Opinion ID: 705105
Heading Depth: 2
Heading Rank: 2

Heading: drilling fluids and drill cuttings

Text: 45 Drilling fluid (also called drilling mud) is any fluid sent down the drillhole to aid the drilling process. This includes fluid used to maintain hydrostatic pressure in the well, lubricate and cool the drill bit, remove drill cuttings from the well, and stabilize the walls of the well during drilling or workover operations. The fluid is pumped down the drill pipe and through the drill bit. At the bottom of the hole, it sweeps crushed rock drill cuttings from beneath the bit, carries them back to the surface, is separated from drill cuttings and is discharged or is returned to the mud tank for recirculation. 46 Under the Final Rule, EPA prohibits all discharge of drilling fluids and drill cuttings from wells located within three nautical miles from shore for the Gulf and California regions. The BAT, NSPS, and BCT all require any dischargers within the three-mile limit to transport drilling fluids and drill cuttings to shore by barge and to dispose of the discharge in landfills. Beyond the three-mile limit, drilling fluids and drill cuttings may be discharged under BCT after meeting the limitation for no discharge of free oil measured by the static sheen test. 17 BAT and NSPS for dischargers beyond the three-mile limit are more stringent, requiring compliance with four basic requirements. 18 47 Alaska was completely exempted from the zero discharge requirement within the three-mile limit due to special conditions in that region as discussed infra, Part II.B.4.c. As a result, BAT and NSPS for all offshore Alaska wells must meet the four basic requirements limiting free oil, diesel oil, toxicity, and metals content in barite. 19 BCT for all Alaska wells simply prohibits the discharge of free oil. 48 Industry petitioners challenge the EPA's decision to impose the zero discharge limitation on drilling fluids and drill cuttings discharged within three miles of shore in the Gulf and California regions. The BAT, NSPS, and BCT chosen for these dischargers is to barge the drilling fluids and cuttings to shore to be disposed of in landfills. Industry petitioners assert that EPA acted arbitrarily and violated the CWA by (1) improperly calculating the BCT cost test, (2) regulating drill cuttings as Total Suspended Solids (TSS), and (3) failing adequately to consider the cost factor in its BAT and NSPS determination.
49 The BCT cost test is made up of two parts, the POTW test and the industry cost-effectiveness test. The portion of the BCT cost test at issue here, the industry cost-effectiveness test, has been translated into the following mathematical formula: 50 BCT cost/lb. - BPT cost/lb. ------------------------------ < 1.29 BPT cost/lb. - preBPT cost/lb. 51 Based on this formula, EPA's first step was to calculate the existing cost of BPT under which some drilling muds were hauled to shore when they did not meet the no free oil test. EPA then calculated the BCT cost of hauling all drilling muds and cuttings within the Final Rule's three-mile limit. 52 Industry petitioners allege that EPA made two mistakes in calculating the cost of BPT. First, Industry petitioners contend that EPA mistakenly classified the costs of substituting mineral oil for diesel oil as a BPT cost. EPA candidly admits that it did commit this error. EPA contends, however, that this mistake was harmless error because, even with a substitution cost of zero (which EPA does not concede), the BCT level chosen still passes the BCT cost test once Industry petitioners' second contention is rejected. 53 Industry petitioners' second contention is that EPA exaggerated BPT onshore disposal costs for oil-based muds. According to Industry petitioners, no cost should be attributed to the onshore disposal of oil-based muds because dischargers actually sell the muds to mud companies who recondition the mud for reuse as drilling fluids. Industry petitioners assert that a correct calculation of the BPT cost should include only the transportation of oil-based muds to shore. As Industry petitioners view it, a recalculation of the industry cost-effectiveness test, omitting the cost attributed to product substitution and the cost attributed to the disposal of oil-based muds, causes EPA's zero discharge BCT level to fail the BCT cost test. 54 EPA counters that Industry petitioners are not permitted to raise their claim relating to the disposal cost of oil-based muds, because the issue was not raised during the rulemaking process. The requirement that a party raise its concerns to an agency prior to the publication of the final rule promotes agency autonomy and judicial efficiency. Ohio v. EPA, 997 F.2d 1520, 1528-29 (D.C.Cir.1993). Industry petitioners counter that they could not have raised this issue earlier because EPA's calculations were not available until the Rule was published. Industry petitioners' claim is not persuasive, however, because although the exact calculations may have been unavailable, we find ample record evidence that Industry petitioners had sufficient notice that disposal costs of oil-based muds were being considered by EPA as part of the BCT cost test. 55 Even if Industry petitioners had the right to raise this issue, EPA persuasively argues that some cost must be associated with disposal of oil-based muds. For example, EPA suggests that there will be some solids in the process that still require disposal because they will not pass the no free oil test; that reconditioning all of the drilling fluid may not be feasible; and that for those fluids that are reused, there is probably some limit to the number of times such reuse can occur. Logically, there must be some cost associated with the reconditioning operation itself. EPA claims that all of these factors make the Industry petitioners' argument for zero disposal cost an unreasonable one. 56 We are persuaded by EPA that its revised BPT calculation passes the BCT cost test. When EPA drops the mistaken amount included for product substitution, and leaves the rest of the numbers the same, the result of the equation is 1.239. This figure is still lower than the permissible threshold of 1.29.
57 Industry petitioners also argue that EPA improperly classified, and then regulated, drill cuttings as Total Suspended Solids (TSS). According to Industry petitioners, it is arbitrary to ban an entire waste stream (such as all drill cuttings) as TSS when only a small portion of the waste is actually suspended. In Industry petitioners' opinion, a large percentage of the drill cuttings are heavy bits of rock that sink immediately to the ocean floor and should therefore not be classified as TSS. 58 EPA counters that drill cuttings are classified as TSS because they fit within the definition of TSS. According to EPA, TSS is defined as nonfilterable residue. This definition requires only that the substance will not pass through a glass filter. Consequently, EPA uses Method 160.2 20 to measure the amount of solid retained by a fiber filter. Because the drill cuttings discharged by oil and gas producers will not pass through such a filter, drill cuttings are, by EPA's definition, TSS. Industry petitioners maintain that it is illogical to include drill cuttings in a test method that is intended to filter much smaller particles. According to Method 160.2, the practical range of material to be measured is 4 mg/l to 20,000 mg/l. However, as Industry petitioners point out, a representative drill cutting sample is over 1.1 million mg/l. 59 We are persuaded by Industry's argument that EPA has arbitrarily classified drill cuttings as TSS. It is error for EPA to classify drill cuttings, typically on the magnitude of 1.1 million mg/l, by measuring TSS using a test designed to include only particles smaller than 20,000 mg/l. Despite the deference due to EPA in its choice of analytical methodology and testing procedures, it is apparent to this Court that most drill cuttings may not qualify as TSS because they are not suspended. Our view is further bolstered by another of EPA's own tests, Method 160.5, which measures residue classified as settleable. 40 C.F.R. Sec. 136.3, Table 1B (1994). The drill cuttings discharged from the oil and gas development and production phases should not be measured by Method 160.2 unless they fit within that test's practical guidelines. 60 Despite our belief that EPA may have erred in classifying drill cuttings as TSS, it appears senseless here to remand this portion of the Final Rule. Because BAT and NSPS for drill cuttings require the same technological control on drill cuttings as BCT, that is, zero discharge within three nautical miles of shore and no discharge of free oil beyond three miles, altering BCT in this case would not change the result. Furthermore, even if EPA improperly classified drill cuttings as TSS, the agency is not precluded from regulating drill cuttings as an indicator for oil and grease. It is well documented that once drill cuttings are separated from the reusable drilling mud, they continue to carry drilling fluid residues of conventional and toxic pollutants. It is apparent in this specific situation that altering BCT would not in any way change the treatment of drill cuttings in the Gulf of Mexico, California, or Alaska. In this case, therefore, we will not disturb the EPA's treatment of drill cuttings as TSS in the Final Rule although we find some merit in Industry petitioners' allegation.
61 Finally, Industry petitioners challenge the BAT and NSPS levels set by EPA for drilling fluids and cuttings. The BAT and NSPS for dischargers within three miles of shore (excluding Alaska) require zero discharge of the pollutant by barging the mud and cuttings to shore for onshore disposal. Industry petitioners contend that EPA failed to consider adequately the relevant factors required, specifically the cost of barging. Phrased another way, Industry petitioners claim that the BAT and NSPS levels were improperly promulgated because the environmental benefits of the limitations are negligible. 62 EPA counters that it has discretion whether or not to use cost considerations under BAT and NSPS, and that EPA need only find that the technology is technically and economically achievable and that the cost of the technology is reasonable. NRDC v. EPA, 863 F.2d at 1426; see also CPC Int'l Inc. v. Train, 540 F.2d 1329, 1341-42 (8th Cir.1976) (setting NSPS does not require cost-benefit analysis, [w]hat is required ... is a thorough study of initial and annual costs and an affirmative conclusion that these costs can be reasonably borne by the industry), cert. denied, 430 U.S. 966, 97 S.Ct. 1646, 52 L.Ed.2d 357 (1977). The CWA does not require a precise calculation of BAT and NSPS costs. NRDC v. EPA, 863 F.2d at 1426. Congress intended that EPA have discretion to decide how to account for the consideration factors, and how much weight to give each factor. Weyerhaeuser, 590 F.2d at 1045. 63 Industry petitioners maintain that when environmental benefits are de minimis, the regulation is not valid. However, EPA points to several environmental benefits of the zero discharge rule, primarily, the decrease in pollutants ingested by fish and shellfish and passed along the food chain. Among the non-monetary benefits of zero discharge is the reduction in recreation degradation. Industry petitioners maintain that zero discharge is not necessary because simply meeting the four basic requirements under BAT for dischargers outside the three mile limit reduces virtually any pollution harm. However, Industry petitioners have not carried their burden of showing that zero discharge does not achieve any additional environmental benefit. 64 We are persuaded that EPA acted within its discretion in setting BAT and NSPS for drilling muds and drill cuttings.
65 In promulgating the permissible discharge of drilling fluids and cuttings in this part of the Final Rule, EPA determined that zero discharge for all offshore platforms in the Gulf, California and Alaska was technologically available (through barging to shore) and economically achievable ($12.3 million for drilling fluids, $6.6 million for drill cuttings). However, unacceptably high nonwater quality environmental impacts led EPA to establish the three-mile zero discharge limit for the Gulf and California, and to reject the zero discharge option completely for Alaska. In the Gulf of Mexico, EPA rejected zero discharge beyond three miles from shore because of a lack of landfill capacity in the region. In California, zero discharge beyond three miles was rejected because of its serious impact on air pollution. And zero discharge was not required in Alaska because of numerous factors unique to that region. NRDC challenges each of these decisions. 66
67 NRDC contends (1) that EPA overestimated the volume of waste that would be generated by platforms outside the three-mile limit, and (2) underestimated land disposal capacity. According to NRDC, correcting these errors clears the way for a zero discharge requirement for drilling fluids and drill cuttings from all oil and gas rigs in the Gulf of Mexico. 68 EPA estimated the landfill capacity in the Gulf region over the next 15 years and determined that 8.5 million barrels of waste could be disposed each year. Because the landfills in that area are already receiving 3 million barrels of waste each year from other sources, EPA calculated that only an additional 5.5 million barrels of waste from offshore sources could be accommodated. EPA then examined the amount of waste that would be generated offshore if a zero discharge limitation were in place for all platforms. It was estimated that offshore platforms would generate 6.6 million barrels/year. In addition to the 1.1 million barrels/year already being produced by coastal drilling operations, the total amount of drilling wastes generated totals 7.7 million barrels of waste per year. Because EPA estimated landfill capacity at only 5.5 million barrels each year, EPA devised its three-mile mark, beyond which platforms are not required to comply with zero discharge. 69 NRDC first contends that EPA overestimated the amount of waste that would require disposal by use of the zero discharge limit. NRDC claims that EPA used poor solids control technology in its calculations. Solids control technology removes drill cuttings from the drilling fluid system and reduces the total amount of drilling wastes that cannot be reused. As EPA points out, however, improved solids control technology only increases the volume of drill cuttings separated from reusable drilling fluid. Consequently, EPA found that the additional waste reduction that might be achieved is minimal. NRDC also raised the oil-based muds issue, contending that such muds are reused and that EPA did not take this into consideration. EPA maintains that reconditioning oil-based muds cannot eliminate all drilling fluids from the waste stream and that, therefore, any reuse does not drastically change its calculations. 70 NRDC also contends that EPA underestimated the landfill capacity of the Gulf region. NRDC believes that EPA ruled out acceptable landfills for insufficient reasons. For example, in its estimation of landfill capacity, EPA did not include landfills that are not now in operation. NRDC contends that those landfills currently are not operating because of a lack of demand. If it were more economically productive for those landfills to operate, NRDC presumes that more space would open up for drilling wastes. Nor did EPA consider landfills whose licenses are currently suspended. NRDC asserts that those sites might regain their licenses. Despite NRDC's contentions, however, this Court would have to engage in pure speculation to determine whether landfill operators would reopen or regain their licenses. Furthermore, the confusion cited by NRDC over the names of several of the landfills in the EPA estimate is adequately explained by the fact that several landfills are known by more than one name. 71 Finally, NRDC criticizes EPA for failing to include in its estimate of landfill capacity any sites equipped to accept hazardous wastes. However, EPA purposely omitted hazardous landfill sites due to the high demand for such hazardous sites. According to EPA, the decision to exclude hazardous sites from its estimation of total landfill capacity is consistent with its 1988 decision not to regulate oil and gas under the hazardous waste portion of the Resource Conservation and Recovery Act (RCRA), 42 U.S.C. Secs. 6901-6987. It is EPA's position that hazardous waste sites must be reserved for disposing of those substances that are more hazardous and dangerous than drilling fluids and drill cuttings. 72 This Court believes that EPA has both the discretion and the expertise to make the decisions and value judgments behind its rejection of the zero discharge option beyond three miles off the shore of the Gulf of Mexico. Furthermore, EPA continuously reevaluated data and collected comments on the estimated volume of drilling fluids and cuttings, revising its information as recently as 1993. It is clear from the record that EPA made the decisions NRDC challenges after considering all of the options raised by the NRDC and after weighing the benefits and drawbacks of those options. We find that EPA's decisions are not arbitrary or capricious, nor are they the result of an abuse of the agency's discretion. 73
74 NRDC also alleges that EPA illegally rejected zero discharge of drilling wastes in California beyond the three-mile limit. Having found zero discharge to be achievable in the California region, EPA nevertheless rejected zero discharge beyond the three-mile limit, based on the severity of the air pollution in Southern California. In EPA's opinion, the increased air emissions that would result from barging all drilling wastes from offshore platforms to the coast of California vastly outweighed the benefit of a zero discharge limitation beyond three miles from shore. 75 NRDC generally charges that EPA cannot reject zero discharge on the basis of possible increased air emissions. According to NRDC, EPA cannot reject a limit based on nonwater quality environmental impacts unless the impacts are wholly disproportionate to the possible pollution reduction. NRDC also argues that the estimated addition of 54 tons/year of air pollution off the coast of California is small compared to the present degree of air pollution in California, and that offshore platforms that increase air emissions would be able to purchase pollution offsets to compensate for the increased air pollution. We find each of NRDC's arguments unpersuasive. 76 The overriding principle in our review of the Final Rule is that the agency has broad discretion to weigh all relevant factors during rulemaking. The CWA does not state what weight should be accorded to the relevant factors; rather, the Act gives EPA the discretion to make those determinations. NRDC v. EPA, 863 F.2d at 1426. Compared to the benefit of a zero discharge requirement for all California offshore platforms, EPA views this increase in air pollution to be unjustified. 77 Furthermore, Southern California is a severe nonattainment area under the measurements of the Clean Air Act (CAA). 21 There is some doubt that emissions offsets are available at any cost. Even if offsets could be purchased by offshore oil producers, they would cost approximately $15,000 per ton of nitrogen dioxide and $5,000 per ton of hydrocarbons. 78 If any entity has the ability to weigh the relative impact of two different environmental harms, it is the EPA. Here, EPA has weighed all the factors and has decided to compromise by requiring zero discharge within a three-mile limit. In the absence of a showing of clear error or abuse of discretion, this Court will not overturn EPA's determination. 79
80 NRDC also challenges the EPA's decision to reject zero discharge of drilling wastes in Alaska. EPA based its decision on several factors: (1) the severe weather, which restricts the movement of barges; (2) the lack of any nearby landfills along the Alaska Coast; and (3) the infeasibility of reinjection technology. Consequently, EPA's Final Rule does not require zero discharge for platforms off the coast of Alaska. NRDC argues that zero discharge is already achieved offshore of Alaska through the waste minimization and reinjection required by state regulation. Accordingly, NRDC contends that EPA likewise should require the achievable goal of zero discharge in Alaska. 81 EPA carefully examined the possibility of requiring reinjection of drilling wastes in Alaska and rejected this option because of geologic concerns and the large amount of space required for such reinjection technologies. Although reinjection is currently occurring at the one and only offshore Alaskan platform, that platform is located on a gravel island in the Beaufort Sea, which makes reinjection possible. Injection of the waste depends on fracturing the receiving formation, which must be suitable for such a process. The formation also must be confined by layers that will not be affected by the fracturing so that the injected material remains in place. Consequently, EPA found that, although design work is continuing to improve the technology and reduce the size of the systems required, the technology is still experimental and is not yet available for application to offshore platforms. 82 Furthermore, zero discharge in Alaska is unrealistic in light of the severe weather conditions in that region. Sea ice, winter snow, and fog restrict visibility and navigability of the tugs and barges that would be required to haul wastes to shore. This Court is persuaded by EPA's analysis and studies proving that zero discharge is not a viable option at this time.