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Who’s Watching? Regulating Technology and Safety Standards in Deepwater Drilling: 1897-2010

Exam Numbers 199346 & 362783

I. Introduction………………………………………………………………….page 1 II. Offshore Drilling in the United States, 1887-Today…………………..page 2

a. The Early Years: 1887-1953…………………………………………...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

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

I. Introduction

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 1897.1 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 Rapidly-

advancing 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 66. 2 Offshore Magazine, “Milestones and Influences in U.S. Offshore History (1947-1997),” May 1, 1997. Available at http://www.offshore-mag.com/index/article-display/23876/articles/offshore/volume-57/issue-5/news/special-report/milestones-and-influences-in-us-offshore-history-1947-1997.html.

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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: 1887-1952

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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, http://www.noia.org/website/article.asp?id=123. 4 American Oil & Gas Historical Society, “Offshore Oil History,” available at http://sites.google.com/site/petroleumhistoryresources/Home/offshore-oil-history. Accessed October 29, 2010. 5 Bartley, supra note 1, at page 67. 6 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. 404. 9 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 http://www.coastal.ca.gov/energy/ocs99.pdf.

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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 3.

11 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 4. 13 Id. 14 Bartley, supra note 1, at page 67. 15 American Oil & Gas Historical Society website, supra note 4.

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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 3. 18 Michael J. McHale, “An Introduction to Offshore Energy Exploration—A Florida Perspective,” 39 J.Mar.L.&Com. 571, 573 (2008). 19 332 U.S. 19, 30 (1947) Id. at 39. 20 339 U.S. 699 (1950); 339 U.S. 707 (1950).

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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

21 332 U.S. at 21. 22 McHale, supra note 18 at 574; H.R. Rep. No. 695, 82nd Cong., 1st 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. §§ 1331-1356 (2002).

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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 576. 26 43 U.S.C. §1334(a)-(d). 27 Larson, supra note 11, at page 59. 28 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 103.

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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 http://www.progressivereform.org/articles/BP_Reg_Blowout_1007.pdf Accessed Nov. 2, 2010. 31 Larson, supra note 11, at page 62, quoting 43 U.S.C. § 1802 (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 http://www.eia.doe.gov/pub/oil_gas/natural_gas/feature_articles/2005/offshore/offshore.pdf. 34 Wiygul, supra note 28; Flournoy et al., supra note 30 at page 13.

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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 well-

trained 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 13. 36 43 U.S.C. §1347(b) (1988). 37 Wiygul, supra note 28 at Section 5. 38 43 U.S.C. §1332(6).

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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 technology-based effluent limits. See Claudia Copeland, “Clean Water Act: A Summary of the Law,” Congressional Research Service, April 23, 2010, available at http://www.nationalaglawcenter.org/assets/crs/RL30030.pdf. 40 Wiygul, supra note 28 at Section 5. 41 Flournoy et al., supra note 30, at page13. 42 30 CFR 250.243(e).

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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 6. 44 Id. at page 29. 45 National Environmental Policy Act Regulations, 40 C.F.R. 1500 et seq. 46 Flournoy et al., supra note 28, at page 30.

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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 2009. 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.48

47 U.S. Coast Guard et al, “Spill of National Significance (Gulf SONS) Joint After Action Report 22, p. 22 (2002), available at http://www.uscg.mil/history/docs/2002SONSAARfinalReport.pdf. 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 http://energycommerce.house.gov/documents/20100720/Stupak.Statement.07.20.2010.pdf

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In 2005, MMS agents were able to inspect 1,292 rigs, while in 2009, they were

able only to inspect 760.49

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 http://www.cozen.com/admin/files/publications/Deepwater_Horizon_White_Paper_Final.pdf. 50 Flournoy et al., supra note 30, at page 22.

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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 300 - 400 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 2. 52 Id. at 2. 53 Id. at 3. 54 Id. at 3-4.

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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 . 56 30 C.F.R. §250 (1999).

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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, 2009.58 BP completed the engineering design for

the well in June 2009. 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

57 30 C.F.R. §250.411 (2003). 58 BP Incident Investigation Team, "Deepwater Horizon Accident Investigation Report," page 15 (Sept. 8. 2010) available at http://www.bp.com/liveassets/bp_internet/globalbp/globalbp_uk_english/incident_response/STAGING/local_assets/downloads_pdfs/Deepwater_Horizon_Accident_Investigation_Report.pdf. 59 Id. at 16. 60 30 C.F.R. §250.465(a)(1) (2006).

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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 10-11.

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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 http://www.oilspillcommission.gov/sites/default/files/documents/Letter%20from%20Fred%20Bartlit%20to%20Commissioners.pdf. 63 Id. at 2. 64 API RP10B-2/ISO10426-2 65 American Petroluem Institute Website, http://www.api.org/aboutapi/. 66 BP Incident Investigation Team, supra note 58, at page 34. 67 Id.

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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 35. 69 30 C.F.R. §250.420(c) (2003). 70 30 C.F.R. §250.420(b)(3) (2003). 71 BP Incident Investigation Team, supra note 58, at page 37.

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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 82. 73 Id. 74 30 C.F.R. §250.423(a) (2003).

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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.

75 30 C.F.R. §250.423(b)(1) (2003). 76 BP Incident Investigation Team, supra note 58, at page 88. 77 Id. at page 89. 78 Id. 79 Id.

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d. The Blowout Preventer Failed to Perform

The regulations requiring the use of a BOP are some of the most detailed of

section 250.80 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 2009.84 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 250.440 (2003). 81 30 C.F.R. §250.442 (2003). 82 30 C.F.R. §250.446 (2003). 83 30 C.F.R. §250.447-448 (2003). 84 BP Incident Investigation Team, supra note 58, at page 178.

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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 178. 86 Id.

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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 13. 88 Flournoy p. 19.

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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.”91

89 Flournoy, et al. Page 17. 90 Ken Salazar, “Raising Bar for Deepwater Drilling,” The Houston Chronicle, August 22, 2010. 91 Id.