Improving drilling safety in deep water

Henry Terrell, News Editor

The big move into the deepwater Gulf of Mexico was spurred by record high prices for petroleum and the hope of ensuring reliable domestic sources. Drilling continued in the deep Gulf, sustained by momentum, even as prices moderated and fell. The Macondo disaster changed the rules (Fig. 1), but not the stakes.

Fig. 1. The Development Driller III (foreground) prepares to drill a relief well near the site of the Macondo well blowout in May 2010, as the intervention vessel Q4000 holds position directly over the damaged BOP. The drillship Discover Enterprise (far) continues to capture oil from the ruptured riser. Courtesy of the US Coast Guard.

HISTORY, DISASTERS AND REGULATION

From the mid-1980s to 2003, oil mostly remained under $25/bbl, measured in constant dollars. At the beginning of 2008, as the economies of the world steamed along at a high and sustained rate of growth, the price of crude oil passed $100/bbl. Even as the first signs of the coming global financial crisis were appearing, the US stock market topped a six-year run, and then held its ground. Crude oil prices peaked in July 2008 at $147/bbl, as markets reacted to geopolitical tensions over Iranian missile tests.

The rapid rise in prices and new potential for profit caused oil industry heads to turn toward the deep water and the unexplored Lower Tertiary play. The worldwide economic crisis sent oil prices tumbling again, but industry’s long lead times for projects, plus growing belief that markets would be there, has kept interest in the deepwater prospects alive.

Early development and regulation. Offshore drilling took its first tentative steps in the late 1800s before offshore regulation of any kind existed, but almost all oil drilling was onshore until the 1940s. The first offshore well drilled out of sight of land was spudded in 1947, and by the end of 1949 dozens of exploration wells had been drilled and 11 fields discovered. The rapidly increasing demand brought on by World War II and the postwar boom created more and more interest in offshore and near-shore production, and with that came legal disputes about ownership of subsea fields. Specifically, did the states control the shelf areas off their coasts, and if so, how far offshore did that control extend? The first regulations of offshore petroleum concerned control of the resources, not drilling safety.

Congress passed the US Submerged Lands Act in 1953. This law established the federal government’s title and ownership of submerged lands of the Outer Continental Shelf (OCS) from three miles out from the coast. Exceptions were made for Texas and Florida, which were given jurisdiction over the first 10.3 miles of their coastal waters. This was followed shortly by the Outer Continental Shelf Lands Act (OCSLA), which specifically authorized the Secretary of the Interior to lease offshore fields for development, and gave the Department of the Interior the right to create any regulations deemed necessary. The OCSLA has been amended several times since then, but remains the basis of all offshore regulation. In 1983 President Reagan declared the US Exclusive Economic Zone (EEZ), which claimed the rights to submerged land out to 230 miles (200 nautical miles) from the coastline, all administered by the Interior Department under the OCSLA.

After Santa Barbara. The oil spill that is sometimes credited with starting the modern environmental movement occurred in January 1969. Located just 6 miles from the site of the very first offshore oil well in 1896, the blowout at Dos Cuadras Field offshore Santa Barbara (Fig. 2) dumped some 80,000–100,000 bbl of crude into coastal waters. Although not as large as some later well blowouts, and contained fairly quickly, the spill affected some of the most popular public beaches in California. Cameras rolled, and oil-soaked wildlife appeared on news programs across the country. The well had been drilled beyond the 3-mile coastal limit, so federal regulations, which were less stringent than California’s, applied. People and politicians who had never been directly affected by oil pollution got involved. Even President Richard M. Nixon, taking a helicopter tour of the disaster, observed that “the Santa Barbara incident has frankly touched the conscience of the American people.” An executive order resulted in a temporary moratorium on all offshore drilling, but it was lifted one week later and drilling activities resumed.

Fig. 2. Oil gushes to the surface and spreads following the blowout at Union Oil’s Platform A in the Santa Barbara Channel in January 1969. The event brought about the first comprehensive federal safety rules in offshore drilling.

In the following years, a flurry of environmental laws were passed. In 1969, Congress passed the National Environmental Policy Act (NEPA), which required environmental impact studies before any drilling or development could be conducted on federal lands. States, particularly California, adopted similar legislation, such as the California Environmental Quality Act (CEQA) and the creation of the California Coastal Commission. Nationally, this was followed by the Clean Air Act, the Clean Water Act, and laws to protect sensitive coastal areas and endangered species.

No new leases have been granted in California coastal waters since 1969. In the California OCS, no leases have been granted since 1981, when Congress imposed a moratorium on all offshore leasing except for parts of Alaska and the western and central Gulf of Mexico.

After Piper Alpha and the Exxon Valdez. The North Sea production platform Piper Alpha caught fire and exploded in July 1988, with the consequent loss of 167 personnel and rescue workers, Fig. 3. Inquiries that followed assigned blame for the accident to a combination of equipment failure, poor maintenance and safety procedures, and human error. Phase 2 of the inquiry, concluded in 1990, made 106 recommendations for changes to North Sea safety procedures. They included firewalls able to withstand explosion, more safety training, better inspection, better access to shutoff valves, increased number of escape routes, and other regulations concerning smoke abatement and firefighting. All of these were accepted by the industry. One of the most important of these recommendations was that the responsibility for enforcing safety in the UK North Sea be moved from the Department of Energy to the Health and Safety Executive, because having safety and production overseen by the same agency was regarded as a conflict of interest.

Fig. 3. The Piper Alpha explosion and fire in the UK North Sea in July 1988 was the worst offshore disaster in terms of loss of life. Strict new safety guidelines were proposed and accepted, but North Sea production was not interrupted.

No criminal charges were ever brought. In marked contrast to the Deepwater Horizon disaster, oil and gas activities in the North Sea continued unabated during the investigations.

Then, in March 1989, the oil tanker Exxon Valdez ran aground in Prince William Sound, Alaska, spilling at least 260,000 bbl of crude, Fig. 4. Although the accident had no direct bearing on drilling or production of offshore petroleum, one significant result was the Oil Pollution Act of 1990. This act, according to the Environmental Protection Agency (EPA) website, established provisions that expand the federal government’s ability, and provide the money and resources necessary, to respond to oil spills.” Included in the law was this provision: “the total of the liability of a responsible party under section 2702 of this title and any removal costs incurred by, or on behalf of, the responsible party, with respect to each incident shall not exceed … for an offshore facility except a deepwater port, the total of all removal costs plus $75,000,000 [emphasis added].

Fig. 4. The Exxon Valdez oil spill in Prince William Sound, Alaska, in March 1989 resulted in the Oil Pollution Act, upon which subsequent US offshore regulation was based.

Macondo. Prior to the Deepwater Horizon disaster, the use of “categorical exclusions” waiving NEPA requirements for environmental impact studies was common in the deepwater Gulf. In 1986, the White House’s Council on Environmental Quality (CEQ) had rescinded a 1978 NEPA regulation that required agencies to conduct a “worst-case analysis” in their Environmental Impact Assessments (EIAs). In some circumstances, it was determined that if a proposed action, based on past experience, did not normally have significant impact on the environment, an agency could categorically exclude that action from further environmental review.

In October 2007, the Minerals Management Service (MMS) completed a NEPA analysis for Gulf of Mexico Lease Sale 206, which included Mississippi Canyon Block 252 and the Macondo exploration well. BP submitted an exploration plan for the proposed well, and MMS approved the plan following two categorical exclusion reviews in April 2009. The agency then approved BP’s drilling permit application, also under a categorical exclusion. Based on the documented historical record, a blowout and spill of the magnitude of the Deepwater Horizon disaster was not addressed in the NEPA analysis. It was the first failure in the Macondo well—one of imagination.

In September 2009, the Tiber exploration well in Keathley Canyon Block 102 was drilled to a record depth of 35,000 ft. That project had also received categorical exclusions, and all had gone smoothly and proceeded in good time. It was also the last well completed by the Deepwater Horizon before the giant semisubmersible moved on to Mississippi Canyon.

NEW RULES

The oil was still flowing uncontrolled in May 2010 when the Obama administration appointed a commission to study the accident. The National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling was created to:

• Examine facts and circumstances to determine the cause of the disaster
• Develop options to guard against future occurrences
• Submit a final report within six months of its first meeting.

In a 48-page excerpt of its final report, the commission concludes that decisions that were intended to save time and money created an unreasonable amount of risk. The report also said that BP, Halliburton and Transocean each made decisions that increased the risk of a blowout. Ultimately, the disaster came down to an overriding systemic failure of management. When decisions were made, no one was considering the risks being taken. One example cited was a request by BP to set an “unusually deep cement plug,” which was approved by the Minerals Management Service in only 90 minutes. “The blowout was not the product of a series of aberrational decisions made by a rogue industry or government officials that could not have been anticipated or expected to occur again. Rather, the root causes are systemic, and absent significant reform in both industry practices and government policies, might well recur,” the commission concluded.

In July, offshore drilling in the Gulf was temporarily suspended, and in August, the MMS, now reorganized as the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE), issued a directive that effectively eliminated the use of categorical exclusions for any application for a permit to drill (APD) involving a BOP. BOEMRE’s new “interim final” rules on drilling were introduced at the end of September, and took effect immediately. Interior Secretary Ken Salazar had promised that the new regulations would “raise the bar” on safety standards in deepwater drilling, reducing the possibility of another catastrophic blowout and making drilling safer for offshore workers.

The Drilling Safety Rule includes:

• A requirement that the casing and cementing program be appropriate for the well under the expected wellbore pressure, as certified by an engineer
• A requirement for two independent test barriers across each flow path during well completion, also to be certified by an engineer
• The ensuring of proper installation, sealing and locking of the casing or liner
• A requirement of approval from the BOEMRE district manager before replacing a heavier drilling fluid with a lighter fluid (this provision refers directly to a major factor in the Macondo blowout)
• A requirement of enhanced deepwater well control training for rig personnel
• A provision making API Recommended Practice 65–Part 2 mandatory.

This last item, “Isolating potential flow zones during well construction,” contains best practices for zonal isolation in wells to preserve the integrity of pressure-containment barriers that are installed during well construction. The standards are intended to control flows just prior to, during and after primary cementing operations to set casing and liners in wells, and to help prevent sustained casing pressure.

Rules specific to the BOP and activation equipment are:

• The operator must submit documentation and schematics for all control systems.
• Blind-shear rams should be capable of cutting any drill pipe in the hole under maximum anticipated surface pressure. This must be verified by a third party.
• The subsea BOP stack must have ROV intervention capability. At a minimum, the ROV must be capable of closing one set of pipe rams, closing one set of blind-shear rams, and unlatching the lower marine riser package. (ROV intervention on the Macondo well BOP was unsuccessful, Fig. 5).

Fig. 5. ROV operators try to manually engage the shear ram on the BOP stack of the Macondo well after automatic systems failed. The attempt was unsuccessful. Courtesy of the US Coast Guard.

• An ROV and a trained ROV crew must be maintained on each floating drilling rig. Minimum standards must be established for crew who are authorized to operate BOP equipment.
• Dynamically positioned rigs must have an auto-shear system and deadman system (a backup BOP control system that automatically closes the blind shear ram in case there is total loss of both hydraulic and electric communication between the pods and the surface). These must be tested on the seafloor.
• Testing of ROV intervention on the BOP stack during stump test and testing of at least one set of rams in the initial seafloor test are required.
• Subsequent pressure testing is required if any shear rams are used in an emergency.

At the same time, BOEMRE issued its Workplace Safety Rule, compelling all operators with oil and gas operations in federal waters to follow API Recommended Practice 75. This requires operators to develop and maintain a Safety and Environmental Management System (SEMS), a comprehensive management program for identifying, addressing and managing operational safety hazards. It is intended to address the human element in workplace safety. (It was pointed out by one speaker at the DeepGulf 2010 conference in Galveston, Texas, that of the eight barriers to disaster in the Macondo well, three of them failed due to human error—misinterpretation of integrity testing, failure to properly monitor the well and failure to respond correctly in the immediate aftermath of the accident.)

The SEMS has to include site-specific hazards analysis, management of change (personnel, contractors, shift changes), procedures evaluation, work practices, training, maintenance, pre-startup review of all systems, emergency response, investigation of incidents and good documentation. It also increases the frequency of audits—to an initial audit within two years of implementation of the SEMS and at least one every three years thereafter.

NEW GUIDANCE

Responding to criticism that a lack of clarity in the new rules was delaying projects, in early December BOEMRE issued new details about the deepwater drilling rules. The new document contained no new rules, but did provide more information about how companies can comply with previously established mandates.

For example, the document seeks to clarify how companies can satisfy the requirement of proving that they can quickly respond to subsea blowouts. Operators must provide detailed “containment plans” explaining how they would deal with the resulting debris while trying to contain the well. The companies also must describe what subsea containment equipment, ROVs and support vessels they would be able to use in case of a disaster. However, drilling operations that were allowed to proceed under the moratorium will not require additional information on subsea containment.

Although BOEMRE plans to conduct environmental reviews before approving new deepwater projects that were suspended by the moratorium, the agency will exempt sidetrack wells from these reviews. New wells drilled near existing ones in the same formations are considered to be covered by the main review.

Also, the guidance document attempts to clarify how companies are to calculate the “worst-case discharge” from offshore wells and how they should determine their capability of responding to a spill. It suggests that operators meet face to face with BOEMRE staff to discuss those calculations. Operators seeking permits to drill in shallow water have had such meetings with federal regulators for years.

WHAT IS AT STAKE?

The US oil and gas industry has had an uneasy relationship with both the government and the public, something that is not as true in other countries such as the UK and Norway. This public ambivalence did not begin with the Deepwater Horizon disaster, but that event has turned up the volume on discourse and created uncertainty.

The deepwater OCS and the Gulf of Mexico in particular are essential to the future energy security of the US, Fig. 6. In projections made before the Macondo blowout, the Energy Information Agency (EIA) estimated that deepwater oil production, which passed 1 million bopd just 10 years ago, was expected to peak at 1.65 million bopd in 2013 and continue at that level, essentially flat, through 2035. This depended on several assumptions that have now been thrown into doubt. Since fields decline, production could be sustained only through continuous development of new fields. After actually rising in 2010, Gulf oil production is projected to show a decline in 2011 to 2009 levels.

Fig. 6. Federal offshore oil production in the Gulf of Mexico.

As Geoffrey Brand of the American Petroleum Institute (API) said recently, “Whether or not we continue up to 1.65 million bopd is highly dependent on what proposals are accepted in the future.” He said that there will have to be some $15 billion per year in capital investment, which will contribute half a trillion dollars to the US economy over 20 years, Fig. 7. It also means more than 175,000 jobs, 93,000 directly related to the oil and gas industry and the rest in supporting industries like manufacturing and steel.

Fig. 7. Total federal offshore revenues collected by MMS/BOEMRE, by fiscal year.

“The deep water will provide one-fourth of the domestic oil production in the US. If further development does not occur, we will end up importing another 20% over and above what we would have imported anyway,” Brand said. “This is just true of crude oil—natural gas will not be affected as much, because there are many onshore options.”

Jack Belcher, managing director of the National Ocean Policy Coalition, believes that national policy is definitely headed in the wrong direction: “The idea has existed that the Department of the Interior has had a cozy relationship with industry, and we need to clean house. We’re in a situation now where there is paralysis and fear in an agency [BOEMRE] with personnel really afraid to act.”

He said that the current government administration is following a philosophy of “Don’t let a good crisis go to waste.” (Belcher was paraphrasing an oft-quoted comment made in late 2008 by Rahm Emanuel, who was referring to the banking credit crisis at a Wall Street Journal conference of top CEOs, after accepting the chief-of-staff position in the Obama administration.) Belcher added that although the moratorium is officially lifted, there is a de facto moratorium in place due to the fact that no deepwater permits have been issued, with even bigger delays possible in future lease sales.

FUTURE COSTS

BOEMRE estimates that the new drilling regulations will add an average of $1.42 million to the cost of a well. In a $6 billion project with a couple of dozen wells, the incremental cost would be trivial. However, if the new permitting process adds many days to the project—at half a million dollars per day for rig rental—that amount could be reached and greatly exceeded in only a few days. If the delays add up, so that a project’s expected completion date is pushed back months or even a year, it would have a heavy impact on revenues, and some projects may no longer be economic. To avoid this, it is crucial that the permitting process cease to be uncertain and become routine.

Liability must also be clarified. The $75 million cap is essentially meaningless, since cleanup costs can run into the billions of dollars. If the cap is increased significantly, the question is what will companies have to show to be able to cover their liability? Traditional insurance is just not available for a $10 billion or $20 billion insurance policy; other forms of national or industry insurance must be considered. The option of self-insurance would be available to only the largest companies, and if liability is unlimited, only the largest companies will be able to work in the Gulf of Mexico.

Cooperation between industry and government is in the interest of both. Everyone agrees on the importance of improving safety. However this is achieved, through agency oversight or compliance with API recommended practices or through an industry-run safety council (modeled on the Institute of Nuclear Power Operations or the Chemical Safety Board), it should not be forgotten that uncertainty means added time, and time is money. Regulation that adds time but does not improve safety is bad for everyone.