AUGER TENSION-LEG PLATFORM

¶Like a giant alien creature, a scale rendering of a tension-leg drilling platform is superimposed over New Orleans. Built by Shell to tap its Auger deepwater field some 200 miles southwest of the city, the huge platform uses steel mooring cables to stabilize its 3,000-foot legs and can drill 20,000 feet below the seafloor. The platform augured well for Shell in the late 1990s, delivering 100,000 barrels of oil a day.

¶Courtesy of Shell

¶Deepwater Treasures

¶The productivity of the Auger wells made the Gulf of Mexico the hottest oil play in the world. And it was mostly about oil. Deepwater proved to be largely oil-prone. The source rocks for most of the deepwater region are an Upper Jurassic kerogen that generates natural gas only when subjected to very high temperatures. But subterranean thermal gradients and source-rock temperatures in the deep Gulf are quite modest, despite the enormous pressures exerted several miles below the seabed. The massive amounts of salt (see below) has acted like a heat sink, keeping hydrocarbons from getting too hot and thus cooking up large amounts of natural gas.77

¶Despite downward pressure on oil prices in the late 1990s, the promise of prolific production from deepwater was too much to resist. Exploration and production firms with deepwater leases consolidated their positions. Companies that had sat on the sidelines during the 1980s stampeded into unclaimed areas. Newly developing or commercialized exploration and production technologies found vibrant new markets. Contractors all along the Gulf Coast and, indeed, around the world, geared up for a surge of activity. Port Fourchon, Louisiana's southernmost port on the tip of Lafourche Parish, came to life as the jumping-off point for supplying and servicing deepwater operations in the Gulf.78

The next landmark on the horizon for deepwater drilling was Mars. In July 1996, Shell began producing from its Mars platform, six months before NASA launched its Pathfinder probe to the planet Mars. At a total cost of $1 billion, Shell's Mars was more than three times as expensive as the Mars Pathfinder, and its remote technologies and engineering systems were arguably more sophisticated. The investment of money and technology paid dividends: the Mars platform tapped into the largest field discovered in the United States since Alaska's Prudhoe Bay. Creating a system to produce the field also established a new paradigm for large projects and revealed how exploration and production strategy was being reshaped in the Gulf.79

To reduce costs and avoid the headaches experienced at Auger, Shell introduced a different contracting model at Mars based on "alliances," including the sharing of technology and patents. Shell ended up giving away more than BP, which had little deepwater experience. But the costs and risks were too large to go it alone, as Shell had usually preferred to do. The partners carried the alliance concept over to their relationship with contractors, who built the tension-leg platform hull, fabricated the topsides, and integrated the two. The project team brought in contractors early on to collaborate on developments and share risks and rewards. The key advantage of this approach was that it reduced the so-called "cycle time" of design, bidding, and contracting by an estimated six to nine months.80 On a platform such as Mars, where the first well came in at 15,000 barrels per day, the time- value of money made at the beginning rather than at the end of the platform's life was quite significant. Shell's contracting model at Mars, replicated on its subsequent tension-leg platforms, established the growing importance of alliance networks for global oil and gas developments in technologically complex frontier regions characterized by high costs and risks.81

In the late 1990s, having control of one-third of all Gulf leases in depths greater than 1,500 feet, Shell rolled out one tension-leg platform after the other.82 In 1997, a Mars "clone" called Ram-Powell, developed in a joint venture with Exxon and Amoco, went on-stream in 3,200 feet of water 80 miles southeast of Mobile, Alabama. In March 1999, Shell and its minority partners, BP, Conoco, and Exxon, started up the massive Ursa, on a lease two blocks to the east of Mars. Nearly double the weight of Mars, Ursa was designed to accommodate astounding initial well-production rates of 30,000 barrels per day; in September 1999, a well at Ursa broke all records with a production rate of nearly 50,000 barrels of oil equivalent per day. Finally, in 2001, Shell brought in production from the Brutus platform, which tapped into a 200-million-barrel field in 3,000 feet of water in the Green Canyon.83

Shell's new technologies solidified the company's position as the leader in the Gulf. Its tension-leg platforms, as well as major fixed platforms such as Bullwinkle and West Delta 143, not only produced hydrocarbons from the fields beneath them, but also served as hubs used to take and process oil and gas production from satellite subsea wells, thus extending the life of those platforms once their own production declined. Deepwater output from Shell's platforms and subsea wells, and eventually from other companies in the vicinity, fed into network of Shell-owned or operated crude-oil trunk pipelines, gathering systems, and natural-gas pipelines. Shell also made special arrangements to

¶FIGURE 2.4: Wells Drilled in the Gulf of Mexico by Water Depth, 1940-2010

Wells Drilled in the Gulf of Mexico by Water Depth, 1940-2010 12,000

¶10,000

¶8,000

¶Water Depth

¶6,000

¶4,000

¶2,000

1940 1950 1960 1970 1980 1990 2000 — 2010

Year Source: Commission staff, adapted from Bureau of Ocean Energy Management, Regulation and Enforcement

¶transport crude oil production from its growing deepwater properties into the Clovelly storage facilities owned by the Louisiana Offshore Oil Port in South Louisiana. By 2001, Shell operated 11 of the 16 key oil trunk pipelines servicing deepwater.84

¶Shell's lead in the deepwater Gulf was substantial but not unassailable. During the latter half of the 1990s, many companies gained ground, including a rising percentage of small and midsized independents. But the only company that chased down and eventually overtook Shell was BP.

¶Deeper Still

¶In the 1990s, technological breakthroughs in imaging and drilling through massive salt sheets opened a new "subsalt" play, first on the shelf and then ranging into deepwater. Discoveries in at least four different "fold belts" across the Gulf of Mexico extended the search for oil into "ultra-deepwater" and led to another wave of innovation in floating production. In 1990, most oil and gas from the Gulf had still come from shallow water; average production-weighted depth had barely reached 250 feet. By 1998, the weighted average passed the 1,000-foot milestone, at which point deepwater production (at about 700,000 barrels per day of oil and 2 billion cubic feet per day of gas) surpassed that from shallow water for the first time.85

¶As the industry moved deeper, the abandonment and decommissioning of older platforms on the shelf became a thriving business. During the 1990s, 1,264 platforms were removed, more than twice the total prior to 1990; after 2000, removals continued at a rate of 150

per year.86 Some obsolete platforms found use as "artificial reefs" through a creative program, coordinated by the Minerals Management Service and the states of Texas and Louisiana, to place old platforms in specially designated locations on the sea bottom, where they attracted marine life much like natural reefs.87

Meanwhile, another relaxation in the terms of access to Gulf of Mexico leases, in the form of the Deepwater Royalty Relief Act (see Chapter 3), helped sustain the oil industry in deepwater. Deepwater royalty relief no doubt enticed some oil companies, especially non-majors, into deepwater. But judging from the huge upswell in bidding at the May 1995 Central Gulf of Mexico sale, before royalty relief was enacted, the race appeared to be already under way.88 Oil explorers were clearly gunning for fields like Auger with high flow rates and high ultimate reserves. Many of them were also on the hunt for petroleum in a new geological location: beneath the Gulf 's massive sheets of salt.

Subsalt Discoveries Salt is the dominant structural element in the Gulf of Mexico petroleum system. Oil explorers had long ago discovered oil trapped against the flanks of salt domes or between the salt diapirs in the deepwater mini-basins. But geologists had typically assumed that there could be no oil reservoirs lying beneath any salt they encountered. By the 1970s, advancing knowledge about the basin's regional geology suggested that oil could be found under the salt. In many places, the salt pillars that extruded upward into sandstone and shale flowed horizontally in elastic plumes over vast expanses of younger, potentially oil-bearing sediment that extend more than 35,000 square miles across the Gulf. Geologists invented new terminology to describe different kinds of salt formations in the picture they pieced together—canopies, tongues, nappes, egg crates, and turtle domes—and established a special subfield of geology to explain how the salt moves. What they were really interested in, however, was what lay beneath the salt.89

The subsalt play began in 1990, when Exxon (with partner Conoco) made the first discovery at a prospect called Mickey. Located in 4,352 feet of water on the Mississippi Canyon 211 lease (about 10 miles northeast of where BP would later drill Macondo), Mickey was not then large enough to put into production.* Two years later, Chevron drilled a well in Garden Banks 165 through almost 7,000 feet of salt and another 5,000 feet of subsalt sediment. The well found no oil, but was a milestone because it demonstrated that the technology existed to drill through an enormous body of salt.90

Finally, in 1993, Phillips Petroleum announced the first commercial subsalt oil discovery. Years earlier, Phillips had begun to look systematically for places where salt sheets might be obscuring oil reservoirs. In 1989, the firm acquired 15 leases including one at a location called Mahogany. It was a speculative move. Salt plays tricks with seismic sound waves, which travel through salt at a much higher velocity than through the surrounding sediments and also get refracted, much as the image of a pencil is bent when it is stuck in a glass of water. Obtaining clear images of rocks in their proper location under the salt seemed almost impossible. To get a better focus, Phillips shot a 3-D seismic survey over

. * Ten years later, Exxon developed the prospect as a subsea natural gas development called Mica

¶The subsalt play progressed, haltingly, from Mahogany. Drilling through salt involved myriad technical complications. Under high temperature and pressure, salt masses flow, creep, and deform like plastic; this movement can shift the well casing and production tubing. These wells also had to be drilled to great depths, escalating costs. And limitations on computer power made it difficult to obtain reliable seismic images from beneath the salt, adding risk to exploration. Subsalt wells missed hydrocarbons a lot more often than they hit them.92

¶As operators drilled a string of dry holes, the post-Mahogany euphoria ebbed. In the 1995–1997 lease sales, companies began to turn from shallow subsalt prospects, pursuing instead ultra-deepwater (greater than 5,000 feet) prospects, looking for easier-to-image drilling targets in foldbelts formed by the lateral movement of salt and sediment. In 1995, Oryx Energy made a discovery at Neptune, opening a new play in the Western Atwater Foldbelt. The next year Shell announced a strike at its Baha prospect in the far western Gulf. This discovery initiated the Perdido Foldbelt play in more than 8,000 feet of water.93 A deeper ocean frontier, once again, beckoned the industry.

¶An Industry Restructured—and Globalized

¶As geologists and geophysicists in Houston dedicated themselves to solving the riddles presented by depths of the Gulf of Mexico, the world oil industry began a radical restructuring. Oil and gas companies had not yet recovered from the 1980s bust when oil prices swooned again in the late 1990s, driven in large part by the drop in global demand precipitated by the Asian financial crisis. Increased shareholder pressure on oil firms to improve short-term financial results and longer-term profitability spurred one of the greatest merger movements in history. In 1998, BP acquired Amoco. The next year, Exxon merged with Mobil in an $80 billion deal to create the world's largest company. BP-Amoco countered by acquiring ARCO; Total merged with Fina and Elf (renamed Total in 2003); Chevron combined with Texaco; and, finally, Conoco and Phillips joined to create the sixth "super major" (along with Royal Dutch Shell). During these consolidations, many companies relocated staff from New Orleans and elsewhere to Houston, reinforcing that city's claim as the international oil capital.94

Mergers boosted results as management pared away overlapping functions and laid off employees, reinforcing the trend toward outsourcing R&D and reducing internal technological expertise. Mergers benefitted the oil industry, on the other hand, by equipping firms with new capital reserves needed to finance long-term growth strategies— some of them dependent on riskier, but potentially higher-return, ventures. The deepwater Gulf figured significantly in the growth strategies of all the "super major" oil companies— albeit as only one among several frontier provinces worldwide. They took renewed interest in Arctic and sub-Arctic regions and began to invest in other deepwater basins from the northeast Atlantic west of the Shetland Islands, to the Campos Basin off Brazil, to West Africa's Gulf of Guinea and offshore Angola, to northwest Australia. By the early 2000s, analysts regarded the three provinces rimming the central Atlantic Ocean—the Gulf of Mexico, Brazil, and West Africa—as the "New Golden Triangle," the place where the largest future reserves were likely to be found.95

Echoing the oil companies, consolidation also swept through offshore contractors. After half of the world's seismic crews were idled in 1999 due to a price collapse early in the year, the ensuing shakeout left only handful of seismic contractors, led by Western-Geco, owned by Schlumberger and Baker-Hughes; Petroleum Geo-Services; and CGG and Veritas (which merged in 2007). The major oil-service companies, which provided a variety of drilling, evaluation, well-completion, and production services, began to combine at the same time (notable was the 1998 merger between the oilfield giants, Halliburton and Dresser Industries). Most significantly, the drilling-contractor industry—continuously in the process of mergers, acquisitions, and bankruptcies—consolidated further. In 1999, Sedco-Forex and Transocean, themselves the products of earlier mergers, became Transocean Sedco Forex, later simplified as Transocean. In 2000, it acquired R&B Falcon, whose assets included a semisubmersible under construction in Korea by Hyundai Heavy Industries called the Deepwater Horizon. In 2001, Global Marine merged with Santa Fe, and six years later this firm became part of the modern Transocean, by far the largest offshore drilling firm in the world.

During this era, offshore oil exploration and production became an increasingly global enterprise. U.S. operators searched for oil in deepwater basins outside the Gulf of Mexico, and more than ever, companies such as Norway's Statoil, Brazil's Petrobras, and France's Total were drilling in the Gulf. Shipyards along the Gulf Coast—the pioneers in design and construction of mobile offshore drilling units—had by the 1990s almost totally surrendered this work to competitors in Korea and Singapore. Many of the largest offshore engineering, construction, and pipelaying firms (Heerema Marine Contractors, Technip, Worley Parsons, and others) were globally oriented companies based outside the United States.96

Offshore contractors headquartered in the Gulf survived by expanding internationally. Morgan City's J. Ray McDermott branched out around the world more aggressively after the 1980s industry depression and eventually moved its headquarters to Houston. Louisiana-based Gulf Island Fabricators, Chet Morrison Contractors, Global Industries, and even Frank's Casing Crew and Rental Tools grew from small, family-owned firms servicing operations in the Gulf to become major offshore contractors active worldwide.

¶BP's Moment

¶In the late 1990s, the global company making the biggest news in the Gulf of Mexico was BP. Founded in 1908 and since 1954 named British Petroleum, it had for decades built its business around access to crude oil from Iran and neighboring Middle Eastern countries. In the 1960s and 1970s, BP achieved great success in discovering and developing oil reserves in the North Sea and in Alaska's Prudhoe Bay. By the early 1990s, however, BP had been exiled from the Middle East and Nigeria. Production from Prudhoe and the North Sea were in decline. Billions of dollars had been invested in unprofitable nonpetroleum ventures. And an ambitious exploration program had yet to bear fruit. The company tottered on the brink of bankruptcy.97

¶Sir John Browne, a forceful exploration manager whose father had also worked for BP, orchestrated its stunning turnaround. In the 1980s, as executive vice president of Sohio, BP's American subsidiary, he reined in spending and cut staff in order to place the company on better footing. Returning to London in 1989, he reorganized BP's exploration arm; Browne slashed expenditures, established a rigid—if not ruthless—performance ethic, and refocused on high-risk but potentially high-reward opportunities. Upon becoming chief executive in 1995, he directed a major part of BP's upstream focus to the deepwater Gulf. In the deals he negotiated to acquire Amoco and ARCO, BP emerged with a greatly expanded portfolio of Gulf leases and assets.98

¶In the late 1990s, BP's Gulf exploration team made a series of remarkable deepwater discoveries. Once the fields came online, they vaulted BP ahead of Shell as the Gulf 's largest oil producer. BP prided itself as a "fast follower," rather than an "early adopter," in exploiting technological innovations. BP had closely followed Shell at Mars and quickly applied what it had learned to develop the Marlin field with a tension-leg platform in 3,400 feet of water. BP also joined with Exxon in developing deepwater discoveries at the Hoover and Diana fields in the western Gulf. After the string of subsalt dry holes in the mid-1990s, some of BP's competitors began looking for other kinds of plays the Gulf might still present. Shell shifted to managing production from its large number of deepwater developments. But BP sprang faster than anyone to confront the Gulf 's nagging exploration challenge—the salt.⁹⁹⁹⁹ Testimony of Steve Bertone, 37. Commission staff analysis of MMS yearly budget request and enactments, by nominal and real (2005) dollars. Ibid. "Shell 'Ignored Accident Warning,'" BBC online, June 14, 2006, http://news.bbc.co.uk/2/hi/5077886.stm; Terry Macalister, "Shell Accused Over Oil Rig Safety," The Guardian, June 23, 2006.

¶In a costly and complex undertaking, BP combined new advances in computer processing for 3-D seismic imaging with new methods of acquiring seismic data from multiple directions to gather a better understanding of the salt history, stratigraphy, and the sources and migration pathways of oil in deepwater. BP's scientists and engineers found geographically promising areas just as large as those discovered and profitably exploited on the shallower continental shelf. Based on their analyses, they began to believe that the deepwater frontier could ultimately hold 40 billion barrels of commercially exploitable oil—four times the prevailing estimates. Said Dave Rainey, BP's deepwater exploration manager, "One of the lessons we have learned about the Gulf of Mexico is never to take it for granted."100

¶FIGURE 2.5: U.S. Crude Oil Production, 1990-2035 (projected)

¶Barrels of Oil Per Day (Millions)

1990 2000 2008 2015 2025 — 2035

Year • Alaska • Offsore Lower 48 • Onshore Lower 48 Source: Commission Staff, Adapted from U.S. Energy Information Administration

As this chart makes clear, overall production of crude oil in the U.S. has been declining for decades. However, production from deepwater wells in the Gulf of Mexico (Offshore Lower 48) is on the rise.

A new generation of drilling vessels coming onto the market, along with advances in drilling, encouraged BP to take the risk to explore those prospects. Outpacing most of the industry by a year, the company shifted its sights to prospects in much deeper waters. Rich rewards followed with a historic string of giant oil finds in subsalt formations ranging out to 7,000 feet of water. In 1998, BP struck oil in the deepwater subsalt of the Green Canyon's Mississippi Fan Foldbelt at Atlantis (minority partner BHP Billiton) and Mad Dog (minority partners BHP Billiton and Chevron), two of the largest fields ever discovered in the Gulf of Mexico. Atlantis's original reserves estimates were 400–800 million barrels of oil equivalent and Mad Dog's were placed at 200–450 million barrels. In 1999, working for BP (and minority partner Exxon) in 6,000 feet of water in the Mississippi Canyon, Transocean's Discoverer Enterprise drilled the largest Gulf field of all time, a subsalt prospect called Crazy Horse (subsequently renamed Thunder Horse), containing more than

¶500 million barrels, called Thunder Horse North.102 Also that year, BP and yet another partner, Chevron, discovered a 100 million barrel field in 7,000 feet of water at their Blind Faith prospect in the Mississippi Canyon. (In the harsh glare of hindsight following the Macondo blowout, the executive director of the Natural Resources Defense Council commented that, in the name Blind Faith, "It would be hard to find a more fitting symbol of the oil industry's steady and assertive advance into the Gulf 's deep waters, or the corporate thinking behind it."103)

¶In August 2002, BP's Browne boldly announced that the company would spend $15 billion during the next decade on drilling and developing these discoveries. BP had become the largest-acreage holder in the deepwater Gulf, with more than 650 tracts in water depths greater than 1,500 feet, and in possession of one-third of all deepwater reserves then discovered. The deepwater Gulf of Mexico, Browne asserted, would be the "central element" of BP's growth strategy.104 "The question is how they will manage the embarrassment of riches they have," said one analyst at the time. "They have a bunch of projects and they need to coordinate people and contractors. There is the sheer scale of the facilities and the size of the investment required—all this before a drop of oil ever comes out of the ground."105

¶Clouds on the Horizon

¶After BP's impressive discoveries, the industry dove into deeper waters across the Gulf. From 2001 to 2004, operators found 11 major fields beneath water 7,000 feet deep or more. Most deepwater discoveries were made in relatively young sandstones of the lower Miocene era. But companies increasingly explored down into the deeper and older Paleogene or "Lower Tertiary" strata found in the foldbelts near the edge of the Sigsbee Escarpment, a salt sheet that resembles a near-surface moonscape extending to the base of the continental slope. In 2006, Chevron and its partners Devon Energy and Statoil disclosed promising test results from a two-year-old discovery at its Jack prospect, proving that Lower Tertiary reservoirs could produce oil at pressures encountered at great depths, creating excitement that the Lower Tertiary play might ultimately yield between 3 billion and 15 billion barrels of hydrocarbons—collectively rivaling the size of the great Prudhoe Bay discovery. This implied a future for ultra-deep drilling, ranging out to 10,000-foot water depths and 25,000 feet beneath the seafloor. Reported the Oil & Gas Journal, "The Jack-2 test results boost confidence in that potential and highlight the central role technology plays in future supply."106

¶The industry was in need of a confidence booster after the previous three years of development challenges that had sorely tested BP's and the industry's confidence and conviction about deepwater.

¶BP's decision to develop multiple deepwater fields at once was an incredibly ambitious undertaking. Its program focused on the major fields at Holstein (a discovery above the salt), Mad Dog, Atlantis in the Green Canyon, and Thunder Horse in the Mississippi

¶BP Thunder Horse Platform

BP's mighty Thunder Horse platform was out-muscled by Hurricane Dennis in 2005 as it was being readied for service. Evacuated crews returned to find the semi-submersible production facility listing badly. After repairs and thorough analysis, additional problems were discovered that put the platform further behind schedule. For BP it was worth the wait: By 2009 Thunder Horse was producing a whopping quarter-million barrels a day.

¶Getty Images/U.S. Coast Guard photo/PA3 Robert M. Reed/digital version by Science Faction

Canyon—with total potential reserves of 2.5 billion barrels of oil, in water ranging from 4,000 to 7,000 feet deep, requiring wells reaching 30,000 feet in total depth. To produce oil at these places, BP selected "truss spars" for Holstein and Mad Dog, and semisubmersibles (such as the one BP and Shell had introduced at Na Kika), for Thunder Horse and Atlantis.107

Beyond about 4,000-foot depths, the weight of tension cables was too great, so BP could not employ tension-leg platforms, the workhorses at Shell's first deepwater projects. The spar, successfully demonstrated in 1996, is a giant buoy consisting of a large-diameter, vertical cylinder supporting a deck for drilling and processing. Its deep-draft floating caisson keeps about 90 percent of the structure underwater, giving the structure favorable motion characteristics. During 2000–2005, Kerr-McGee (acquired by Anadarko in 2006) went on to pioneer several innovations in spar designs.108

BP's choice between spars and semisubmersible production facilities depended upon different economic, functional, and safety factors at each field. All four projects would be linked by pipeline to a platform hub, where crude oil would be transferred into a 390- mile pipeline, the Cameron Highway, and transported to refineries at Texas City and Port Arthur. All four projects, as well as Na Kika, also would connect to the BP-operated Mardi Gras transportation system, itself a billion-dollar project that integrated five different

¶FIGURE 2.6: Deep Discoveries

00 f 10 t

¶ft

¶5000 ft

¶7500 ft

1975–1989 • 2004–2005
1990–1999 • 2006–2007
2000–2003 • 2008 pipelines covering a total of 450 miles, with capacity to transport 1 million barrels of crude and 1.5 billion cubic feet of natural gas per day. The selection and development of technology on all these projects was a major challenge at every step, given the extreme water depths, reservoir conditions, and associated environmental issues. Thunder Horse had an unusually high pressure/high temperature reservoir. Atlantis was located under complex seafloor topography near the steep Sigsbee escarpment, and a large portion of the field was subsalt. Mad Dog lay under a massive salt canopy, causing large uncertainties in describing the actual reservoir. The Holstein geology forced BP to use a spar with wells housed on the platform. As BP production managers admitted in 2004, "None of the projects can be categorized as 'business as usual.'"109

¶The $5 billion Thunder Horse project was especially challenging. A major incident in drilling occurred even before the semisubmersible facility was put in place. In May 2003, the top of the drilling riser on the Discoverer Enterprise broke loose from the vessel, ripped apart again 3,000 feet under the surface, and left the lower marine riser package to collapse on and around the top of the blowout preventer, where the riser and drill pipe snapped off. The blowout preventer's blind shear rams were activated and worked as designed, averting any spill. "No one was hurt, and the well was secure," BP reported, "but the initial scene was daunting."110

¶An even bigger scare awaited the Thunder Horse semisubmersible production facility, which was towed to the field and moored on location in April 2005. As work proceeded to connect the predrilled subsea wells and commission all the facilities above and below the

water, Hurricane Dennis neared in July, forcing the evacuation of all personnel and leaving the production facility unmanned. "No one could have anticipated the major shock that awaited the first helicopter flights after the storm had passed," according to one official BP account. The columns and other areas of the hull had filled with water, causing the facility to list to one side. Investigations later revealed that a valve in the bilge and ballast system had been installed backward, allowing seawater to move into the hull, a failure exacerbated by electrical pathways that were not watertight. Had BP not arrived when it did, the structure might have been lost. Crisis management crews were able to right the facility within a week, but reworking Thunder Horse's hull systems delayed commissioning for a year. Similar work on the Atlantis semisubmersible production platform pushed its installation back several months, too, until July 2006.111

Nor was that the end of BP's major shocks—it discovered that a weld had cracked open on one of the Thunder Horse manifolds that collected oil from the network of satellite subsea wells. The company made the difficult decision to pull out all the manifolds and subsea equipment that had a similar weld configuration— adding hundreds of millions of dollars to the cost of the project. After a lengthy investigation, engineers found that minute cracks had formed in the thermal insulation on the manifold pipe work, leading to reactions that embrittled the weld interface. BP and contractors developed new weld techniques, created more rigorous inspection and assurance procedures, and refurbished all the affected subsea equipment on Thunder Horse and at Atlantis. Thunder Horse finally delivered its first oil on June 2008, three years behind schedule.112 By March 2009, production ramped up to 250,000 barrels per day, 4.5 percent of total U.S. daily production. (Atlantis went online a year before Thunder Horse, in 2007, but BP has been dogged by accusations that Atlantis has not been in compliance with safety and environmental regulations.113)

Damaging Hurricanes BP was not alone confronting environmental challenges. During 2002 and 2004–2005, hurricanes ravaged the Gulf Coast, with major impacts on offshore infrastructure and operations. In September 2002, Hurricane Lili blew into the heart of the Ship Shoal, Eugene Island, and South Marsh Island areas, damaging platforms and pipelines. Two years later, Ivan—a Category 4 storm—swept through the alley east of the Mississippi River delta, causing mudflows and anchor-dragging by mobile drilling units that tore up undersea pipelines. The following year, Hurricane Katrina flooded New Orleans and points east, with horrible effects. Offshore, Katrina destroyed 47 platforms and extensively damaged another 20. The 1,000-ton drilling rig on Shell's Mars platform collapsed, prompting an around- the-clock onsite recovery effort.

A month later, Hurricane Rita, storming farther west, wiped out 66 platforms and broke up another 32. Rita capsized Chevron's Typhoon, an unfortunately named mini-tension-leg platform. The majority of the platforms obliterated in these two storms were from an early generation of Gulf facilities, more than 30 years old. The two hurricanes also damaged more than 70 vessels and nearly 130 oil and natural gas pipelines, as they hit more prolific and sensitive areas than previous storms and, accordingly, caused much more extensive damages. Ominously, the short interval between the two storms exhausted the resources available for normal recovery and overwhelmed support bases.114

¶The Oil Industry and Deepwater Technology at Decade's End

¶As the end of the decade approached, the offshore industry in the Gulf had recovered from hurricane devastation and pressed on with deepwater and ultra-deepwater developments. Although many independent companies (such as Anadarko, Hess, BHP, Newfield, Marathon, and Mariner) had substantial deepwater leases and were actively exploring and developing them, the edge of the frontier was mainly the playground of the super-majors and firms with partial government ownership, such as Norway's Statoil and Brazil's Petrobras.115

¶In September 2009, Transocean's Deepwater Horizon semisubmersible made a historic discovery for BP at the company's Tiber prospect in the Keathley Canyon. Drilling in 4,000 feet of water and to a world-record total depth of 35,055 feet, Deepwater Horizon tapped in a pool of crude estimated to contain 4 to 6 billion barrels of oil equivalent, one of the largest U.S. discoveries. Six months later, in March 2010, Shell (with partners Chevron and BP) started production at its Perdido spar in 8,000 feet of water in the Alaminos Canyon. A hub for the development of three fields, Perdido was the world's deepest offshore platform, and the first project to pump oil and gas from the Lower Tertiary. Other Lower Tertiary developments were coming onto the horizon. Later in the year, Petrobras planned to develop the Gulf 's first floating production, offloading, and storage facility to produce from Lower Tertiary reservoirs at its Cascade and Chinook prospects. By 2010, the industry had announced 19 discoveries in the Lower Tertiary trend,¹⁴¹⁴ "Global 500," CNNMoney.com, July 26, 2010, http://money.cnn.com/magazines/fortune/global500/2010/full_ list/index.html. Tyler Priest, "Auctioning the Ocean: The Creation of the Federal Offshore Leasing Program, 1954-1962," History of the Offshore Oil and Gas Industry in Southern Louisiana: Vol. 1: Papers on the Evolving Offshore Industry (Minerals Management Service OCS Study 2004-049, 2008). Other states petitioned for the 9-nautical-mile boundary in the federal courts, but failed to prevail. Internal BP document (BP-HZN-CEC 8848-58).Show full note of them containing more 100 million barrels of oil equivalent.116

¶Technical Tests The fanfare around these discoveries and developments could not disguise the fact that the technical challenges of ultra-deepwater drilling and production and the subsalt geology remained unique and formidable. Water depths are extreme, down to 10,000 feet. Total well depths, as Tiber demonstrated, can go beyond 30,000 feet. Well shut-in pressures can surpass 10,000 pounds per square inch. Bottom-hole temperatures can exceed 350 degrees Fahrenheit. Salt- and tar-zone formations can be problematic. The sandstone reservoirs are tightly packed, and ensuring hydrocarbon flow through risers and pipelines can be difficult. According to a 2008 report from Chevron engineers for the Society of Petroleum Engineers, all these factors "separate many [Gulf of Mexico] deepwater and ultra-deepwater wells from deepwater and ultra-deepwater wells in other parts of the world."117

¶Drilling in extreme water depths poses special challenges. Risers connecting a drilling vessel to the blowout preventer on the seafloor have to be greatly lengthened, and they are exposed to strong ocean currents encountered in the central Gulf. Managing higher volumes of mud and drilling fluid in these long risers makes drillers' jobs more demanding. Connecting and maintaining blowout preventers thousands of feet beneath the surface can only be performed by remote-operating vehicles. A 2007 article in Drilling Contractor described how blowout preventer requirements got tougher as drilling went deeper, because of low temperatures and high pressures at the ocean bottom. The author discussed taking

advantage of advances in metallurgy to use higher-strength materials in the blowout preventers' ram connecting rods or ram-shafts. More generally, he suggested "some fundamental paradigm shifts" were needed across a broad range of blowout-preventer technologies to deal with deepwater conditions.118

Under such conditions, methane hydrates raised a host of serious problems. Methane gas locked in ice ("fire ice") forms at low temperature and high pressure, and can often be found in sea-floor sediments. Temperature and pressure changes caused by drilling, or even by natural conditions, can activate the release of 160 cubic feet of gas from one cubic foot of methane, collapsing surrounding sediment, and thus destabilizing the drilling foundation. Hydrates can also present well-control problems. As hydrocarbons are produced and transported in cold temperatures and high pressures, hydrates can form and block the flow through deep pipelines and other conduits. Government, academic, and industry research programs on hydrates and associated flow problems begun in the 1990s are continuing.119

More broadly, knowledge about localized geology, types of hydrocarbons, and pressure profiles in ultra-deepwater wells is still not thoroughly developed. Geological conditions are complicated and vary from prospect to prospect, and from well to well. Each well, indeed, has its own "personality" that requires maintaining an extremely delicate balance between the counteracting pressures of the subsurface formation and drilling operation. Beneath the salt, pressures in the pores of the sediment are exceedingly hard to predict. Reservoirs in the Lower Tertiary are thicker and with higher viscosity than the fluids found in younger rock. Finally, ultra-deepwater developments are far removed from shore and thus from established infrastructure. As a BP technical paper prepared for the May 2010 Offshore Technology Conference noted, "the trend of deepwater discoveries in the [Gulf of Mexico] is shifting toward one with greater challenges across many disciplines represented by the conditions of Lower Tertiary discoveries."120

Nevertheless, the challenges seemed manageable and the rewards appeared worth the perceived risk. The offshore industry had enjoyed a long run in the Gulf without an environmental catastrophe. The hurricanes of mid-decade had caused widespread damage, but not a major offshore spill. In recent years, the industry had touted its relatively clean record in the Gulf as a justification to allow exploration elsewhere. As oil prices climbed from 2003 to 2008, peaking at over $140 per barrel, so did the industry's interest in exploring other frontier areas, especially offshore Alaska. In 2007, Shell and Total bid aggressively for federal leases offered in the Beaufort Sea, and in 2008, Shell spent $2.1 billion for leases in the Chukchi Sea. The following year, however, a lawsuit in a federal appeals court challenging the Minerals Management Service's environmental studies preceding the sale held up applications for permits to drill on these leases.121

Still, from 2008 through early 2010, both government and industry were largely bullish about the potential of offshore drilling for the nation's future. Not incidentally, both were earning even greater revenues from ever-more ambitious exploration. In 2008, President George W. Bush and Congress ended the leasing moratoriums on vast stretches of the U.S. outer continental shelf, and Bush proposed opening new areas for exploration. In a March

¶31, 2010 announcement, President Barack Obama scaled back Bush's plan, but he left open the possibility of expanding offshore leasing beyond the Gulf of Mexico and Alaska. The President defended his position by observing, "oil rigs today generally don't cause spills."122

¶As President Obama spoke, Transocean's Deepwater Horizon—fresh from completing BP's spectacular find at Tiber a few months earlier—was busy drilling on BP's Mississippi Canyon 252 lease, in approximately 5,000 feet of water. BP had named the prospect Macondo, after the fictional town in Gabriel Garcia Marquez's novel, One Hundred Years of Solitude. The fate of the town of the Macondo, as described in a memorable passage by Marquez, presaged the fate of the Macondo well and summed up the challenges facing the industry as a whole as it plumbed the depths of the Gulf:

It was as if God had decided to put to the test every capacity for surprise and was keeping the inhabitants of Macondo in a permanent alternation between excitement and disappointment, doubt and revelation, to such an extreme that no one knew for certain where the limits of reality lay.123

¶Chapter Three "It was like pulling teeth." Oversight—and Oversights—in Regulating Deepwater Energy Exploration and Production in the Gulf of Mexico The Deepwater Horizon rig sank on April 22, 2010, two days after the Macondo well blowout and explosion that killed 11 workers. Not long after the tragedy, its repercussions shifted to the Minerals Management Service (MMS), the federal agency responsible for overseeing the well's drilling and operation. Nineteen days after the rig sank, Secretary of the Interior Ken Salazar announced his intention to strip MMS's safety and environmental enforcement responsibilities away from its leasing, revenue collection, and permitting functions, and to place the former within a "separate and independent" entity.1 A week later, he announced MMS would be reorganized into three separate entities with distinct missions: a Bureau of Ocean Energy Management; a Bureau of Safety and Environmental Enforcement; and an Office of Natural Resources Revenue.2 And, by June 19, the Secretary had discarded the "MMS" name altogether.3 Like the Deepwater Horizon, MMS had ceased to exist.

¶The rig's demise signals the conflicted evolution— and severe shortcomings—of federal regulation of offshore oil drilling in the United States, and particularly of MMS oversight of deepwater

¶The often competing goals of energy independence and environmental protection collide at the Department of the Interior, which historically has held broad regulatory authority in both realms. For nearly three decades a single departmental agency, the Minerals Management Service, was at the center of the offshore-oil saga.

¶Mark Wilson/Getty Images

drilling in the Gulf of Mexico. The regulatory context for the leasing procedures and safety and environmental oversight that led up to the Macondo blowout took shape in the 1970s, when two conflicting priorities dominated the political landscape. The first to appear, in the early 1970s, was the public mandate for environmental protection, which prompted enactment of an extraordinary series of sweeping regulatory laws intended, in the language of the National Environmental Policy Act, to "create and maintain conditions under which man and nature can exist in productive harmony."4 The second was the nation's drive for energy independence; it led to new policies designed to increase domestic production and decrease American reliance on foreign energy supplies. Oil served as a catalyst for both: the Santa Barbara oil spill in 1969 helped to promote passage of demanding environmental protection mandates, and the OPEC oil embargo of 1973 amplified the urgency of efforts to make the nation more energy self-sufficient.

The federal regulation of offshore drilling awkwardly combined the two priorities, as a series of Congresses, Presidents, and Secretaries of the Interior—responding to competing constituencies in explicitly political ways—sought to reconcile the sometimes conflicting goals of environmental protection, energy independence, and revenue generation. In some offshore regions, oil drilling was essentially banned in response to environmental concerns. Elsewhere, most notably in the Gulf, some environmental protections and safety oversight were formally relaxed or informally diminished so as to render them ineffective, promoting a dramatic expansion of offshore oil and gas production and billions of dollars in federal revenues.

The origins of MMS vividly illustrate that political compromise. Secretary of the Interior James Watt created the agency with great fanfare in January 1982, aiming from the outset to promote domestic energy supplies by dramatically expanding drilling on the outer continental shelf. He combined, in one entity, authority for regulatory oversight with responsibility for collecting for the U.S. Treasury the billions of dollars of revenues obtained from lease sales and royalty payments from producing wells.5 From birth, MMS had a built-in incentive to promote offshore drilling in sharp tension with its mandate to ensure safe drilling and environmental protection.

Revenue generation—enjoyed both by industry and government—became the dominant objective. But there was a hidden price to be paid for those increased revenues. Any revenue increases dependent on moving drilling further offshore and into much deeper waters came with a corresponding increase in the safety and environmental risks of such drilling. Those increased risks, however, were not matched by greater, more sophisticated regulatory oversight. Industry regularly and intensely resisted such oversight, and neither Congress nor any of a series of presidential administrations mustered the political support necessary to overcome that opposition. Nor, despite their assurances to the contrary, did the oil and gas industry take the initiative to match its massive investments in oil and gas development and production with comparable investments in drilling safety and oil-spill containment technology and contingency response planning in case of an accident.

On April 20, the inherent risks of decades of inadequate regulation, insufficient investment, and incomplete planning were realized in tragic fashion. MMS no doubt can fairly boast

¶of many hardworking individual public servants who have in good faith sought to achieve their agency's important safety mission over sustained industry opposition. But, notwithstanding their individual efforts and accomplishments, the overall picture of MMS that has emerged since April 20 is distressing. MMS became an agency systematically lacking the resources, technical training, or experience in petroleum engineering that is absolutely critical to ensuring that offshore drilling is being conducted in a safe and responsible manner. For a regulatory agency to fall so short of its essential safety mission is inexcusable.

¶This chapter is divided into three parts. The first part describes the emergence of MMS as the dominant federal regulatory agency responsible for overseeing the offshore oil and gas industry. The second part examines the performance of MMS over time, with particular focus on its efforts to promote drilling safety and the institutional, political, and cultural impediments to its success. Finally, the third part explores in more detail the application of environmental protection requirements to offshore drilling, highlighting the particular ways in which the requirements were effectively diminished or ignored.

¶Creation of a Cross-Purposes Regulator

¶The federal government's authority to regulate oil and gas leasing activities on the outer continental shelf is not merely an expression of the government's traditional authority to regulate private activities affecting public health, safety, and welfare. Its authority is even more sweeping in nature and further arises out of the nation's ownership of the natural resources on the outer continental shelf and the federal government's corresponding power and responsibility to manage and protect those invaluable resources on behalf of current and future generations of Americans. As described by the Constitution's Property Clause, it is the "power to dispose and make all needful rules and regulations respecting the territory or other property belonging to the United States."6 The federal government, accordingly, has plenary authority, essentially "without limitations,"7 "to prescribe the conditions upon which others may obtain rights in" natural resources located on properties that belong to the nation as a whole.8 Because, moreover, of the national security implications of those resources, especially energy resources, that national power further implicates the President's broad authority as Commander-in-Chief to ensure the maintenance of sufficient energy supplies to keep the nation secure.9

¶Rights and Riches: The Early Skirmishes over the Outer Continental Shelf The foundations of federal regulation of offshore oil and gas development were laid in the Outer Continental Shelf Lands Act of 1953.10 That initial legislation gave the Department of the Interior diverse and potentially contradictory responsibilities for offshore mineral development. The vigorous debates preceding enactment of the new law and its early implementation gave the impression that it was all about the money.11

¶The potential windfall from leasing public land offshore to private companies for mineral development provoked an intense dispute between coastal states and the federal

government. In 1945, President Harry Truman had proclaimed federal authority over the subsoil of the U.S. continental shelf. California, Texas, and Louisiana defied this proclamation and continued to lease offshore land, prompting suits by the U.S. Department of Justice. The Supreme Court ruled against California in 1947 and against Louisiana and Texas in 1950, declaring that the federal government possessed "paramount rights" that transcended the states' rights of ownership.12 Offshore leasing and exploration stalled for three years, as Congress and the 1952 presidential candidates postured around proposals to return submerged coastal lands to the states.13 That conflict was largely resolved in the Submerged Lands Act, passed in 1953, two months before the Outer Continental Shelf Lands Act: states would control three nautical miles out from the shoreline (9 nautical miles for Texas and western Florida due to historic claims).14 The "outer continental shelf "—seaward of state lands—was claimed by the federal government. Estimates of the value of federal land offshore ranged from $40 billion to $250 billion.15

President Truman had called on the nation to postpone mineral development in the federal offshore area, foregoing the revenues immediately available. He argued that setting the federal offshore area aside, in the Naval Petroleum Reserve, would ensure that the oil and gas would be there later when needed for strategic purposes.16 But the congressional debates in 1953, under President Dwight Eisenhower, focused on what to do with this attractive new source of revenue. Various senators proposed dedicating the funds to deficit reduction or to education. But in the end, the new money from lease sales, rents, and royalties would flow into the general treasury.17

The first leases. During the first week of September 1954, Secretary of the Interior Douglas McKay announced the first federal lease sale: rights to explore 748,000 acres off the coast of Louisiana.18 When the sealed bids were opened on October 13, half the available acreage was leased with winning bids totaling $130 million. The next month, a similar sale off the Texas coast yielded $23 million.19 The promise of a new stream of federal revenue had come to pass.

The Rise of Environmental Law At the outset, environmental restrictions on offshore drilling were very limited. The 1953 legislation governing offshore mineral development authorized the Interior Department to prescribe rules "for the prevention of waste and conservation of natural resources" of the outer continental shelf,20 but "conservation" at that time mostly referred to the desire not to waste the resource physically by destroying the oil and gas reservoir. The Department did announce, however, that the Fish and Wildlife Service would have to approve all offshore drilling in wildlife refuges and that oil and gas leasing there that endangered "rare" wildlife species (like whooping cranes or trumpeter swans) would not be allowed.21

Federal offshore leasing policy remained largely unchanged until a Union Oil Company well located in the Santa Barbara Channel blew out on January 28, 1969 (described in Chapter 2). The Interior Department toughened its rules in response to the spill (after first issuing a moratorium on offshore drilling and production in California waters pending those new rules), the first changes since 1953.22 And, at that time Congress was already taking up legislation in response to heightened awareness of a host of environmental

¶problems, now punctuated by the Santa Barbara spill. Starting with the National Environmental Policy Act (NEPA), signed into law on January 1, 1970,23 Congress enacted sweeping new environmental protection and resource conservation laws that dramatically changed the federal role in overseeing activities that polluted the air or water or that exploited the nation's natural resources on public lands—including offshore oil and gas development.24

¶Given its bold promises of preserving the environment for future generations, NEPA is often referred to as the Magna Carta of the nation's environmental laws. It requires federal agencies to prepare "environmental impact statements" for all proposed "major Federal actions significantly affecting the quality of the human environment" in order to ensure that decisions are based on full consideration of their environmental consequences.25 Although it is far from clear that either Congress or the President appreciated NEPA's full import, federal courts quickly embraced the law, applying its procedural requirements strictly and enjoining agency actions found to be in violation.26

¶In order to provide the science needed for the environmental reviews and consultations directed by these statutes, the Department of the Interior created the "Environmental Studies Program" in 1973.27 The program was established to provide information on the geological, physical, biological, and chemical characteristics of offshore oil and gas leasing areas. It was initially focused on scientifically characterizing areas and providing baseline environmental data, but later shifted its focus to research directly linked to resource management decisions by the offshore leasing program.28

¶NEPA was just the first among approximately 20 new laws enacted during the 1970s that aimed to advance environmental protection by curbing pollution of the nation's waters, air, or land; manage commercial activities that sought to exploit the nation's natural resources, including mining and forestry; manage the coastal zone prudently; control noise; regulate toxic substances; and protect endangered species—among other goals.29 Amid this rapid, extensive transformation of the nation's environmental protection and natural resource management laws, one had particular significance for federal oversight of offshore drilling: the Outer Continental Shelf Lands Act Amendments of 1978. It was the last major natural resource law that Congress passed during the 1970s—and so embodies the shifting nature of national politics from the decade's beginning to its end.

¶Energy Independence vs. Environmental Protection: Conflicting Aims in High Relief Although Americans' embrace of environmental protection persisted throughout the decade, the 1973 oil embargo prompted ambitious efforts to promote the nation's energy independence. President Richard Nixon proposed a dramatic expansion of offshore oil and gas development, including in frontier areas around most of the nation's coast. President Jimmy Carter created the Department of Energy in 1977 and secured passage of the National Energy Act of 1978, consisting of five separate laws, some designed to promote development of domestic energy supplies and others to encourage energy conservation.30

The Outer Continental Shelf Lands Act Amendments, also enacted that year, not surprisingly reflected the tension between the nation's environmental and energy independence goals. Those skeptical of accelerated offshore leasing—including many coastal states, local governments, fishermen, and environmentalists—sought, to that end, opportunities to ensure that offshore oil and gas leasing complied with strict safeguards and a greater voice in the decisionmaking process. They were concerned about the broad discretion the Act conferred on the Secretary of the Interior over control and management of offshore energy resources.

By contrast, advocates for expanded domestic production wanted to ensure that the new legislation did not allow environmental protection laws to stifle exploration, development, and production of significant offshore oil and gas reservoirs. They were aware that environmental organizations had used NEPA successfully to challenge a proposed lease sale, covering almost 380,000 acres offshore Louisiana and Mississippi, on the grounds that the Interior Department had failed to first prepare an adequate environmental impact statement. The federal courts had agreed and enjoined the sale in January 1972.31 Coastal states and environmentalists had since launched challenges against other lease sales.

Congress began to hold hearings on revamping the federal offshore leasing program in 1974—just after the oil embargo and not long after those early environmental challenges.32 The law that emerged in 197833 included findings on the need to reduce the nation's dependence on "imports of oil from foreign nations," the potential to increase production of oil and gas on the outer continental shelf significantly "without undue harm or damage to the environment," and the need to review "environmental and safety regulations relating to activities on the Outer Continental Shelf . . . in light of current technology and information."34 The Act's purposes included "expedited exploration and development of the Outer Continental Shelf " and the "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."35

The 1978 Act fundamentally transformed federal offshore leasing. The law added detailed procedures governing the leasing of rights to explore, develop, and produce the resources of the outer continental shelf. The offshore program was divided into four distinct stages: • Development by the Secretary of the Interior of a "schedule of proposed lease sales indicating, as precisely as possible, the size, timing, and location of leasing activity which he determines will best meet national energy needs for the five-year period following its approval or reapproval";36 • Lease sales by the Secretary pursuant to that five-year schedule; • Submission by lessees of exploration plans for the Secretary's approval; and • Upon discovery of oil and gas in commercial quantities, submission of development and production plans by lessees for the Secretary's approval.

The Act further requires lessees to apply for the Secretary of the Interior's permission prior to drilling any wells, pursuant to an approved exploration plan37 or, in most areas, pursuant to a development and production plan.38

¶FIGURE 3.1: Outer Continental Shelf Oil and Gas Leasing, Exploration & Development Process

PRE-LEASE • Stage I: Develop 5-Year Program

SOLICIT COMMENTS DRAFT PROPOSED PROGRAM PUBLISHED PROPOSED PROGRAM DRAFT PROPOSED FINAL DRAFT 5-YEAR PROGRAM ANNOUNCED

¶• Stage II: Planning for Specific Sale

CALL FOR INFORMATION PUBLISHED DEFINE SALE AREA NOTICE OF SALE

¶SALE

LEASES ISSUED

POST-LEASE • Stage III: Exploration Plan Approval

EXPLORATION PLAN SUBMITTED APPLICATION FOR PERMIT TO DRILL APPROVED | PERMITS GRANTED EXPLORATION DRILLING STARTS FIRST EXPLORATION WELL COMPLETED DELINEATION DRILLING

Stage IV: Development & Production Plan Approval