substantial atmospheric reactions and using the physical properties of decane result in a very conservative calculation, likely overestimating hydrocarbon loadings to the oceans from these sources. Under this simple scenario, equilibrium calculations show that less than 0.2 percent of the released VOC are deposited to surface waters, even under these very conservative conditions. Thus the values reported in Chapters 2 and 3 are 0.2 percent of the estimated mass released reported in Table D-7. volume of oil produced in the region. Otherwise the published VOC rates were used to calculate the best estimate of VOC emissions. When viewing the tables in this section, it should be kept in mind that these are total estimated VOC released to the atmosphere. These estimates will later be used in Section E to estimate the total VOC going back to the sea. North American Estimates Table D-7 summarizes the estimated VOC emissions for producing platforms in the various zones of North America. Five columns are shown for each zone. Columns 2-4 show the lower, best, and upper limits of the estimated annual tonnage of VOC discharged to the atmosphere. Column 5 shows
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Oil in the Sea III: Inputs, Fates, and Effects TABLE D-7 Estimates of VOC (Kilotonnes/yr) Released and Offshore Oil Produced (Kilotonnes/yr) in North America during 1995 Offshore Air Emissions (VOC, k-tons per year) Offshore Zone >10% 50% <-90% Oil Produced (k-tons/yr) Source Oil Production Rate (kbbl/day) Description of Region A > 3 mi 0 0 0 0 0 Canadian Arctic west of Hudson Bay A < 3 mi 0 0 0 0 B > 3 mi 0 0 0 0 0 Canadian Arctic east of Hudson Bay B < 3 mi 0 0 0 0 C > 3 mi 0 0 0 0 0 Canadian Maritime provinces C < 3 mi 0 0 0 0 D > 3 mi 0 0 0 0 0 Maine to Virginia D < 3 mi 0 0 0 0 E > 3 mi 0 0 0 0 0 N. Carolina to Florida Straits E < 3 mi 0 0 0 0 F > 3 mi 0 0 0 0 API XI-15 Eastern GOM (MI and east) F < 3 mi 0 0 0 0 API XI-15 G > 3 mi 9 28 59 50,410 API XI-15 942 Western GOM (LA & west) G < 3 mi 1 2 5 4,422 API XI-15 83 H > 3 mi 22 22 138 117,742 PEMEX 1999 Annual report 2,200 Campeche H < 3 mi 0 0 0 0 I > 3 mi 0 0 0 0 0 West coast of Mexico I < 3 mi 0 0 0 0 J > 3 mi 2 3 12 10,621 API XI-15 198 S. California J < 3 mi 1 1 3 2,907 54 K > 3 mi 0 0 0 0 0 N. California K < 3 mi 0 0 0 0 L > 3 mi 0 0 0 0 0 Oregon/WA coast L < 3 mi 0 0 0 0 M > 3 mi 0 0 0 0 0 Western Canada M < 3 mi 0 0 0 0 N > 3 mi 0 0 0 0 API XI-15 SE Alaska including Cook Inlet N < 3 mi 1 4 8 6,919 API XI-15 129 O > 3 mi 0 0 0 0 0 Bering, Chukchi, Beaufort Seas O < 3 mi 0 0 0 0 P > 3 mi 0 0 0 0 0 Puerto Rico, Virgin Is. P < 3 mi 0 0 0 0 Q > 3 mi 0 0 0 0 Q < 3 mi 0 0 0 0 0 Hawaii, W. Pacific North America 36 60 226 193,020 3,607 W. Europe 41 254 381 216,859 API XI-2 4,052 Africa 30 88 188 160,718 API XI-2 3,003 Middle East 34 99 211 180,520 API XI-2 3,373 S. America 10 29 62 53,412 API XI-2 998 Asia & Pacific 38 113 240 205,513 API XI-2 3,840 E. Europe/Russia 2 6 13 11,185 API XI-2 209 World Wide Total 191 649 1,322 1,214,247 19,082 VOC(ton)/oil(k-ton)/yr VOC(k-ton/yr)/Oil(kbbl/day) Calif VOC/kbbl= 2.80E-04 0.015 GOM VOC/kbbl= 5.61E-04 0.030 PMEX= 1.87E-04 0.010 UK/Norway VOC/kbbl= 1.18E-03 0.063 avg= 5.42E-04 0.029
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Oil in the Sea III: Inputs, Fates, and Effects the estimated annual tonnage of offshore oil produced for the year 1995 from API (2001). The year 1995 was the most recent year included in API (2001). Note that most of the rows are “zero” because there is no offshore production in those zones in 1995. Estimates for VOC rates in the U. S. Gulf of Mexico come from the Minerals Management Service (MMS, 1994, OCS Study MMS 94-0046; Gulf of Mexico Air Quality Study, Vol. 1 Summary of Data Analysis and Modeling). The VOC rates are based on measurements in 1993 and projected here to 1995 using production rates derived from API (2001). It should be noted that MMS estimates for VOC rates are based on only a two-month summer sampling program involving two platforms offshore Texas and Louisiana within the land-sea breeze corridor. Clearly this is a small data set with considerable uncertainty. Nevertheless the number seem to be consistent with the other sites in Tables 2-2 through 2-6. VOC for Southern California (zone K) were calculated from numbers provided by the California Air Resources Board (CARB) inventory for 1997 in the Santa Barbara Channel (available on request from www.arb.ca.gov). Actual VOC in Table D-7 were calculated using the California VOC rate times the 1995 production from API (2001). These VOC rates are by far the most accurate estimates since they were based on detailed component (valves, internal combustion engines, etc.) counts multiplied by an assumed VOC emission rate per component (Tier 3 level). The best estimate for Alaskan offshore platforms were based on the GOM VOC rates times the relevant 1995 production from API (2001). The best estimate of total VOC released in North America in 1995 is 60 kilotonnes/year with a lower bound of 36 kilotonnes/year and upper bound of 226 kilotonnes/year. Worldwide Estimates Table D-7 summarizes the worldwide estimates. It shows a best estimate of 649 kilotonnes per year with lower and upper bounds of 191 and 1,322 kilotonnes per year, respectively. VOC rates for the U.K. sector were provided by U. K. Offshore Operators Association (http://www.ukoaa.co.uk). Estimates for the Norwegian Sector were provided by Norwegian Petroleum Directorate (Einang Gunnar). The estimates were combined and labeled “W. Europe.” No direct estimates of VOC data could be found for the remainder of the world so these were estimated by multiplying the VOC rate by the oil produced offshore in that region 1995 from API (2001a). One problem arose in doing this. The API (2001b) lumps Mexico with “Other Latin America.” In order to estimate VOC for North America, the production volumes from Pemex (2000) were subtracted from the API “Other Latin America” and the resultant added to the API “Venezuela” estimate to get the value for “S. America shown in Table D-7. OPERATIONAL (PRODUCED WATER) DISCHARGES INTRODUCTION During oil production, water from the reservoir is also pumped to the surface. Under current industry practices, this “produced water” is treated to separate free oil and either injected back into the reservoir or discharged overboard. Produced water is the largest single wastewater stream in oil and gas production. The amount of produced water from a reservoir varies widely and increases over time as the reservoir is depleted. For example, in the North Sea, a maturing oil production area, the volume of produced water has increased at a rate of 10-25 percent per year over the period 1993-1997 in Norway (NOIA, 1998) and the United Kingdom (UKOOA, 1999). Norwegian oil fields produced about half as much water as oil (NOIA, 2000) in 1997. However, an increasing amount of the produced water is re-injected. Produced water discharges are permitted as operational discharges. The oil and grease content is regulated by permit, and the allowable maximum concentrations vary by region and nation: For the U.S. Gulf of Mexico, the limit is 29 mg/L (USEPA, 1996); in the North Sea and Canada, it is 40 mg/L (PARCOM, 1986, PanCanada, 1999). Conventional treatment consists of oil/water separators, and there will have to be major technological advances before significant improvements in treatment efficiencies can be expected. Tables D-8 and D-9 show the estimated volumes of water and oil discharges from offshore produced water discharges for North America and other major offshore producing regions, where available. Data from the 1985 Oil in the Sea report (based on 1979 offshore oil production volumes) are included for comparison. It should be noted that the 1979 estimates were calculated very indirectly; offshore oil production was multiplied by a water:oil ratio (which varied from 0.1 for the U.K. to 0.8 for the United States) and three concentrations for oil content (low, best estimate, and high) that varied by a factor of two. The 1979 estimate did not consider reinjection of produced waters. PRODUCED WATER DISCHARGES IN NORTH AMERICA The 1990s estimates were made using very different and more precise methods. In the United States and the North Sea, offshore operators are required to routinely monitor the volumes and oil content of produced water discharges and to submit reports to regulatory authorities to demonstrate compliance with discharge permits. Therefore, the 1990s estimates have a relatively high degree of certainty. For the United States, produced water discharge volumes and oil and grease content are reported in discharge monitoring reports (DMR) that are submitted monthly to the U.S. Environmental Protection Agency. Table D-8 includes detailed calculations for the different oil production areas in the United States and the North Sea.
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Oil in the Sea III: Inputs, Fates, and Effects TABLE D-8 Estimates of Oil Discharges to the Marine Environment from Produced Water Discharges. NR = Not Reported Produced Water (1,000 bbl/yr) Oil and Grease Content, in mg/L (min-max estimates) Oil and Grease Discharge, in tonnes/yr (min-max estimates) Country 1979 1990s 1979a 1990s 1979a 1990s Total U.S.A.b 311,300 745,000 50 20 2,228 2,500 (2,000-3,600) Gulf of Mexico Offshore 473,000 20 (15-29) 1,700 (1,300-2,500) Louisiana Territorial Seas 186,000 20 (15-29) 600 (450-860) Texas Territorial Seas 4,300 ~6.6 4.5 California Offshore 36,100 ~18 (15-29) 85 (85-170) Alaska Territorial Seas 45,700 15 (15-29) 110 (110-210) Canadac No offshore prod. 18,500 − 21 (15-29) − 62 (32-85) Mexicod NR 15,200 NR ~60 (29-100) NR 140 (70-230) Total North America 780,000 2,700 (2,100-4,000) U.K.e 57,400 1,620,000 60 25 (15-40) 486 5,700 (3,400-9,100) Norwayf NR 450,000 NR 24 (15-40) NR 2,000 (1,300-3,400) The Netherlandsg NR 74,200 NR NR (~35) (15-40) NR 230 (100-260) Denmarkh NR NR NR NR NR 160 Total North Sea 8,200 (5,000-13,000) Otheri 786,400 6,740 25,000 (12,000-41,000) Totals 9,454 36,000 (19,000−58,000) aBased on 1979 oil production volumes, water: oil ratios of 0.1 (U.K.) to 0.8 (U.S.A), and best estimate oil content of produced water. bData reported as means for various periods: Gulf of Mexico Outer Continental Shelf 1996-1998 (Rainey, pers. comm., 2000); Texas Territorial Seas Fourth Quarter 1999 (McClary, pers. comm., 2000); Louisiana Territorial Seas 1992 (Hale, pers. comm., 2000); California OSC 1989-1998 (Panzer, pers. comm., 2000); Alaska Territorial Seas 1997-1999. cData reported for 1999 only PanCanadian Petroleum Limited, 1999) dData reported for 1999 only (PEMEX, 2000) eData reported as means for 1996-1998 (UKOOA, 1999) fData reported as means for 1996-1997. Includes water and oil discharges for produced water and ballast/drainage water (NOIA, 1998) gData reported as means for 1995-1997 NOGEPA, 1998) hData reported for 1996 only NOGEPA (1998) iSee Table D-9. TABLE D-9 Estimates of Oil and Grease Discharges from Produced Water Discharges in Other International Oil Production Areas, Using a Factor Derived from the Gulf of Mexico Offshore Country Oil Production Rate (kbbl/day) % Offshore Production Oil and Grease Discharge (tonnes/year) Nigeria 2,000 80 6,000 Angola 750 100 2,800 Australia 600 100 2,300 Brazil 1,200 100 4,500 Venezuela 100 60 230 Indonesia 0 10 0 Malaysia 800 100 3,000 Thailand 130 50 250 China 320 10 120 India 235 10 90 Iran 200 5 40 Kuwait 280 18 190 Qatar 700 100 2,600 Saudi Arabia 2,000 25 1,900 United Arab Emirates 500 21 400 Totals 25,000
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Oil in the Sea III: Inputs, Fates, and Effects For the Gulf of Mexico production facilities operating in the Outer Continental Shelf (OCS) region, MMS tracks the volume of produced water as part of their royalty program. MMS provided produced water volumes in barrels for 1996, 1997, and 1998, reported as a total of (1) injected on lease (i.e., injected back into a reservoir within the lease area), (2) injected off lease (i.e., injected into a reservoir outside the lease area, usually meaning that produced water is piped to another platform for re-injection), (3) transferred off lease (i.e., piped to a central facility for treatment and re-injection), and (4) overboard discharge (i.e., pumped into the water at the platform) (Gail Rainey, pers. comm., 2000). The overboard discharges were used as the volume of produced water discharged into marine waters for the offshore Gulf of Mexico. The DMR data for the Gulf of Mexico are not available in digital format, and the very large number of facilities makes it impossible to review each report to obtain specific data on the oil and grease content. Therefore, a default value of 29 mg/L, which is the maximum amount allowed for the Gulf of Mexico discharges, was used to estimate the maximum amount of oil and grease in offshore produced water discharges in the Gulf of Mexico. Industry operators attempt to keep oil and grease levels below 25 mg/L, so that the maximum will not be exceeded, and many operators are able to achieve levels below 20 mg/L (the long-term average for California was 18 mg/L and for Alaska was 15 mg/L). Thus, 20 mg/L represents the best estimate, and 15 mg/L was used to calculate the minimum estimate for this region. For the calculations, barrels of produced water were converted to liters, then multiplied by 20 mg/L to get mg of oil, that were then converted into tonnes of oil. Produced water discharged an estimated 2,000 tonnes per year of oil into offshore waters (Table D-8). For the Gulf of Mexico production facilities in coastal waters, referred to as the territorial seas, there is no centralized tracking system. Texas Natural Resources and Railroad Commission (Kevin McClary, pers. comm., 2000) provided a summary of the quarterly reports of produced water volume (in bbls) and oil and grease content (in mg/L) for active dischargers for the fourth quarter of 1999. The volume of produced water discharges in Table D-8 was the total for this one period. The total oil and grease discharges were calculated by multiplying the volume by the oil and grease content for each discharge. For the 29 facilities that reported for this period, the average oil and grease content was calculated as 6.5 mg/L. The calculations were made as for the offshore discharges, that is, bbls of produced water converted to liters, multiplied by 6.5 mg/L to get mg of oil, that was converted to tonnes of oil. Produced water discharged an estimated 4.5 tonnes per year of oil into Texas coastal territorial waters (Table D-8). For Louisiana territorial seas, the most recent summary of the more than 100 produced water discharges is for 1992, based on analysis of the DMRs. Louisiana Department of Environmental Quality (Doug Hale, pers. comm.) provided the estimate of 510,097 bbls per day of produced water discharges. There was no summary of oil and grease levels, so the best estimate default of 20 mg/L oil and grease was used. The calculations were made as for the offshore discharges, that is, bbls of produced water converted to liters, multiplied by 20 mg/L to get mg of oil, that was converted to tonnes of oil. Produced water discharged an estimated 600 tonnes per year of oil into Louisiana coastal territorial waters (Table D-8). In California, all oil production occurs in the offshore. Fourteen platforms report produced water discharges (many platforms commingle their produced waters into one discharge point). MMS (Panzer, pers. comm., 2000) provided spreadsheets with the DMR data for the period 1989-1998 that had running means for produced water volume in barrels and oil and grease concentration in mg/L. The actual reported oil and grease concentrations and produced water volumes for each reporting period were used to calculate the total water volume and oil discharges for the region. The calculations were made as for the offshore discharges, that is, bbls of produced water converted to liters, multiplied by 18 mg/L to get mg of oil, that was converted to tonnes of oil Produced water discharged an estimated 85 tonnes per year of oil into federal offshore waters off California (Table D-8). In Alaska, produced water discharges are reported for fourteen platforms, one tank farm, and one production facility, all discharging into Alaska territorial waters in Cook Inlet. The produced water volumes (in bbls) and oil and grease content, as reported on monthly DMRs for the period January, 1997, to December, 1999, were used to calculate annual averages for that period. For facilities that did not report an oil and grease concentration (e.g., the permit requires only a visual test for sheen), 15 mg/L, the average for all reporting facilities, was used. Produced water discharged an estimated 15 tonnes per year of oil into coastal territorial waters in Alaska (Table D-8). Petroleos Mexicanos (PEMEX) published an annual report (PEMEX, 2000) describing its achievements in safety, health, and the environment. This report included a section on produced water discharges, stating that 79 percent of the 11.5 million cubic meters produced were reinjected, and reporting a total amount of oil discharged in tonnes. It was assumed that all of the produced water discharges were to marine waters. Using these data, the volume of produced water discharged to the sea in 1999 was calculated to be 15,190,000 bbls. The oil content of produced water (60 mg/ L) was calculated by dividing the reported total oil discharges for produced water by this volume, so there is some uncertainty in this number. Canada started offshore oil production in eastern Canada in 1996. Produced water volumes, oil levels, and total oil discharges in 1999 were reported in a 1999 discharge summary for the Cohasset Project published by PanCanadian Petroleum Limited. These data for 1999 are shown in Table D-8.
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Oil in the Sea III: Inputs, Fates, and Effects INTERNATIONAL PRODUCED WATER DISCHARGES In the North Sea, operators sample twice each day and prepare annual summaries that report the total produced water volumes, average oil content, and total amount of oil discharged to the sea. These reports are posted on web sites by the offshore operator associations for each country. The values in Table D-8 for the North Sea were derived directly from the available annual summaries, as described below. The Netherlands Oil and Gas Exploration and Production Association reported annual oil discharges into Dutch waters in tonnes for 1987-1997 (NOGEPA, 1998). Table D-8 shows the average for the last three years, 1995-1997. NOGEPA (1998) also included a table listing oil discharges from produced water for Denmark for 1996. The Norwegian Oil Industry Association published a summary of emissions to air and discharges to sea (NOIA, 1998) for the period 1990-1997. This report included total produced water volumes, amount reinjected, amount discharged to the sea, oil concentration, and total oil discharged in tonnes. The values for Norway in Table D-8 are means for the period 1996-1997, and include oil discharges from produced water and ballast and drainage water. In the 1999 annual report by the United Kingdom Offshore Operators Association (UKOOA, 1999), produced water volumes, oil levels, and total oil quantity discharged in tonnes were provided for 1996-1998. These values are included in Table D-8. For other international areas, where discharge summaries could not be obtained, a rough estimate was made, as follows. A “factor” was developed for the Gulf of Mexico offshore region, by dividing the oil discharge per year in tonnes by the oil production rate for this region. That is, the 1996-1998 maximum amount of 2,500 tonnes of oil from produced water discharges (representing an oil content of 29 mg/L in the produced waters, shown in Table D-8, was divided by the 1999 oil production rate of 1,354 kbbl/day, obtained from the U.S. Department of Energy (DOE, 1999), to get the minimum discharge amount. This approach avoids the need to convert from barrels to tonnes of oil. The U.S. Department of Energy provides data on the oil production rate for international regions. The percentage of production that is offshore is the same estimate used for estimating emissions for VOC. The best estimate was based on an oil and grease content of 60 mg/L, and the maximum estimate was calculated 100 mg/ L. Based on this analysis, other international oil production areas discharge 25,000 tonnes of oil and grease per year. The total amount of oil discharged with produced water discharged for the late 1990s is estimated to be 36,000 tonnes. This volume cannot be compared with the estimate made in 1979 because of the different methods used to make the two estimates. The 1990s volume is based on detailed monitoring and should be considered relatively certain. One issue that could affect the uncertainty of the amount of oil discharged with produced water is the use of the standard Environmental Protection Agency (EPA) gravimetric method for determining oil and grease in the United States (EPA Method 413.1). A study of three Gulf of Mexico platforms found that 2-17 percent of the oil and grease was hydrocarbon material; the nonhydrocarbon components in the oil and grease analysis are fatty acids, phenols, and related compounds (Brown et al., 1992). For three California platforms, petroleum hydrocarbons comprised 30-60 percent of the total hydrocarbons in produced water (Schiff et al., 1992). In the North Sea, total oil is measured by infrared spectroscopy, which also includes nonpetroleum hydrocarbons. Therefore, the total oil discharges in Table D-8 are likely to be high, by as much as a factor of two to five. There have been some major changes in permitted discharges for the oil and gas production industry during the 1990s that are not included in Tables D-8 and D-9. In the United States, produced water discharges into coastal waters (into estuarine areas landward of the shoreline) in the Gulf of Mexico were prohibited by the late 1990s (40 CFR 435.43). Annual produced water discharges into coastal waters in Louisiana in the early 1990s were estimated to be 222,832,000 bbls and contained 1,170 tonnes of oil and grease (Boesch and Rabalais, 1989). By 1997, in the North Sea, discharge of oil-based drilling muds had been prohibited by all countries. In the United Kingdom, oil discharges with drilling cuttings were 3,965 tonnes and represented 40 percent of the total oil releases to the North Sea by the United Kingdom.
Representative terms from entire chapter: