Who s Watching? Regulating Technology and Safety Standards in Deepwater Drilling: Exam Numbers &

Transcription

1 Who s Watching? Regulating Technology and Safety Standards in Deepwater Drilling: Exam Numbers & I. Introduction.page 1 II. Offshore Drilling in the United States, 1887-Today..page 2 a. The Early Years: page 2 b. The Outer Continental Shelf Lands Act.page 6 c. OCSLA and BAST page 8 d. Assorted Regulatory Failures page 10 e. Other Considerations page 11 III. The Process of Drilling a Deepwater Well.page 13 IV. Specific Drilling Regulations page 15 V. What Went Wrong at the Macondo Site.page 16 a. Faulty Cement Slurry page 17 b. Failure of the Mechanical Barriers page 19 c. The Negative Pressure Test Was Accepted page 20 d. The Blowout Preventer Failed to Perform...page 22 VI. Possible Solutions and Conclusion page 23 I. Introduction The deterioration of the environment is in large measure the result of our inability to keep pace with progress. We have become victims of our own technological genius. -Richard Nixon, 1969 Only thirty years separate the first successful oil well on land 1859 in Titusville Pennsylvania from the first offshore oil well, which led to the discovery of the Summerland Offshore Oil Field near Santa Barbara, California, in It has also only been about 30 years since these wells migrated from what can be called coastal production to offshore sites more than 1,000 feet below the ocean s surface. 2 Rapidlyadvancing drilling technology has made these leaps possible in such short time, but the 1 Ernest R. Bartley, The Tidelands Oil Controversy (University of Texas Press, rep. 1979), page Offshore Magazine, Milestones and Influences in U.S. Offshore History ( ), May 1, Available at 1

2 regulatory framework has had trouble keeping up. As the environment in which most drilling occurs becomes less familiar, it also becomes more dangerous. As evidenced by the multiple failures to cap the wellhead after the Deepwater Horizon blowout, when something goes wrong miles from the surface, industry and government actors may be ill-equipped to stop it. Though there is surely much to be written about post-blowout actions, this paper is focused on how the regulations in place may have played a role in allowing the blowout scenario to develop in the first place. This paper begins by outlining the history of offshore development of mineral resources in the United States from 1887 to today, and traces the safety and technology regulations accompanying each era. The second half of the paper will focus on the regulations in place when the Macondo well was conceived, and the places where BP and other involved actors had discretion to make decisions about what technology they used. The purpose is to give some historical perspective on the regulation of offshore drilling technology and identify areas where drilling companies are free to make their own decisions about what kinds of technology to employ in the process. By identifying these regulatory gaps, we will attempt to show that in this case, the areas where the energy companies made decisions unfettered by federal regulation, were the same areas in which technology failed and contributed to the disaster. II. Offshore Drilling in the United States, 1887-Today a. The Early Years:

3 The first offshore oil well was drilled in 1896, in the shallow waters about ninety meters off the coast of Summerland, California. 3 Within five years, 14 more piers went up and 400 more wells went down in the same area. 4 At the time, there was no law in California or any other state governing the exploration and production of oil and gas from submerged lands. 5 Companies with capital could invest in offshore drilling if they chose, and 22 companies were active in the Summerland offshore field at the turn of the century. 6 Off the coasts of Texas and Louisiana, rigs were also popping up in tidal zones. From the very beginning, these operations were privately-driven and there was little government oversight at any level. By 1910, oil was the primary energy source for America, and states had begun to take an interest in capturing some of the revenues from production for themselves. 7 In 1921, California capitalized on the opportunity and passed an Act authorizing it to grant permits to California residents to explore for oil and gas on the submerged lands off its coast. 8 This act mimicked the Federal Mineral Leasing Act of 1920, which authorized the leasing of public lands for developing deposits of minerals, oil, and gas, and provided for 5% of the royalties to go to the State. 9 The 1921 Act did not provide for any supervision of offshore operations, but as production increased so did concerns for its 3 National Ocean Industries Association website, 4 American Oil & Gas Historical Society, Offshore Oil History, available at Accessed October 29, Bartley, supra note 1, at page American Oil & Gas Historical Society, supra note 4. 7 National Ocean Industries Association website, supra note 3. 8 United States v. California, 332 U.S. 19, 38 (1947); Cal.Stats. 1921, c. 303, p Bartley, supra note 1, at page 67; Peter M. Douglas, et al, California Offshore Oil and Gas Leasing and Developments Status Report, May 25, 1999, page 2. Available at 3

4 effect on the environment; the Act was followed in 1924 by a state Oil Pollution Act prohibiting discharges into tidelands waters. 10 During the same period, several other states were also issuing leases for drilling on submerged lands adjacent to their coastlines, believing that they owned the tidelands as far out as they could drill. 11 For several decades, the states enjoyed autonomy over the submerged lands off their coasts. During this period, there were still few safety or technology regulations every driller was a pioneer and drilling technology, though still crude, was rapidly outpacing any government attempts to regulate it. In 1938, a 320-foot by 180-foot freestanding wooden oil platform was built in the Gulf of Mexico in a joint venture by Pure Oil Company and Superior Oil Company. The platform stood in about 14 feet of water a mile from the shore at Creole, Louisiana. 12 Though the platform was demolished by a hurricane a few years after its construction, it had been successfully producing and was quickly rebuilt. 13 In 1947, the Kerr-McGee Corporation drilled the first well from a fixed platform that was not in sight of land, heralding a new era in offshore drilling and technology development. 14 At the time, [n]ot much equipment specifically designed for offshore drilling existed and exploration remained an extraordinarily speculative and risky business venture. An offshore dry hole could easily swallow the huge capital costs sunk into construction of a large, permanent rig platform. 15 Despite these risks, the potential profits were staggering. As 10 Douglas, supra note 9, at page Jennifer Larson, Challenges Under OCSLA and the Future of Offshore Drilling Under the Obama Administration, 13 SMU Sci. & Tech. L. Rev. 55, 57 (2009). 12 American Oil & Gas Historical Society website, supra note Id. 14 Bartley, supra note 1, at page American Oil & Gas Historical Society website, supra note 4. 4

5 the demand for oil products grew, however, so did the federal interest in controlling domestic production. Those advocating coastal state ownership of submerged lands asserted that the coastal states have regulated offshore activities and leased lands for oil and gas development. The coastal states could better encourage and manage offshore oil and gas development because of their less restrictive leasing policies and superior knowledge of local conditions. 16 In the 1950s, oil production revenues became second only to income taxes as revenue generators for the United States. 17 In a series known as the Tidelands cases, the Supreme Court systematically invalidated several coastal states legislation that had allowed the state to govern leases for oil and gas exploration in the submerged lands off the coasts. 18 The first of these was United States v. California, in which Justice Black noted until the California oil issue began to be pressed in the thirties, neither the states nor the Government had reason to focus attention on the question of which of them owned or had paramount rights in or power over the three-mile belt. 19 The Court held that neither California nor the original thirteen states enjoyed rights in the submerged lands between the low-water mark and the three-mile belt along their coasts. The Court reached largely the same conclusion in United States v. Louisiana in 1950, and United States v. Texas the same year. 20 It was established that the Federal 16 Edward Fitzgerald, The Tidelands Controversy Revisited, 19 Envtl. L. 209, 210 (1988). 17 National Ocean Industries Association website, supra note Michael J. McHale, An Introduction to Offshore Energy Exploration A Florida Perspective, 39 J.Mar.L.&Com. 571, 573 (2008) U.S. 19, 30 (1947) Id. at U.S. 699 (1950); 339 U.S. 707 (1950). 5

6 Government rather than the state has paramount rights in and power over that belt, an incident to which is full dominion over the resources of the soil under that water area, including oil. 21 In response to these cases, Congress passed the Submerged Lands Act, the purpose of which was to return ownership of the submerged lands within three nautical miles of the coasts to the states and fix that which was generally believed and accepted to be the law of the land; namely, that the respective states are the sovereign owners of the land beneath navigable waters within their boundaries and of the natural resources within such lands and waters. 22 This triumph of federalism was short-lived, however, as the domestic thirst for oil continued. Oil companies continued to drill deeper and farther from the shoreline, in waters beyond the purview of the states. In the end, the federal government benefited most by dint of the industry s incessant hankering to push into deeper water farther offshore, beyond even state limits. 23 It was this striving past the limits of state offshore boundaries which led Congress to pass the Outer Continental Shelf Lands Act in 1953, establishing the federal regulatory regime for offshore mineral exploration on the Outer Continental Shelf (OCS) beyond three miles from the shore. 24 The Outer Continental Shelf Lands Act (OCSLA) has shaped oil exploration and production in the United States more than any other law. Understanding its framework and the regulations it birthed sheds light on the circumstances contributing to the Deepwater Horizon disaster. b. The Outer Continental Shelf Lands Act U.S. at McHale, supra note 18 at 574; H.R. Rep. No. 695, 82 nd Cong., 1 st Sess., to accompany H.R. 4484, at 5 (July 12, 1951). 23 F. Jay Schempf, Pioneering Offshore: The Early Years, p. 101 (PennWell Custom Publishing, 2007). 24 The Outer Continental Shelf Lands Act, 43 U.S.C (2002). 6

7 In its Congressional Declaration of Policy, the Outer Continental Shelf Lands Act states that the OCS is a precious national resource to be held in trust by the Federal Government for the people of the United States. 25 The Act put the Secretary of the Interior in charge of leasing and promulgating rules and regulations for the governance of such leases on the OCS. 26 The Secretary of the Interior then designated the Minerals Management Service (MMS) as the agency that would manage mineral leases on the OCS and supervise operations. 27 In the 1950s and 1960s, leasing and development on the OCS proceeded under the watch of the Department of the Interior with advice from the oil companies operating offshore coastal states had little, if anything, to do with leases or regulating the drilling. 28 From the beginning, the government had difficulties keeping up with the industry s exponential expansion and advances in technology. The overseeing departments needed more geologists, geophysicists, and petroleum and reservoir engineers, as well as production accounting specialists and administrative personnel, to keep up with the industry s almost geometric expansion. 29 While OCSLA contained language prioritizing safety and environmental protection, it contained no baseline for environmental protection or safety technology that the Department of Interior should require of OCS lessees. Instead, the agency [was] given broad discretion to balance competing interests in oil and gas development, 25 McHale, supra note 18 at U.S.C. 1334(a)-(d). 27 Larson, supra note 11, at page Robert B. Wiygul, The Structure of Environmental Regulation on the Outer Continental Shelf: Sources, Problems, and the Opportunity for Change, 12 J. Energy Nat. Resources & Envtl. L. 75 (1992) 29 Schempf, supra note 23 at page

8 safety, and environmental protection. 30 The Act required that the Department of the Interior enact regulations addressing those three often-competing interests. In 1969, a horrific oil spill off the coast of Santa Barbara led to the proposal of several amendments to OCSLA, and included in the Congressional purpose statements that the hope was the amendments would encourage development of new and improved technology for energy resource production which will eliminate or minimize risk of damage to the human, marine, and coastal environments. 31 These amendments were passed in 1978, and provided for a five-year leasing program, spawned regulations for each stage of the leasing process, and established an oil spill fund to reimburse cleanup costs. 32 c. OCSLA and BAST OCSLA was amended five more times in the next 20 years. 33 The main goal of these amendments was to streamline the permitting and leasing process, but the amended OCSLA continued to lack technology-forcing standards, though its regulations were required to incorporate the best available and safest technology (BAST). 34 In spite of language which requires that health, safety, and the environment be taken into 30 Alyson Flournoy et al, Regulatory Blowout: How Regulatory Failures Made the BP Disaster Possible, and How the System Can be Fixed to Avoid a Recurrence, Center for Progressive Reform White Paper #1007, page 13, available at Accessed Nov. 2, Larson, supra note 11, at page 62, quoting 43 U.S.C (2006). 32 Id. citing 43 U.S.C. 1802(8) (2006). 33 Erin Mastrangelo, Overview of U.S. Legislation and Regulations Affecting Offshore Natural Gas and Oil Activity, Energy Information Administration, Office of Oil and Gas, September 2005, p. 5. Available at pdf. 34 Wiygul, supra note 28; Flournoy et al., supra note 30 at page 13. 8

9 consideration, the statute lacks clear enforceable mandates setting forth adequate environmental and safety standards with which oil and gas drilling activities must comply. 35 The BAST standard is outlined in Section 1347: [T]he Secretary, and the Secretary of the Department in which the Coast Guard is operating, shall require, on all new drilling and production operations and, wherever practicable, on existing operations, the use of the best available and safest technologies which the Secretary determines to be economically feasible, wherever failure of equipment would have a significant effect on safety, health, or the environment, except where the Secretary determines that the incremental benefits are clearly insufficient to justify the incremental costs of using such technologies. 36 Despite this provision, however, there was little oversight that ensured the BAST balancing analysis was being done. A law review article written in 1992 noted that [i]mplementation of the BAST standard has been left up to the various OCS regional offices, and seems to have received virtually no public attention.mms regional staff perform ongoing evaluations of the available technology. It does not appear that the economic feasibility of the technologies is explicitly taken into account in this process. 37 The OCSLA also directs that operations be conducted in a safe manner by welltrained personnel using technology, precautions, and techniques to prevent or minimize the likelihood of blowouts or other occurrences which may cause damage to the environment or to property, or endanger life or health. 38 This lack of specific 35 Flournoy et al., supra note 30 at U.S.C. 1347(b) (1988). 37 Wiygul, supra note 28 at Section U.S.C. 1332(6). 9

10 technology-forcing standards and input driven largely by industry interests means that for the life of OCSLA, the technology and safety regulations have been inadequate. 39 d. Assorted Regulatory Failures Title 30 of the Code of Federal Regulations contains regulations promoted by the Department of the Interior under OCSLA. A cursory look at the regulations in place before the Deepwater Horizon spill reveals an industry-driven slant to those governing technology and safety. The MMS regulations addressed, among other things, well casing and cementing, blowout prevention equipment, well control training for personnel, monitoring and safety systems for producing wells, and plugging and abandonment requirements. 40 MMS did promulgate detailed and extensive regulations about safety technology to be employed, but those were based largely on standards recommended and developed by industry itself. 41 In addition to the lack of oversight concerning BAST, lessees could avoid fully disclosing the types of technology they were using. One regulation requires that a lessee using any new or unusual technology describe it within their development plan, with an option to exclude proprietary information. 42 This possibility further removed drilling operations from regulatory oversight. 39 Compare, for example, OCSLA to the Clean Water Act, under which permits must specify the control technology applicable to each pollutant. A National Pollutant Discharge Elimination System permit requires the polluter to stay within technologybased effluent limits. See Claudia Copeland, Clean Water Act: A Summary of the Law, Congressional Research Service, April 23, 2010, available at 40 Wiygul, supra note 28 at Section Flournoy et al., supra note 30, at page CFR (e). 10

11 Another area of regulatory failure is found in the requirements for scrutinizing and approving exploration plans, which occurs at the beginning of the leasing process. At the time of the Deepwater Horizon blowout, there were insufficient means of requiring companies to demonstrate the safety of their proposed activities and the adequacy of their disaster response plans. 43 When the MMS approved BP s exploration plan for the Deepwater Horizon project, for example, it absolved the project from any environmental review because the danger of an oil blowout, and any resulting environmental damage, was minimal or non-existent. 44 The MMS based this determination not on its own independent analysis, but on documents submitted to it by BP itself. These failures did not spring from OCSLA regulations, but from NEPA, whose associated regulations require detailed environmental impact statements at each stage of the leasing process. 45 Despite existing environmental statutes that were expected to reinforce safety and technology standards in the context of environmental protection, these associated regulations also broke down. [T]he industry and the agency failed to consider the devastating sequence of equipment failures that was clearly foreseeable but thought to be unlikely. BP s own exploration plan minimized the danger of a spill.the agency s assessment of the likelihood of a blowout or massive spill reflected these same assumptions, repeatedly describing these events as unlikely and therefore dismissing them with little or no analysis of their impacts. 46 e. Other Considerations 43 Flournoy, et al., supra note 30, at page Id. at page National Environmental Policy Act Regulations, 40 C.F.R et seq. 46 Flournoy et al., supra note 28, at page

12 One other large obstacle to imposing technology-forcing standards in the deepwater drilling industry is that the expertise resides largely within the industry, with regulators barely, if ever, keeping up with advances in technology and newer, deeper, more dangerous frontiers of drilling being explored every day. The MMS and the Coast Guard have struggled with inadequate funding and unclear mandates, which have hindered their enforcement of statutory and regulatory requirements. In the realm of oil response, [a]gency budget caps have inhibited use of OSLTF [Oil Spill Liability Trust Fund] funds for research and development (R&D) of new response technologies. Agency budget caps and prohibitive policies/regulations have inhibited research, development, test and evaluation (RDT&E) of response technologies. 47 The sheer breadth of coverage regulators have to provide has also impeded their ability to comply with statutory mandates. The number of deepwater wells has increased exponentially, while the number of MMS inspectors has stayed stable. The number of producing deepwater wells increased from 65 in [ ] 1985 to more than 600 in But the number of federal inspectors working for Minerals Management Service (MMS) has not kept pace with the number and complexity of wells and the distance inspectors must travel. MMS had 55 inspectors in 1985 and just 58 some 20 years later. Currently, MMS has approximately 60 inspectors in the Gulf of Mexico region to inspect almost 4,000 facilities U.S. Coast Guard et al, Spill of National Significance (Gulf SONS) Joint After Action Report 22, p. 22 (2002), available at 48 Opening Statement of Rep. Bart Stupak, Chairman, Subcomm. on Oversight and Investigation of the H. Comm. on Energy and Commerce, Hearing on the Role of the Interior Department in the Deepwater Horizon Disaster, Before the Subcomm. on Energy and Environment and the Subcomm. on Oversight and Investigation of the H. Comm. on Energy and Commerce 1 (July 20, 2010), available at pdf 12

13 In 2005, MMS agents were able to inspect 1,292 rigs, while in 2009, they were able only to inspect Another problem facing regulatory bodies has been a brain drain, or trouble recruiting and maintaining qualified inspectors and other agency staff. It is difficult to find inspectors with the requisite expertise who are industry-neutral. For those who are qualified, the industry provides much more alluring wages and bonuses than the government can. 50 Many have treated the BP disaster as inevitable, given the innumerable factors enabling the conditions that existed at the time of the blowout. The second half of the paper focuses on the specifics of the technology involved in the Macondo well, and the regulations governing such integral well aspects as the blowout preventer, necessary pressure tests, and cement slurry. III. The Process of Drilling a Deepwater Well The Macondo well is a deepwater well, which means it was drilled in water deeper than 1000 feet. The Deepwater Horizon was the drilling rig used to drill the Macondo well. The Deepwater Horizon was owned by Transocean and leased to BP. After the Deepwater Horizon was positioned directly over the proposed well location, drilling began. To begin the process of producing oil and gas from a deepwater well, a seismic ship uses magnetic surveying equipment to locate rock formations believed to contain hydrocarbons. A drilling rig is taken to the site with the formations and drills a 49 Richard M. Mackowsky, et al. "The Deepwater Horizon Catastrophe: A Factual Overview and Preliminary First-Party Analysis," page 18 (Cozen O'Connor, 2010), available at pdf. 50 Flournoy et al., supra note 30, at page

14 well, which is then capped. The drilling rig then leaves, temporarily abandoning the site, and a production platform is connected the well and produces the hydrocarbons from the formation. 51 At the Macondo Well, a pilot hole was drilled in the seafloor and filled with a casing. The pilot hole has a wide diameter and is relatively shallow, only feet deep. The casing is a steel pipe used to keep wells drilled into a formation from collapsing. After a casing has been set in a well, cement is pumped through it from the rig. The cement travels down the casing, through the bottom opening and then back up the sides of the casing to fill in the space between the outside of the casing and the hole in the seafloor. This space is often referred to as an annulus. 52 Once the pilot hole is cased and cemented, a blowout preventer ( BOP ) is lowered onto the casing by a riser. Risers are large pipes with high load-bearing capacities. 53 A blowout is a rush of crude oil, natural gas, or both that rushes up the casing or the riser and reaches the rig. Because crude oil and natural gas are extremely flammable, a blowout is very dangerous and a BOP has a series of preventative devices designed to stop the rush of fluids to the rig. 54 The BOP on the Macondo well was manufactured by Cameron, stood at 53 feet tall, weighed 450 tons, and included a series of valves known as rams. A blind ram is used to close off the string if the well is empty, a pipe ram is used to close off the well if it is currently in use for drilling, and a shear ram is used if the casing is being passed through the BOP. The pipe ram presses pieces of steel-reinforced rubber against the string, crimping the line. 51 Mackowsky, et al., supra note 49 at page Id. at Id. at Id. at

15 The shear ram, the final safeguard against a blowout, has two large blades and can sever a casing or drill string to cut off the passage to the rig. After the BOP has been set in place, drilling the full well begins. A drill string is run down the riser, through the BOP and into the initial pilot casing. Drilling mud is pumped through the drill string to cool the bit and to apply pressure to the formation to guard against a blowout. Drilling mud is specifically blended for each well to keep the pressure in the drill string greater than the pressure of the hydrocarbons in that formation. As the well progresses deeper into the seafloor, the casing sections get narrower. This is because each successive piece of casing must be lowered through the previously set piece of casing. Each piece is cemented in place by sending wet cement slurry down the well and out of the lowest piece of casing. The cement flows along the exterior surface of the casing into an annulus and hardens, locking the piece of casing in place. In preparation for temporary abandonment, a cement plug is placed in the well, the riser is disconnected from the BOP and the rig is deployed to another site. 55 IV. Specific Drilling Regulations Section 250 of Title 30 of the U.S. Code of Federal Regulations authorizes the MMS [now the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE)] to regulate oil, gas, and sulphur exploration, development, and production operations on the outer Continental Shelf (OCS). 56 Under the Secretary of the Interior s Authority, all operations are required to be conducted according to the OCS Lands Act (OCSLA), the regulations, MMS orders, the lease or right-of way, and other applicable 55 Mackowsky, et al., supra note 49 at page C.F.R. 250 (1999). 15

16 laws and amendments. To obtain a permit to drill a well from MMS, an applicant must submit (a) a plan that shows locations of the proposed well, (b) design criteria used for the proposed well, (c) drilling prognosis, (d) casing and cementing programs, (e) diverter and BOP systems descriptions, (f) requirements for using an MODU (mobile offshore drilling unit) and (g) additional information. 57 BP submitted an exploration plan for the Macondo well on April 6, 2009, which was approved by MMS on May 22, BP completed the engineering design for the well in June The original design consisted of eight casing strings and included well equipment and operations, mud drill bits, cement plans and pressure testing. 59 Once drilling began in accordance with the original plan, a section of the drill pipe became stuck and could not be freed. BP determined that the high formation pressure caused the sticking and changed the casing design. BP filed and received approval for an application for permit to modify as required for a revision to the drilling plan. 60 Aside from the change in casing design, BP drilled the Macondo well in accordance with their original plan that was drafted in accordance with the regulations and approved by the MMS. As explained below, many of the decisions that BP made in planning this well were acceptable within the regulations but likely contributed to the blowout. V. What Went Wrong at the Macondo Site C.F.R (2003). 58 BP Incident Investigation Team, "Deepwater Horizon Accident Investigation Report," page 15 (Sept ) available at se/staging/local_assets/downloads_pdfs/deepwater_horizon_accident_investigation _Report.pdf. 59 Id. at C.F.R (a)(1) (2006). 16

17 The cause of the blowout at the Macondo site remains unclear. Because of the complexity of the operations, it may prove difficult to isolate the exact chain of events which led to the blowout. The BP internal investigation report identified a number of failures that may have contributed to the disaster, including: the annulus cement barrier did not isolate the hydrocarbons; the shoe track barriers did not isolate the hydrocarbons; the negative-pressure test was accepted although well integrity had not been established; influx was not recognized until hydrocarbons were in the riser; well control response action failed to regain control of the well; diversion of the mud gas separator resulted in gas venting onto the rig; the fire and gas system did not prevent hydrocarbon ignition; and the BOP emergency mode did not seal the well. 61 The following sections discuss the regulations and BP s decisions regarding the cement barrier, the mechanical barriers, the negative-pressure test, and the BOP. a. Faulty Cement Slurry One of the possible causes of the blowout was faulty cement slurry supplied by Halliburton, the contractor hired by BP to perform the cementing operations at the Macondo site. In a letter to the commissioners of the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling, the Commission came to four conclusions: (1) only one of the four tests run by Halliburton demonstrated that the cement design was stable; (2) Halliburton may not have had, and BP did not have, the test results by the time the cement was to be installed into the Macondo well; (3) Halliburton and BP both had results that a similar foam design proved to be unstable; and (4) Halliburton should have considered redesigning the foam before using it in the 61 BP Incident Investigation Team, supra note 58, at pages

18 well. 62 These findings are based on test results performed at a Chevron lab in Houston that replicated the cement slurry mixture used at the Macondo site. 63 Chevron conducted these tests according to an American Petroleum Institute (API) Standard. 64 API is the trade association that represents the oil and gas industry by lobbying the government, researching economics, generating statistics, and setting equipment and operating standards. 65 The nitrified foam cement slurry for the Macondo well used a mixture of 55% - 60% nitrogen by volume to achieve a downhole mixture of 18% - 19%. Test results by CSI Technologies demonstrated that cement slurry with greater than 50% nitrogen is unstable. 66 In addition to the nitrogen percentage, the BP report identifies four other decisions that may have led to the failure of the cement job. First, the cement slurry yield point was low, which could have increased instability. Second, the small slurry volume used in conjunction with a long displacement and a base oil spacer could have increased instability. Third, destabilization may have resulted from the use of a defoamer additive. Fourth, fluid loss control additives were not used for cementing across the hydrocarbon zone, which could have allowed for formation fluids to permeate the cement. 67 BP concluded that the nitrified foam cement slurry used would probably have experienced nitrogen breakout, nitrogen migration and 62 Letter from Fred H. Bartlit, Chief Counsel, National Commision on the BP Deepwater Horizon Oil Spill and Offshore Drilling, pages 3-4 (Oct. 28, 2010), available at %20Bartlit%20to%20Commissioners.pdf. 63 Id. at API RP10B-2/ISO American Petroluem Institute Website, 66 BP Incident Investigation Team, supra note 58, at page Id. 18

19 incorrect cement density, which would explain the failure to achieve zonal isolation of hydrocarbons. Nitrogen breakout and migration would have also contaminated the shoe cement and may have caused the shoe track cement barrier to fail. 68 BP s conclusion appears to blame the accident on Halliburton s cement job. However, even if BP s conclusions are correct, its amount of discretion on how to design the foam highlights a hole in MMS s regulations. None of these decisions violated any of the regulations listed in Section 250. The most specific cementing requirement states that [y]ou must design and conduct your cementing jobs so that cement composition, placement techniques, and waiting times ensure that the cement placed behind the bottom 500 feet of casing attains a minimum compressive strength of 500 psi before drilling out of the casing or before commencing completion operations. 69 b. Failure of the Mechanical Barriers For the final casing string (or liner if it is your final string), you must install dual mechanical barriers in addition to cement, to prevent flow in the event of a failure in the cement. These may include dual float valves, or one float valve and a mechanical barrier. You must submit documentation to BOEMRE 30 days after installation of the dual mechanical barriers. 70 In accordance with this regulation, the end of the casing string placed in the Macondo well included a shoe track comprised of a float collar with two check valves, a section of 7 inch casing and a ported reamer shoe. 71 BP speculates a number of possible factors, alone or in combination, contributed to the failure of the mechanical barrier: (1) contamination of the shoe track cement by nitrogen 68 BP Incident Investigation Team, supra note 58, at page C.F.R (c) (2003) C.F.R (b)(3) (2003). 71 BP Incident Investigation Team, supra note 58, at page

20 breakout from the nitrified foam cement; (2) contamination of the shoe track cement but mud in the wellbore; (3) inadequate design of the shoe track cement; and (4) swapping of the shoe track cement with the mud in the bottom of the hole. This regulation appears to require a device that is wholly inadequate to protect against a faulty cement job. c. The Negative Pressure Test Was Accepted After the cement job is complete and the well is being prepared for temporary abandonment, the integrity of the cement job is tested. There are two separate pressure tests that are used to check well integrity: a positive-pressure test and a negative-pressure test. 72 A positive-pressure test confirms that the casing and wellhead seal assembly are capable of containing a pressure inside the well. A negative-pressure test assess the integrity of the casing shoe track, the casing and the wellhead seal assembly to hold back formation pressure. Removing the mud and replacing it with seawater simulates the temporarily abandoned condition when the BOP and riser are removed. 73 MMS requires that both of these tests are performed but only gives a standard for the positive-pressure test. The CFR states that [y]ou may not resume drilling or other down-hole operations until you obtain a satisfactory pressure test. If the pressure declines more than 10 percent in a 30-minute test, or if there is another indication of a leak, you must re-cement, repair the casing, or run additional casing to provide a proper seal. 74 BP performed this test in two stages, a low-pressure test and a high-pressure 72 BP Incident Investigation Team, supra note 58, at page Id C.F.R (a) (2003). 20

21 test, and found that the well did not lose more than 10 percent of its pressure in 30 minutes. Once the well passed the positive-pressure test, the regulations require the negative-pressure test. The regulations read in part: [y]ou must perform a negative pressure test on all wells to ensure proper casing installation. You must perform this test for the intermediate and production casing strings. 75 Unlike the requirement for the positive-pressure test, there are no guidelines for what constitutes a successful negative test. The BP accident report states that a successful test is indicated by no flow from either the kill line or the drill pipe. 76 The report explains that there was a reading of 1,400 psi in the drill pipe, which indicated communication with the reservoir. A worker on the rig explained that this was caused by a phenomenon, the bladder effect, like one he had seen before. 77 The site leader accepted this explanation and because there was no indication of flow from the other passage, the kill line, the integrity of the well was accepted. 78 The BP internal investigation could not determine a plausible explanation to back up the worker s story. 79 Because the MMS regulations offered no guidance about a successful test, the abandonment of the well was allowed to proceed. This is a key area in which BP was allowed to use its discretion that likely led to the blowout C.F.R (b)(1) (2003). 76 BP Incident Investigation Team, supra note 58, at page Id. at page Id. 79 Id. 21

22 d. The Blowout Preventer Failed to Perform The regulations requiring the use of a BOP are some of the most detailed of section The regulations specify the number of shear rams, methods of independently operating the BOP system, requirements for remote controls and automation, and specific types of physical barriers in case of accidental disconnections. 81 However, the regulations for maintaining the BOP are not sufficient. BOP systems are to be maintained and inspected in accordance to an API standard and should be documented. 82 Pressure testing is required for a few minutes every two weeks. 83 This may have allowed too much time to elapse between tests when a BOP malfunction could have been detected. Additionally, modifications to the BOP do not have to be reported. The precise reason that the BOP did not prevent the blowout remains unclear. The internal investigation by BP includes conclusions by the company on the condition of the BOP before the blowout, and what happened before and after the accident. Before the accident, the BOP maintenance records were not accurate. BP also identified the inaccurate record in September Additionally, there were six leaks in the BOP hydraulic system but the report states that it is unclear if the leaks 80 You must design, install, maintain, test, and use the BOP system and system components to ensure well control. The working-pressure rating of each BOP component must exceed maximum anticipated surface pressures. The BOP system includes the BOP stack and associated BOP systems and equipment. 30 CFR (2003) C.F.R (2003) C.F.R (2003) C.F.R (2003). 84 BP Incident Investigation Team, supra note 58, at page

23 contributed to the BOP s failure. 85 Further, pressure and testing of the BOP when it was deployed were in compliance with industry and regulatory standards. However, the BOP was not tested at the surface, a circumstance required by Transocean s internal standards, but not by the regulations. 86 In sum, the blowout of the Macondo well likely could have been prevented if adequate industry regulations were in place. As discussed above, Halliburton was allowed to install unstable cement slurry in the well. Next, the mechanical barriers that are required to prevent a blowout in the event of a cement failure are insufficient. Further, the guidelines for pressure testing do not define what results are acceptable. Finally, inadequate maintenance requirements for BOPs leave the last line of defense from a blowout without sufficient safeguards to ensure functionality. VI. Possible Solutions and Conclusion The major factors in the Deepwater Horizon blowout seem to be a lack of enforcement resources and mechanisms, regulations which allowed for too much discretion and autonomy on the part of the regulated, and a systematic undermining of environmental laws and regulations designed to prevent this sort of disaster. Given this complex stew of problems with the status quo, and the focus of this paper, a few solutions seem plausible. First, implementing technology-forcing regulations like those in the Clean Water Act could create a regulatory framework in which there was more oversight of technology and safety standards. As it stood, [i]nstead of requiring that the lessees demonstrate that their safety technology performed as well as the best available 85 BP Incident Investigation Team, supra note 58, at page Id. 23

24 technology, regulators simply accepted assurances that a blowout was unlikely and adopted industry standards. The absence of any technology-forcing mandate in the statute meant that industry lacked any incentive to develop new and better safety technology. 87 Another option, in the world of industry-set standards, may be increasing penalties for their violation. In an industry that must innovate or die as oil and natural gas become more and more elusive, the most plausible regulatory framework may be the one which allows the industry to propose and implement its own technology and safety standards. In this context, raising penalties for violations may be the most efficient means of ensuring compliance with safety standards. For that to be possible, though, the regulators must have the required resources to inspect facilities, identify violations, and enforce the rules. This was not the case when the Deepwater Horizon blew. 88 Finally, actually enforcing the protective environmental regulations as written could provide more oversight of the technology and safety standards employed in each project. BP, for example was able to submit an exploration plan for the Gulf of Mexico detailing potential effects on walrus and other fauna not present in the area having simply cut-and-pasted from an Alaska-region exploration plan. This carelessness was present in much of the oversight process. Doing away with certain categorical exclusions, exempting industry actors from further NEPA review would be an ideal starting point. Environmental assessment at the exploration and development stages is 87 Flournoy, et al. Page Flournoy p

25 the best opportunity to focus on specific impacts of the precise plan of exploration or development proposed. 89 In sum, in a field such as offshore drilling, regulators will struggle to keep up with the rapid changes in technology which are necessary to sustain the industry. The more interconnected the regulatory framework, however the more the technology standards are tied to environmental goals, such as BAST, and to safety requirements the more checks there are to catch rogue actors and potential failures. Most analysts agreed that there were many points in the story of the Deepwater Horizon at which the disaster could have been averted. The trick will be, from this point forward, to engage and tweak the existing framework in ways that implement rather than undermine the stated goals of safety, environmental protection, and continued exploration and development. Secretary of the Interior Ken Salazar was right when he noted, [f]or the past two decades, the deep waters of the world s oceans have been the so-called final frontier for the oil and gas industry as they raced to drill deeper, faster, and farther out for resources and profits. 90 Now, it remains to be seen if he was right when he concluded, [t]hose days of big risks are over Flournoy, et al. Page Ken Salazar, Raising Bar for Deepwater Drilling, The Houston Chronicle, August 22, Id. 25