In this special report, editors from E&P and Oil and Gas Investor examine the response of the oil and gas industry, the scientific community and the federal government to the Deepwater Horizon disaster.
The ecological, financial and emotional fall-out from the Macondo catastrophe was enormous. But learning and healing are well underway five years later. Regulatory agencies have been overhauled to better monitor industry activity. New technologies have come to the fore that make deepwater drilling safer. Consortia have been formed to develop spill response and containment strategies.
And studies are underway to measure the impact of the spill on the environment and suggest procedures going forward. Perhaps the most exciting news is the response of E&P companies who tolerated a drilling moratorium and a lengthy permitting process and are now exploring and developing this world-class province with a vengeance.
The last line of defense on the seabed below the Deepwater Horizon did not function properly.
Those failures led to the redesign of many of the pressure-control components of the BOP and changes in procedures and inspections.
On Oct. 14, 2010, the Bureau of Safety and Environmental Enforcement (BSEE) released its Interim Drilling Safety Rule. In a press release BSEE explained that the rule established new standards for casing and cementing, including integrity testing requirements; required independent, third-party verification of blind-shear ram capability and subsea BOP stack compatibility; added new requirements and functional testing for subsea secondary BOP intervention; and required documentation for BOP inspection and maintenance, certification of casing and cementing and specific well-control training, including deepwater operations.
That rule was followed Aug. 15, 2012, with the Final Drilling Safety Rule, which included all of the recommendations in the interim rule along with several refinements. These included the enhanced description and classification of well-control barriers; definition of testing requirements for cement; required negative pressure tests on wells that use a subsea BOP or a mudline suspension system; clarified requirements for the installation of dual mechanical barriers (cement and one mechanical barrier); and extended requirements for BOPs and well-control fluids to well completions, workovers and decommissioning operations.
The failure of the BOPs in the Macondo accident was a major focus of the investigation following the blowout. The drillpipe buckled in the BOP, preventing the blind shear rams from cutting the pipe and allowing oil to flow out of the wellbore.
Several joint industry task forces were formed after the accident, including ones that focused on the pressure-control equipment and well design. As a result of those studies, API Recommended Practice (RP) 53 was upgraded to API Standard 53 (S 53) “Blowout Prevention Equipment Systems for Drilling Wells.”
This standard requires all subsea BOP stacks to be Class 5 or greater and consist of at least one annular preventer, at least two pipe rams (excluding test rams) and at least two sets of shear rams (one set must be capable of sealing).
All emergency control functions must be tested when connected and during the drilling program. Automatic mode and deadman functions also must be tested subsea. All key functions must be able to be operated by ROVs and perform at normal function control times.
In May 2012 GE Oil & Gas introduced its next-generation blind shear ram designed for use in its 18¾-in. ram BOP. The blind shear ram can both shear and seal after cutting 6⅝-in. tool joints. This technology solution also is designed to eliminate nonshearable sections—one of the problems with earlier shear rams—and allow greater shearing flexibility.
The shearing capability was confirmed during testing. The rams were successfully tested to 15,000 psi after cutting the tool joint. Centralizing arms are designed to allow successful shearing of buckled or offset pipe, and modifications to the block and blade allow greater force to be applied without damage.
In May 2014, GE introduced its next-generation BOP program for 20,000-psi subsea formations. Current GE subsea BOPs are only rated for 15,000 psi. However, the physical demands of 20,000-psi drilling at depths of 3,811 m (12,500 ft) are so different from existing 15,000-psi systems that GE completely reengineered the new BOP stack’s components and also developed several new techniques and technologies with its project partners, according to a press release.
Currently, most subsurface drilling operations rely on mud returns to identify when a well is taking on a kick from oil, gas or water. By the time the drilling mud carrying the kick material has reached the rig floor, the ability of the drilling operator to mitigate potential impacts of the kick is limited. Many drilling operations use LWD, MWD or seismic-while-drilling (SWD) tools to help guide drilling operations. These data are not presently used to fully evaluate the intra-borehole environment to inform drilling operational decisions, which puts the drilling rig, operator, personnel and surrounding environment at risk if the kick cannot be constrained and brought under control quickly. Researchers at the U.S. Department of Energy’s National Energy Technology Laboratory (NETL) have devised an early detection system for identifying changes in the intra-borehole environment related to invasion of gas or oil from the formation at or near the drillbit to provide information on the wellbore environment in close to real time.
The invention leverages data obtained from LWD, MWD and SWD to detect kicks in the area of the drillbit. The information is processed in real time by novel algorithms and approaches. The use of this technology to rapidly identify kicks could improve safety, reduce operational costs and lessen the likelihood of a loss-of-control event during drilling operations.
Research is currently active on the technology under U.S. Provisional Patent Application No. 62/053,832 filed Sept. 23, 2014, and titled "Kick Detection at the Bit Using Wellbore Geophysics" by inventor Kelly K. Rose. This technology is available for licensing and/or further collaborative research from NETL.
The Macondo incident resulted in swift changes to how the offshore oil and gas industry is regulated, including changes to the regulator itself. Within a month of the accident, then-Secretary of the Interior Ken Salazar issued an order to eliminate the U.S. Minerals Management Service (MMS) and replace it with the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE), which was later replaced by the Bureau of Offshore Energy Management (BOEM), the Bureau of Safety and Environmental Enforcement (BSEE) and the Office of Natural Resources Revenue (ONRR).
“Separating the functions of MMS into different agencies is very important when you think about the various responsibilities that existed and the extent to which the previous MMS directors had spent a lot of time on revenue collection,” Fran Ulmer, who served on the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling and currently chairs the U.S. Arctic Research Commission, said. Separating the entities meant a cleaner focus and mission for each one of them. Now, BOEM and BSEE give their attention to analysis, planning and regulatory regime without the distractions of revenue collection, which ONRR handles.
Another significant change was the movement of safety and environmental management systems (SEMS) to a required practice. Previously, SEMS were only recommended practices for the industry. Macondo provided the impetus and political environment to change that.
“Our government tried to get that through for 20 years, and finally, finally it took a disaster to move it from a recommended practice to a required practice,” Jacqueline Weaver, a professor of law at the University of Houston, told Oil and Gas Investor.
Also known as the Workplace Safety Rule, the SEMS rule requires offshore operators to define certain roles and provide documentation related to safety. According to BSEE, the main objectives of a SEMS program are to focus attention on the influences and effects that human error and poor organization have on accidents, continuously improve the offshore industry’s safety and environmental records, encourage the use of performance-based operating practices and collaborate with industry in efforts that promote the public interests of offshore worker safety and environmental protection.
“It definitely changes the way in which risk is evaluated and managed,” Ulmer said. “It pushes more communication, planning and integration between the operators and the contractors, which is a really important thing.”
Currently, the federal government is reviewing new rules proposed by BSEE to improve the reliability of BOPs. Ulmer said she expects the rules to be unveiled by the spring.
But, according to Weaver, it is one thing to require a rule of safety. “It’s quite another for a company to internally ingest it, live it and breathe it,” she said.
She believes a culture of safety cannot be implemented by regulation alone but will take time to develop. “SEMS are to drive everyone on the platform and the board of directors and top management into always, always, always thinking about the safety aspects. And that will take a while.”
Ulmer is a little more upbeat when talking about how the regulatory environment has changed over the past five years. The recently released draft strategy for offshore leasing—which seals off portions of the Arctic Natural Wildlife Refuge from drilling—shows consideration for places with high ecological value. The proposal takes into account a 40-km (25-mile) corridor reflecting the migration pattern of Bowhead whales, which fuel a subsistence economy for some indigenous peoples. It also describes an area around Hanna Shoal in the Chukchi Sea that is a feeding area for walruses.
“Interior is saying there are some areas that are not only high-risk but [of] high ecological value and subsistence use areas, and the leasing program that Interior is going to do from now on, or at least for now, recognizes that there are some areas that should be off-limits,” Ulmer said. “And so I would offer both of those as examples of how the Interior Department is acting quite differently from how it would have 10 years ago.”
The immediate aftermath of an oil spill is never a pretty sight. The effects five years later are a little more difficult to spot. But as tragic as the Deepwater Horizon catastrophe was, it provided a huge laboratory for studying the impacts of this type of event.
BP was quick to realize this fact. Just a couple of weeks after the April 20, 2010, spill, it earmarked $500 million, to be spent over a period of 10 years, to study Gulf of Mexico (GoM) ecology, the effects of the spill and methods for cleanup and restoration, according to Dr. Rita Colwell, chairman of the GoM Research Initiative (GoMRI), the initiative receiving the funding.
“It’s an entirely independent organization to focus on basic research, the questions to be asked,” Colwell said.
GoMRI is headed up by a research board. Shortly after the spill, research priorities were established by BP and this board.
“The memorandum of understanding was that we would work on the physics and physical properties of oil and oil in seawater; the chemistry of oil degradation; the technology of handling oil and samples for environmental study; the ecology of the system in the deepwater but also the coastal areas; and, very importantly, the public health aspects of the oil spill on individuals, on communities and on the biological components of the environment,” she said.
At the February 2015 Gulf of Mexico Oil Spill & Ecosystem Science Conference, GoMRI researchers presented their findings. One paper focused on oil source fingerprinting in coastal marsh samples. Using gas chromatography, researchers compared source oil samples to environmental oil samples to try to match their chemical compositions. A large number of samples were collected in the near-shore environment, including after storm events. While presence of normal hydrocarbons and several families of aromatic hydrocarbons were below the detection limits, other compounds were detected that had obviously been chemically changed by weathering.
Another paper studied the impacts of river diversions on surface oil transport in estuaries.
Several areas along the Gulf Coast use diversions—manmade channels—for salinity control and to deliver nutrients to coastal wetlands, the researchers said. They investigated river diversions in Barataria and Breton Sound estuaries using a finite-volume coastal ocean model.
“The model was driven by tidal and subtidal forcing at the open [GoM] boundary, freshwater discharge from the diversions and surface wind stress,” they noted in the abstract for the presentation. “[There are] some important challenges in developing oil spill trajectory models in these systems.”
A third study focused on the impact of the spill on an Alabama salt marsh microbial community. Collecting salt marsh sediments from Point Aux Pines, Ala., beginning in June 2010, the researchers noted that a metagenomic study of the microbial communities revealed an overall decrease in species richness in areas where oil was present but a gradual recovery as time passed. “These results contribute to our understanding of temporal variability in microbial communities, allowing us to detect patterns of distribution and predict microbial responses to changing environments and human-induced events such as the 2010 [Deepwater Horizon] oil spill,” the researchers concluded in their abstract.
Another study on microbial communities found direct correlation between poorer microbial health and higher total organic carbon concentrations as well as higher n-alkane concentrations. Yet another examined the effects not only on the microbial communities but also on the rate of erosion. Using pre- and post-spill satellite imagery, researchers determined a threshold at which soil parameters change significantly with even small increases in oil concentration in the soil.
For Colwell, this type of research is an important step in responding to another oil spill due to the effects of the Macondo incident. “Fortunately we are seeing recovery,” she said. “It’s a bit slower than we had hoped but very typical of oil that has been cascaded into the environment.
“It’s very important to know after all of the studies are done the best lessons learned of where we should go, how we should act and what we should institute if there is a massive spill,” she said. “We would hope there isn’t, but we have to be realistic. Sometimes accidents happen, and how you go in to work very quickly to minimize the effect on the environment, to maximize the recovery of the oil, to enhance the degradation of whatever is persistent and to understand the public health effects is very important.”
When it comes to oil spills, prevention is the obvious key for the energy sector. But when operations go wrong, preparation and having proper procedures, people and equipment ready are critical.
The Deepwater Horizon tragedy ushered in a new era for oil spill response preparedness. In the five years since the gas release and explosion, industry players have stepped up response efforts, deploying new technology such as an expanded containment system, enhanced capping stacks and remote sensing surveillance.
Still, challenges remain, as operators move farther and deeper into the GoM and HP/HT environments, creating the need for equipment capable of handling emergencies in such conditions.
“Nobody ever wants to make that phone call to us because something has gone wrong,” said Judith Roos, vice president for marketing, customer services and corporate relations for Marine Spill Response Corp. (MSRC). “But it is so important to be prepared for response just like you take preventive measures at home to make sure you’re safe. When you do have to call your local fire department, it’s a great comfort to know that they have the right tools in their toolkit.”
MSRC was the largest surface response contractor for BP during Deepwater Horizon, providing 12 responder-class vessels, Roos said during an event in Houston. With conventional response capabilities that include open-ocean mechanical recovery, controlled burning and aerial dispersants, MSRC’s oil response toolkit includes responder-class oil spill response vessels (OSRVs), dual-purpose oil spill response barges and fast-advancing encounter systems in addition to skimming systems and containment booms. The 15 responder-class OSRVs now have dual-option recovery systems.
“We have the ability to use a Transrec skimmer in a J configuration with boom off the starboard side of the vessel,” she said. “We’ve also modified the vessel to be able to use Buster technology, which allows you to go through the water at a higher speed of advance [3 to 5 knots] thus encountering more oil. It’s very difficult to use this type of technology, though, in a highly debris-laden field.” So having both options available is a plus.
In the last three years MSRC has focused on remote sensing. Following Deepwater Horizon, the company conducted a study, and the key takeaway was that there were challenges with visual spotting of oil.
“It really helps. You’ve got somebody in the plane. They are looking not just with their eyes but also with a computer screen that helps them direct the assets to potential targets,” Roos said. “You can also track moving oil with it, another advantage because that is always part of the challenge.”
Advances also have been made below the surface. These include Marine Well Containment Co.’s (MWCC) expanded containment system.
“The new expanded system gives us capabilities to cap a well or cap and flow a well at deeper water depths,” MWCC CEO Don Armijo told E&P. “It also gives us the capability to handle, in the event of a cap-and-flow situation, much more fluid.”
“At the end of last year, we added to our arsenal what we call the subsea containment assembly—our newest capping stack—which is part of the expanded containment system,” Armijo added. “This particular stack allows us to cap or cap and flow a well at water depths up to 10,000 ft [3,050 m].”
This technology came after MWCC introduced in June 2013 a smaller capping stack suitable for platforms with much tighter well spacing such as tension-leg platforms. The 10,000-psi capping stack is MWCC’s smallest stack. Additionally, the company has a single ram capping stack, which is rated for 15,000 psi and capable of handling fluids up to 177 C (350 F).
“A key feature of our mission is to stay current or ahead of the game with respect to requirements as our members drill deeper in the U.S. Gulf of Mexico. As members find reservoirs that are higher pressure and higher temperature, we need to stay current with technology so we can support them with drilling permits,” Armijo said. “We’re working now on developing a 20,000-psi capping stack to handle higher pressure reservoirs.”
Work started this year for the 20,000-psi capping stack project, which has a two- to three-year development timeline.
“I’ve been in the business for 32 years. When I reflect back to Macondo and movement the industry has made with the creation of MWCC, the industry is better prepared to handle an event,” Armijo continued. “We’re more experienced now and as an industry have learned from Macando. We’re ready with the right people, processes and equipment necessary to respond and effectively handle another incident like Macondo.”
MWCC is equipped with a reservist team of about 100 people, employees of Wood Group PSN, who are deployed to operate the modular capture vessels, which capture and process well fluids during a cap-and-flow response. Each member undergoes extensive classroom training, drills and other on-the-job training on the modular capture vessels to ensure their readiness and effectiveness during response operations.
“It’s all about being prepared and having the proper training; this includes having the right people and processes and dedicated equipment, which is being maintained and tested to ensure operability when deployment is necessary,” he added.
The focus of the Center for Offshore Safety, formed following Deepwater Horizon like the MWCC, is on good response planning and identification of hazards as well as effectively managing change as the project unfolds, said Charlie Williams, executive director of the center.
One of the key areas that people have focused on is finding the oil spill and getting there quickly. "There has also been a lot of work on technology that is even more effective at cleanup,” he added. “But a lot of focus has been on this ability to find the oil spill and assess it in all kinds of weather and at night.”
Other advances since April 2010 have included bigger, more effective barges with greater boom deployment; skimmers that can remove a larger percentage of oil; and smaller, quicker response vessels, he added.
“I think there were many people that were well prepared before Horizon,” Williams said. “BSEE has required a lot of new things, including new ways of calculating how big a response you need.” The federal agency also has become more specific on what type of equipment must be deployed and the deployment plan itself.
Companies, at times working with BSEE and the U.S. Coast Guard, have taken part in response planning and drills in significant detail, he said, adding “I think the detail with which people understand the plan both in companies and in the government has improved.”
A key part of planning is ensuring that the workforce is correctly trained, Williams continued, “but even more than that is to ensure that they are ready to respond, respond effectively and respond in the right way. We’re really on a journey of continuous learning and improvement on how to identify hazard spill barriers and build better response and other kinds of plans.”
World-class reserve potential coupled with relatively low geopolitical risk and attractive fiscal terms continue to attract significant investment to the GoM, making the province rank high among other global E&P opportunities. The Macondo tragedy did not change that.
Today the biggest impediments to Gulf activity are low oil prices and the generous allocation of dollars to onshore shale plays that often yield higher rates of return much faster. The jackup rig count in the Gulf is at its lowest point since the 2008-09 financial crisis, and 70 newbuilds are on their way in 2015 on top of about 500 rigs currently in the fleet—with 50 more projected to be delivered in 2016.
In the end, these are the factors affecting the Gulf today more than the fallout from BP’s Deepwater Horizon accident five years ago.
To be sure, the offshore industry has had to adapt, meeting stricter regulations that have hiked drilling and completion costs. However, significant new production continues to come online from deepwater, where majors and the largest independents keep investment flowing year in and year out for multibillion-dollar, long-term projects. In 2012, deepwater E&P expenditures topped those in shallow water for the first time, a trend not expected to reverse.
|Freeport-McMoRan||McMoRan, Plains E&P||$9.4 B||1H2013||Acquired two offshore firms|
|Plains E&P||BP, Shell||$6.1 B||2H2012||Acquired BP interests in three deepwater fields|
|Fieldwood Energy LLC||Apache Corp.||$3.75 B||2H2013||Acquired 500 shelf blocks; Apache exits GoM entirely|
|Energy XXI||EPL Oil & Gas||$2.3 B||1H2013||Acquired EPL and added 65 Mboe/d|
|Freeport-McMoRan||Apache Corp.||$1.4 B||1H2014||Acquired interests in Lucius and Heidelberg fields|
|SandRidge Energy||Dynamic Offshore Resources||$1.275 B||1H2012||Acquired all of Dynamic’s Gulf assets|
|Energy XXI||ExxonMobil||$1.1 B||2H2010||Acquired interests in nine shelf fields|
|McMoRan Exploration||Plains E&P Co.||$991 MM||1H2011||Acquired interests in 197 shallow-water blocks, nine prospects and 22 leads|
|Fieldwood Energy LLC||SandRidge Energy||$750 MM||1H2014||SD exits GoM|
|Credit Suisse Group||ATP Oil & Gas||$690 MM||2H2013||Acquired assets out of bankruptcy court|
|Marubeni Corp.||BP||$650 MM||2H2010||Acquired various working interests in four fields|
|Talos Energy LLC||ERT GOM||$620 MM||1H 2013||Acquired E&P unit of Helix Energy Solutions Group|
|Plains E&P||Shell||$560 MM||2H2012||Acquired 50% of Holstein Field|
|EPL Oil & Gas||Hilcorp Energy||$550 MM||2H2012||Acquired Hilcorp’s shallow water assets|
In shallow waters, however, low natural gas prices and steeper production declines pose a challenge for all but the most robust producers. A series of mergers and acquisitions (M&A), therefore, has changed the cast of characters operating there. Longtime player Apache Corp., for example, exited the GoM entirely in 2013 except for a deepwater joint venture where it retained some rights. This is ironic in that the same month as Macondo in April 2010, it paid $5 billion to buy Mariner Energy and all of Devon Energy’s GoM Shelf assets.
Immediately after Macondo, activity slowed dramatically while the industry and regulators sought a new way forward. An IHS study in second-half 2011 showed the permitting process was taking as much as 95% longer in the wake of the tragic accident amid the strain of federal regulatory changes and economic uncertainties; no wonder operators filed 60% fewer applications for permits to drill that year. The industry has since resolved those problems.
At the June 2012 Central Gulf Lease Sale—the first of its kind in two years—there were $17 billion in sales, exceeding expectations and indicating that the recovery was underway. The march of technology was scarcely slowed in 2012 when Petrobras brought its deepwater Cascade Field to production via the Gulf’s first FPSO vessel. Drilling and producing in ever-deeper water continues thanks to technical advances, with the Lower Tertiary Paleogene plays—particularly in Walker Ridge and Keathley Canyon—the focus.
At the same time, the financial world remains eager to bet on the Gulf. In mid-2012, New York private equity firms Apollo Global Management and Riverstone Holdings committed $600 million to newly formed Talos Energy LLC for shallow-water shelf drilling. Likewise, Warburg Pincus led South Korea’s Temasek and other investors to back former Nexen employees, who created Venari Resources LLC, a deepwater-focused company, with $1.1 billion in commitments—the largest such private-equity backing in Gulf history. The parties said that while everyone else was down on the Gulf or leaving it altogether, they wanted to jump in because of its reserve potential.
Since then, large deepwater discoveries continue to roll out: Shenandoah Field in Walker Ridge blocks 51 and 52 and Coronado Field 9.6 km (6 miles) away on Block 143, and Guadalupe Field in Keathley Canyon. In January 2015 Chevron announced the Anchor 2 appraisal well drilled to Lower Wilcox at a depth of 10,287 m (33,749 ft) in Green Canyon 807. (Venari holds 12.5% in these).
In Keathley Canyon, none other than BP is underway in the deepwater Lower Tertiary Trend. Despite selling assets and cutting back activity all over the world, the company filed a plan earlier in 2015 to drill as many as 10 tests on its Tiber 3 prospect, where its Tiber discovery on Block 102 holds an estimated 3 Bbbl of oil in place.
In 2014 Shell also furthered its stellar record in the Norphlet play at Rydberg Field in Mississippi Canyon 525. When combined with the nearby Appomattox and Vicksburg fields, the complex has recoverable reserves of about 700 MMboe.
New production is on the upswing. In December 2015, Chevron saw first oil at its Jack/St. Malo complex on blocks 758, 759 and 678, another in a string of successes in Walker Ridge. The fields are expected to produce up to 500 MMboe over the next 30 years. Tubular Bells in Mississippi Canyon 725 recently came onstream as well, operated by Hess. It and partner Chevron bought out BP’s stake in the field in 2011. It may contain up to 120 MMboe of recoverable resource. Drilled to Miocene at 8,230 m (27,000 ft), it is among the deepest wells ever drilled in the Gulf.
Federal leases in the Gulf now contribute 17% of U.S. oil and 5% of dry gas production, but those numbers will increase in the near future when large projects begin production. One of the biggest will be Julia Field in Walker Ridge blocks 540, 583, 584, 627 and 628, coming onstream in 2016 and tied back to the Jack/St. Malo complex with some 6 Bbbl of oil in place.
Barclays forecasts that daily Gulf oil production will increase to 1.6 MMbbl/d by year-end 2015, up from 1.4 MMbbl/d currently. The U.S. Energy Information Administration projects production will rise to nearly 2 MMbbl/d by 2016. Consultancy WoodMackenzie forecasts that deepwater production alone, which was 1.4 MMbbl/d in 2014, will rise to 1.9 MMbbl/d by 2020.
The GoM and its operators were wounded by the Macondo incident, but five years later, important lessons are being applied, technology and spill response measures have advanced, and the Gulf’s reserve potential is again being fulfilled.