Image courtesy of CNPC

The drilling industry is built on people, and we’re running short. Despite ongoing recruitment efforts around the world, as well as accelerated training programs in place, we know we can’t undo a couple decades of neglect overnight. “You can’t accelerate experience,” said David Payne, Chevron’s VP of drilling and completion. Real-time operations centers that leverage the experience of industry veterans appear to be helping, however, as is simulator-based training.

On the technology side, industry leaders see gaps in areas such as subsea BOP control systems and water use/disposal related to fracturing. Most also agree that higher levels of drilling automation are on the way. However, perspectives on the value proposition of automation differ across segments of the business, and a shift in the business model may be needed to incentivize the next step.

Further, a shake-up in the way that operators, contractors and equipment manufacturers interact with one another could be on the horizon. “We have to find a way to change the model, to find a way to apply technologies that will actually give a better result,” said David Reid, National Oilwell Varco senior VP of global accounts and chief sales officer.

Finally, everything still comes back to safety. The industry remains focused on incident prevention and safety leadership, whether by engineering hazards out of rig designs or building in redundancies to enhance equipment reliability. There’s no silver bullet, however.

“It’s hard work. It’s repetitive work,” said Claus V. Hemmingsen, CEO of Maersk Drilling. “You have to keep working on that message, making sure you grow and motivate your people to think safety all the time.”

• David Payne, Chevron
• Claus V. Hemmingsen, Maersk Drilling
• Liao Yongyuan, China National Petroleum Corp (CNPC)
• John Lindsay, Helmerich & Payne
• Zuhair Al-Hussain, Saudi Aramco
• David Reid, National Oilwell Varco
• Angelo Calderoni, Eni
• Graham Brander, Apache Corp
• Holger Temmen, KCA DEUTAG
• Julio M. Quintana, TESCO Corp
• Datuk George Ling, PETRONAS
• Nicholas Gee, Weatherford International
• Robert W. “Bill” Rose, Prospector Offshore Drilling
• J.F. Poupeau, Schlumberger

2012 IADC Chairman Dan Rabun

If it isn’t broke, don’t fix it. So the saying goes, but Ensco chairman, president and CEO Dan Rabun challenges the notion of maintaining the status quo. Doing something one way simply because “it’s the way we’ve always done it” doesn’t necessarily produce the best results.

So when Mr Rabun joined Ensco in March 2006 as president and a director after a 20-year career as a mergers & acquisitions lawyer, he asked a number of questions about the way things were being done. Is this truly the best approach? How can we think outside the box to improve performance? “I challenged people to consider new approaches that might lead to even better results,” said Mr Rabun, who was appointed Ensco’s CEO and chairman of the Board in 2007. In this respect, his relative lack of knowledge about the contract drilling industry at the time became an asset.

One example of how Ensco took a major step forward, particularly in safety, was a rebranding campaign the company launched soon after Mr Rabun came on board. “We had made great safety improvements, but we had reached a plateau in our performance and were having difficulty seeing a path forward to even better performance. We were saying all the right things, conducting the correct training and everybody had the right intentions, but we were finding it difficult to get to the next level,” he recalled.

He and other Ensco executives came up with an idea for rebranding the company that included the seemingly unimportant task of changing the company uniforms from gray to orange – for the simple reason that orange uniforms make people easier to see on a rig instead of blending them into the background. This change was made over protestations that “our employees love their Ensco gray” and that a rebranding effort would alienate long-time employees.

When the rebranding campaign, complete with new uniforms, signage, vision and values cards, and a corporate video emphasizing the importance of safety and operational excellence was rolled out rig by rig, from New Zealand to the Gulf of Mexico, over the course of one day, “it was obvious that this was one of the best decisions we could make to energize our crews and improve our performance,” Mr Rabun said. “Since that date, our safety performance has improved measurably.”

Another goal of the rebranding was to revitalize the look and feel of the company – making it more attractive to the next generation of workers. “A rebranding may sound trivial, but the retention of our employees has improved as well, and employees now view Ensco as a more progressive company and more attractive to younger employees.”

Globalization

Asking how things may be done “even better” may also help to address the industry’s growing problem with personnel shortages, Mr Rabun believes. “The contract drilling business historically had been a US-centric business, but it is no longer,” he said. A couple of years ago, Ensco moved its headquarters from Dallas to London – a more central location for its global operations. As Mr Rabun describes, the move enhanced Ensco’s image as a truly international company that attracts workers from multiple geographies. “We operate on six continents, and the diversity of our work force is a major competitive advantage.”

IADC

As Mr Rabun begins his term as 2012 chairman of IADC, one of his main priorities is to help the association further its globalization efforts. Although IADC already has a presence in fast-growing markets such as Asia, Brazil, West Africa and the Middle East, he believes more can be done. “Over the next 25 years, these will be growth markets in this business, and IADC needs to be there taking a leadership role on issues like human resource management.”

For example, even though unemployment is high in many parts of the world, drillers are facing increasing challenges to recruit a sufficient number of competent new-hires to crew a growing number of rigs worldwide. By further globalizing itself, IADC will be able to enhance its role in helping the industry address these personnel challenges. “If we can get these chapters in the Far East, Brazil and Africa more actively involved and make them a vibrant part of IADC, we can get the global drilling industry focused on this problem and identify new ways to attract more people to our business,” Mr Rabun urged.

Friendly competitive environment

Whether it’s because of the spirit of collaboration fostered by groups such as IADC or simply because there’s good people in this business, Mr Rabun says he continues to be impressed with the cooperation among drilling contractors. “While we all compete for new business and for talent around the world, it’s an extremely friendly competition,” he said, noting that it’s not uncommon for a contractor to come to the rescue of another if, for example, a piece of long-lead time equipment goes down.

Whether it’s drilling technologies, safety or regulations, in a way we’re all in this together. “We have the same problems, and we can’t address them all by ourselves.” Mr Rabun hopes that, in the coming years, IADC will continue to be the glue for collaboration among contractors. “IADC plays a key role in providing a forum for the whole industry,” he said.

Ensco continues to invest in the more technologically capable rigs that operators are demanding, such as the Ensco 8503. The semi is operating in the Gulf of Mexico for Cobalt International Energy.

Industry future

Looking to the future, Mr Rabun is unfazed by the industry’s historical cyclicality and believes it remains a fundamentally strong business. “I look at the macro picture. As long as the global economy is growing and the BRIC countries are growing, demand for hydrocarbons will continue to increase. Even the recent global financial crisis – although painful – didn’t slow the oil and gas industry down for long.

“I don’t think we’re going to find ourselves in one of those mid-’80s 20-year slumps. I just don’t see that as a fundamental risk for our business. You will continue to see speed bumps, but they’re not going to fundamentally change the business.”

Ensco, like much of the industry, has made significant investments in more technologically advanced deepwater rigs and jackups and has sold less capable rigs. Mr Rabun notes the company has doubled its fleet size since he joined. The growth of the fleet will continue with two drillships, two semisubmersibles and three jackups still under construction. The company also has significantly expanded the scope of its global footprint, with rigs now in all major markets around the world.

“We’re going exactly where our customers are going,” Mr Rabun said. “If you ask me where I want the business to go, it’s really not my decision. It’s our customers’ decisions, and our customers are going to more remote locations in very deep waters. In shallower water, they’re drilling to much deeper well depths.”

“I’m very proud of what this industry does. Our people regularly work far from their families in remote locations. There is a great deal of personal sacrifice in this business. We perform an extraordinarily valuable service providing energy for the world.”

Mr Rabun was a partner at the international law firm of Baker & McKenzie for 20 years before joining Ensco in 2006. He is a certified public accountant and holds a BBA in accounting from the University of Houston and a Juris Doctorate degree from Southern Methodist University.

He lives with his wife of 33 years, Roxanne, in central London, where they enjoy walking their two dogs and riding their two horses. Their daughter, Christina, lives in Scottsdale, Ariz.

By Katie Mazerov, contributing editor

The bounty of resources that lie beneath the icy region known as the Arctic holds great promise but also poses some of the greatest risks and challenges the oil and gas industry has ever encountered.

Shell has been active around the world in Arctic regions. Aside from developing Sakhalin-2, the company drilled several wells in the Beaufort and Chukchi seas off the North Slope of Alaska before moving out of the region in 1998. Shell re-acquired many of those leases in 2005 and 2008.

Although the significant amount of conventional oil and gas believed to exist in the Arctic has become increasingly attractive to operators, political, environmental and technological issues continue to present significant obstacles for development. Covering roughly 6% of the Earth’s surface, the Arctic comes under the jurisdiction of multiple nations with recoverable resources – the US, Canada, Greenland (Denmark), Norway and Russia. Harsh weather, with a limited window for drilling, requires extensive planning, risk management provisions and new equipment and technologies that can provide greater efficiency and withstand temperatures below -50°F.

According to the US Geological Survey (USGS), as of 2007, more than 400 Arctic oil and gas fields had been discovered. Those developments include 40 billion bbls of oil, 1,136 trillion cubic feet (Tcf) of natural gas and 8 billion bbls of natural gas liquids, most of it onshore in Western Siberia and on the North Slope of Alaska.

A 2008 USGS study, the Circum-Arctic Resource Appraisal (CARA), estimated that about 30% of the world’s undiscovered conventional gas and 13% of the world’s yet-to-find conventional oil may be located north of the Arctic Circle, above the 66.56° parallel, most of it along the shelf, in water depths of 500 meters or less.

The Arctic continental shelves are one of the world’s largely untested prospective hydrocarbon areas, said research geologist Dr Donald L Gautier, principal investigator for CARA and project chief of the USGS World Petroleum Project. While the bulk of the resources are offshore, most of the production has been onshore. “Offshore production in the Arctic is technically challenging and expensive and can be difficult politically,” Dr Gautier noted.

CARA used a probabilistic methodology to evaluate 49 geologically defined assessment units (AUs), the most significant for oil being the Alaska Platform, the Canning-Mackenzie area in western Canada, the North Barents Sea, the Yenisey-Khatanga Basin in Siberia, the Northwest Greenland Rifted Margin and the northeast Greenland shelf.

Undiscovered natural gas in the Arctic is three times more plentiful than oil, with the bulk located in Russia. Yet-to-find gas resources could range anywhere from 770 Tcf to 2,990 Tcf, with two-thirds  located in four AUs – the South Kara Sea in the West Siberian Basin, the South Barents Basin, the North Barents Basin and the Alaska Platform.

“The best places for deepwater resources are along the continental margins,” Dr Gautier said. The geology indicates that the deep ocean basins, such as the Canada Basin and the AmerAsian Basin, may not have the same potential as the shallower continental shelf. “It’s not about the depth as much as it is about the geology of the deep basins.

“From a strictly geological standpoint, I believe the most prospective region for oil in the entire Arctic is offshore northern Alaska and northwestern Canada across the Beaufort Sea and the Chukchi Sea. But that area is challenging from a political standpoint,” Dr Gautier said.

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Real and Perceived Issues

Political forces have made doing business in the region a complicated undertaking. “The Arctic can be defined in a number of ways beyond geography and temperature,” said Mitchell Winkler, principal technical expert for Arctic engineering for Shell. “The region has always been challenging from the standpoint of ice, seasonality, harsh weather and darkness that pose technical challenges, but there are also many social, political and environmental challenges, both real and perceived.

“There is a lot of discussion over who owns the Arctic,” Mr Winkler continued. “We know there are vast oil and gas resources in the region, and we expect most of those resources to lie within the jurisdictional limits of the Arctic coastal nations. While there are ownership issues for the Arctic beyond these jurisdictional limits, oil and gas exploration should not be expected in these areas any time soon due to resource prospects and ice conditions.”

Shell has been active onshore and offshore Alaska and Canada for nearly 50 years and previously drilled several wells in the Beaufort and Chukchi seas off the North Slope of Alaska before moving out of the region in 1998. Shell re-acquired many of those leases in 2005 and 2008 and was successful with 19 blocks in the Beaufort Sea in December; the company hopes to begin drilling again this year, Mr Winkler said. Shell also holds two leases in Baffin Bay in a consortium with Statoil, GDFSuez and Nunaoil, the national oil company of Greenland, off the northwest coast of Greenland.

The company was the original developer of the prolific Sakhalin-2 field in far east Russia, over which the Russian national oil company Gazprom has taken control. Russian provisions mandate that all resources on the country’s continental shelf be developed by nationalized operators, Mr Winkler noted.

The structure of the Molikpaq platform was built to operate in severe ice conditions so it could be used in the deeper waters offshore Sakhalin Island. Technology plays a big role in the Arctic, noted Mitchell Winkler, Shell’s principal technical expert for Arctic engineering.

“Technology plays a big role in the Arctic because it allows us to do more, with increased safety, in a severe operating environment,” he continued. “But working in the Arctic is about risk management and developing the required operational practices and procedures to ensure safety and reduce the environmental impact of our operations,” he noted.

“It is critical that we understand and quantify hazards and have shut-down plans in place where hazards exceed the operating parameters.”
For example, Shell and other major operators rely on satellite and synthetic aperture radar to detect and observe ice hazards and movement patterns. Synthetic aperture allows visibility through the clouds.

“By using unmanned aircraft, or drones, which dramatically reduce the emissions footprint, we can do close-in surveillance to take people out of harm’s way,” Mr Winkler said.

Shell also is considering using autonomous underwater vehicles as an alternative to towing a sonar device, for shallow seafloor surveys. “Such technology would allow us to reduce the intensity of exploration activities during the precious open-water season, where operations may interfere with marine mammals – such as the Bowhead whale – and their migration,” he pointed out.

Technology is being used as a way of reducing the environmental footprint in terms of air, sound, emissions and improving oil spill response. “First and foremost, our focus is preventing oil spills,” Mr Winkler said.

“It starts with well design and includes blowout preventers (BOP) with redundant shear rams and real-time operation centers where data on the rig can be transmitted by telemetry to a remote center where experts can monitor the data and provide support to the personnel on the rig. The focus is on the prevention side, but we still need to have a robust spill-response plan.”

Long-term, the Arctic will be a driver for developing technology, Mr Winkler believes.

“We need to look beyond conventional solutions and paradigms,” he said. “Drilling is one example where speed is more than ever a driver, given the short open-water season. In the case of logistics, we need to look beyond conventional methods that often lead to larger vessels and more horsepower, and look for ways to reduce design requirements, which would have the added benefit of reducing both required personnel and the size and scale of the needed emergency response systems.”

Challenges Offshore

Shell was the original developer of the prolific Sakhalin-2 oil and gas field in far east Russia that was later taken over by national oil company Gazprom. Pictured is Molikpaq, one of three offshore production platforms in the Sakhalin-2 project.

In the offshore Arctic arena, the risks and technical barriers on all fronts are particularly daunting, said Gavin Humphreys, new business and technology manager for Aberdeen-based Stena Drilling. The company is not currently operating in the Arctic but in 2010 provided a sixth-generation drillship and a semisubmersible for an Arctic summer drilling campaign in West Greenland. The company currently has two rigs, the Stena Don and Stena Carron, working in the harsh winter environment of the Norwegian North Sea and west of the Shetland Islands.

“The development of oil and gas in the Arctic is going to be complex, especially when one considers the challenges of transferring the lessons of oil or gas production from land locations to the Arctic offshore,” Mr Humphreys said, noting that in addition to planning and risk management, hydrocarbon production in these new regions needs to be seen as providing long-term growth opportunities for regional communities.

“Drilling contractors and service providers also need to consider a multitude of practical issues, not the least of which is the remote operating environment, where ice management, logistics, supplies, crew change, among other factors, are currently structurally non-existent but require substantial investment to create a true oil and gas development environment,” he continued.

Water depths across the prospective Arctic regions range from very shallow up to 1,000 meters, and dictate whether the rig needs to be equipped with dynamic positioning capability, anchors or both. The rig mobilization and de-mobilization philosophy of the operator is an issue that is especially relevant to the US/Canadian Beaufort Sea, Mr Humphreys said.

Operator requirements with respect to the drilling season, such as ice cycle and management, and the impact on rig design, also must be considered. “Finally, there are environmental demands, such as the need for relief well drilling, from regulators and local communities,” he noted.

A hydrophone is deployed and ice thickness is measured during seismic operations on an ice field trial.

In addition, more sophisticated techniques for acquiring seismic data are required for exploration wells. “While subsurface geological risks can be dramatically reduced through well design and appropriate BOP provisions, the well construction process that has been well-defined for offshore drilling needs to be further developed in terms of effectiveness, environmental compliance and contingency planning, for offshore production,” Mr Humphreys said. “This would be most relevant for the designs and functional specification of drillships or semisubmersible rigs permanently assigned to work in the Arctic.”

The increasing complexity of well designs also may mean that it will take up to two seasons to drill, complete and test an exploration well.

“On discovering a movable hydrocarbon that requires testing for evaluation purposes, conventional testing techniques may not be appropriate, primarily for environmental reasons, and as such, an alternative needs to be developed,” he continued. “Due consideration needs to take place with respect to the health, safety and environmental aspects of suspended wells, such as whether there will be requirements to have the wellhead below seabed to avoid damage through ice scouring, and determinations of the most appropriate technology to build the glory holes to accommodate the wellheads and BOPs.”

While drilling rigs may be able to carry on board all the necessary materials – wellheads, casing and bulks, etc – for drilling a single well, in remote areas there will be a requirement for helicopters that can travel extended distances, mainly in the dark during the Arctic winter, fully loaded and in extremely cold weather for crew changes and medical evacuation, Mr Humphreys added.

“The single most complex issue for the Arctic when it goes into development mode is not the technologies related to permanent production platforms, floating production storage and offloading units, or subsea field development system design, or even how the oil or gas is evacuated. Because while the engineering and technology are complex, the technical issues can be resolved at a cost.

“The whole development scenario hinges on having an integrated logistics and supplies infrastructure that can support the drilling rigs, production facilities and export routes in the heart of the remote and hostile Arctic environment,” he said.

Harsh Climate Solutions

While significant barriers remain for near-term offshore development, new equipment and methods are being introduced and tested for the onshore market to withstand the lowest temperatures of the Arctic permafrost.

Stena Drilling, whose Stena Carron drillship is operating in the harsh-environment west of Shetlands, provided two rigs for an Arctic summer drilling campaign in West Greenland in 2010.

Weatherford International has achieved success with its drilling-with-casing (DwC) technology in the gas-rich Yamal Province of Western Siberia. The technology, which uses casing strings instead of drill pipes, enables the permafrost layer to be drilled in a single trip, eliminating nonproductive time (NPT) and improving drilling efficiency by minimizing cement and  reducing trips to run drill and bottomhole assembly (BHA) components into the well, said Mike Sutherland, drilling optimization services manager.
Since November 2009, the DwC technology has been used to drill close to 20 onshore gas wells for three major Russian national operators. At the 2010 “Tools and Equipment for the Oil and Gas Industry in Russia” forum, Weatherford received an Oilfield Services award for the DwC technology and its impact on drilling in Russia following its success on several test wells. It is now being used as the primary method for drilling upper-hole sections in two fields. The technology has been shown to save up to three days of rig time and to reduce fluid loss and mud and cement costs.

The DwC equipment uses steel grade rated from 30°F to -40°F to accommodate the wide range of climate conditions that can impact drilling operations and transportation in the region. “The size of the country and the weather mean planning needs to be well-controlled and organized, very much like a military operation,” Mr Sutherland said. “From the end of November through March, the roads become usable when the marsh freezes over. Then we wait for the thaw and use the river systems. Mid-August through November is a transitional season, when the ground is very soft and difficult to operate in,” he said.

“Typically, the onshore Arctic has a permafrost formation which runs from 0 to 350 meters deep,” Mr Sutherland continued. “We set the casing depth around 450 meters, which gives us 100 meters into the clay stones beneath the permafrost. This gives us a firm casing seat prior to drilling the next section. DwC is usually deployed from the subsurface, anywhere from 20 to 40 meters up to 400 to 700 meters.”

VAM Drilling’s new harsh-environment drill pipes sit stacked in the permafrost on the North Slope of Alaska. High risks are associated with damage during ground transportation and surface handling of tubulars, especially in arctic fields.

The system uses a drillable casing bit from the Defyer series that is attached to the first joint of casing. The casing is rotated in the same way drill pipe rotates in a conventional operation that uses the Overdrive casing, running and drilling system.

“As one of the biggest producers of gas in the world, Russia is a developing market, and there is huge potential here for the DwC technology,” Mr Sutherland said. “The bulk of the production is onshore, but the major operators are beginning to look at more offshore development, which will likely increase over the next five to six years.”

Redesigned Drill Pipe

VAM Drilling manufactures a line of harsh-climate tubulars from the rig floor to the  BHA, including drill string, drill collars, accessories and valves. The company recently introduced a new drill pipe, VM-135 DP LT, that maintains full ductility at temperatures as low as -60°C, according to marketing and technical managers Philippe Machecourt and Kamal El Bachiri. The first delivery of the product was for Gazprom. It has not yet been deployed.

“Operators and drilling contractors are looking for the same tools in terms of performance as are usually used, but which are also suitable for very cold temperatures,” Mr Machecourt said. “Extremely low temperatures change the behavior of the steel. The underlying issues are not uniquely related to the service temperature of the equipment, but rather to the high risks associated with susceptible damage during ground transportation and surface handling, especially in arctic fields.

“The drilling operating parameters are no different between wells in the arctic and non-arctic conditions,” he added. “The shock of the extreme conditions on the steel dramatically increases the risk of equipment failure, leading to a higher scrapping ratio for the product and a huge potential increase of NPT.”

A key goal in developing the technology was overcoming a problem that occurs with steel: the higher the yield strength of the steel, the lower the toughness. VAM Drilling’s customized low-temperature steel grades combine new steel-making technologies and a controlled manufacturing method designed to achieve both yield strength and toughness, Mr El Bachiri said. The process includes high-quality steel, advanced rolling-process technology, fit-for-purpose chemical composition, and an improved heat treatment process.

“The drill pipe presents a better stability and consistency because we use higher quality with, in particular, all the micro-alloy benefits,” he said.

In one case, VAM Drilling provided high-strength drill pipe that also featured a very thin wall pipe body for an ultra extended-reach well on the North Slope of Alaska for a major operator. Because of the environmental sensitivity of the area, the rig could not be placed directly over the wells, so drilling commenced more than six miles from the reservoir. “Had we used regular steel, the drill pipe would have needed to be a certain wall thickness to perform,” Mr El Bachiri explained. “But by using higher-strength steel on the drill pipe, the wall thickness was thinner, so the pipe weighed less and the operator was able to better drill this extremely extended-reach well.”

Methane Hydrate Prospects

This aerial photo shows the temporary ice pad in 2011 that was built for the Ignik Sikumi test well; it has since been rebuilt. In the background is one of the permanent operating gravel pads within the Prudhoe Bay Unit.

The Arctic also is believed to hold considerable unconventional resources, including coalbed methane, oil shales, heavy and viscous oil and tar sands and methane hydrates. This year, the US Department of Energy (DOE), ConocoPhillips and the Japan Oil, Gas and Metals National Corp will embark on a project to test a technology for developing methane gas from hydrate deposits on Alaska’s North Slope. The test is taking place on the onshore Ignik Sikumi gas hydrate test well that was drilled in the Prudhoe Bay area by ConocoPhillips and the Office of Fossil Energy’s National Energy Technology Laboratory (NETL) in 2011.

“The USGS has reported an estimated 85 Tcf of technically recoverable methane in gas hydrates across the Alaska North Slope,” said Dr Ray Boswell, technology manager, methane hydrates for NETL. Methane hydrate consists of molecules of natural gas trapped in a framework of water molecules in sediments in and below thick Arctic permafrost and in the subsurface of most continental waters that are 1,500 ft or more deep, Dr Boswell explained.

The test, which is being conducted from an ice pad during the 2012 winter drilling season (January to April), will involve injecting carbon dioxide (CO2) into methane hydrate-bearing sandstone formations. It is hoped that the CO2 will exchange with the methane (CH4) molecules in the hydrate structure, resulting in the release of methane gas and permanent storage of the CO2 in the formation. The DOE has invested $14 million in the project, including the prior Ignik Sikumi well installation and the upcoming testing program.

A total 85 Tcf of technically recoverable methane gas is estimated to be in hydrates across the Alaska North Slope. Image and map courtesy of the Department of Energy.

Other gas hydrate field programs, such as Japanese-Canadian “Mallik” testing in Arctic Canada in 2007-2008 and the DOE-USGS “Mount Elbert” program with BP Alaska in 2007, have focused on reservoir depressurization as the preferred means to produce gas hydrates. In this method, fluids are pumped out of the borehole to reduce pressure in the well, resulting in dissociation of methane hydrate into methane gas and liquid water, Dr Boswell explained.

“The exchange test is targeting an application that has a very different focus. We want to understand  the basic potential of the CO2 injection technology,” he said. “This will be the first step down the road to determine the potential for recovering methane hydrates with a process that also permanently stores CO2. If this test is positive, there would certainly be a need for tests at larger scales.

“A major challenge,” he continued, “is conducting what is basically a science program, which requires non-standard oilfield equipment, within an active operating area without interfering with the operator’s core business.”

The final stage of the exchange tests will include reservoir depressurization to capture the released methane and then to recapture the injected CO2. “This phase of the testing will assist in the evaluation of reservoir response to depressurization,” he said.

DwC and Defyer are trademarked terms of Weatherford International Ltd.

By Katie Mazerov, contributing editor

While they are hardly new on the oil and gas completion front, expandable technologies are coming of age when highly deviated, mature and depleted wells are the norm and when deep, high-pressure/high-temperature (HPHT) wells are no longer out of reach. As operators exploit resources once deemed unobtainable, expandable liner systems and casing patches are emerging as standard tools of the trade.

“Historically, expandable products have been a premium product with a large price tag,” said Scott Benzie, vice president of engineering and technology for Mohawk Energy, which develops, manufactures and installs solid expandable tubular products.

Mohawk Energy is preparing to launch the MetalPatch, which provides a metal-to-metal seal between the primary casing and an expanded patch. The patch is designed for well integrity issues and can be installed inside the casing anywhere from 30 ft to 6,000 ft in length.

The company expects to launch its new MetalPatch product for cased-hole completions early this year. The technology provides a metal-to-metal seal between the primary casing and an expanded patch.

“Our goal is to provide a mainstream product for cased-hole patching,” Mr Benzie said.

The patch is designed for well integrity issues, such as patching failed completion equipment, or connections, and re-lining of wells with corrosion or perforations along both short and long intervals. The patch is installed inside the casing anywhere from 30 ft to 6,000 ft in length.

“We believe the metal-to-metal feature will be a game-changer because it eliminates the need for elastomers or rubber, which can degrade over time,” he continued. “All elements of the patch use metal-to-metal sealing technology, both for the upper and lower seals and the premium threads on each joint. Also, the product can work within the tolerances of the customer’s API casing, by use of a proprietary compliant sealing system, allowing reliable sealing for variations in API inner diameters.”

The initial target market for the technology is North American land operations, where the patch can be used when frac valves fail, or simply patching leaking connections in cased-hole completions. “We have done extensive testing, including through-pressure and axial load cycle testing,” he said.

A future application would be re-fracking operations in the US shale gas market where the operator needs to re-line existing perforations in the completion with a patch that has high-pressure capability. “The MetalPatch product provides high-pressure and -temperature capabilities, allowing future re-fracking operations,” Mr Benzie said. “One additional advantage is that it can run through nipple restrictions and set the patch below, saving time for the operator as no milling is required to deploy the patch.”

Unconventional shale applications

Weatherford’s MetalSkin cased-hole liner system can be deployed to maintain casing integrity in mature wells that were not cemented all the way to surface and have corrosion problems.

Weatherford International’s MetalSkin solid expandable cased-hole liner system is increasingly being deployed for wells requiring re-entry, re-fracturing and isolation, particularly in unconventional shale formations. The liner, which has a thick wall and a high burst-and-collapse rating, can be used in highly pressurized wells and is being developed for multiple casing sizes. The system was adapted for today’s market from the HOMCO internal steel liner casing patch, a thin-wall patch that has been used for nearly 50 years and is still a solution for repairing mature wells that are not highly pressurized.

“We’re seeing a lot of scenarios in wells that have been producing for 10, 15, 20 years where a zone has become depleted but the operator has identified a new formation,” said Asim Siddiqui, business development manager, North America. “With new solid expandable liner technology, we are able to isolate that depleted zone and achieve a larger internal diameter (ID) for maximum completion size, instead of using a straddle packer or conventional liner that results in a smaller ID and thus lower production.”

Another application is maintaining casing integrity in mature wells that were not cemented all the way to surface and are encountering corrosion problems, or where the old casing has eroded because of the well environment.

“We can run an expandable liner that will cover up the section that is corroded, patch it and still complete the well with full integrity and maintain a larger ID,” Mr Siddiqui said.

The system was used to repair corrosion damage in two long 7-in. casing intervals in a 57-year-old well in north central Texas. Production was brought back online eight days after the liners were expanded and pressure-tested, serving as an alternative to the conventional squeeze method that had failed six times on the well.

Advanced liner technology also has proved effective in isolating depleted or nonproductive zones in horizontal wells in shale plays such as the Bakken and Marcellus.

“Typically the casing size is 4 ½ in. so we can easily cover up the nonproducing zone with the thin-wall internal casing patch, allowing the operator to re-frac or re-stimulate other zones for production,” Mr Siddiqui said. In one case, where the operator needed to isolate multiple zone-fracking sleeves and packers, nine different internal casing patches were installed in each zone so the operator could perforate and frac through the casing.

The newest repair application of the MetalSkin liner will be a 3 ½-in. expandable liner that expands inside 4 ½-in casing. “This will be ideal for corrosion repairs in depleted formations and in re-fracturing or re-stimulation operations that use 4 ½-in. casing,” Mr Siddiqui said. “Using conventional liner in these cases can significantly reduce ID, treating pressures and production.”

Weatherford has invested a significant amount of time and effort in developing its own expandable liner connection, Mr Siddiqui said. “For example, for a 200-ft zone, instead of running multiple expandable liners, we can isolate the zone with a 300-ft liner in one run, resulting in fewer trips into the well and less personnel,” he explained.
While the system is commonly used in onshore North American operations, it is suited for deepwater applications because it does not significantly reduce the casing size, Mr Siddiqui said. A 7 5/8-in. expandable liner was used to repair a leak in 9 5/8-in casing in a 20-year-old North Sea well. The system eliminated the need to cut or mill out more than 6,000 ft of casing, saving the operator significant time and $6 million in costs, and extending the life of the well.

For larger casing sizes, the HydraSkin solid expandable system has been used for deepwater operations. A major operator in the Gulf of Mexico used the liner in a deviated well where multiple trips in and out of the well had caused damage to two long laterals in the 13 3/8-in. casing. Two sections of HydraSkin liner were installed in five days, resulting in improved pressure integrity and providing a whipstock seat for a sidetrack well.

Halliburton’s VersaFlex breech lock system, designed for extended-reach drilling operations, set a record in helping an operator gain 175,000 lbs of compression to reach bottom in a well in the Bakken Shale. The system can handle up to 200,000 lbs of weight-down compression in the 5 in.-by-7 in. tool size.

Achieving maximum compression

Expandable systems are being used in deviated and extended-reach wells where operators face huge challenges. Halliburton’s VersaFlex expandable liner hanger (ELH) system includes the breech lock technology that was designed specifically for extended-reach operations. The system set a record in helping an operator gain 175,000 lbs of compression to reach bottom in a well in the Bakken play in North Dakota. “With that kind of compression, it’s not hard to imagine there are obstacles to reaching needed depth,” said Ron Nida, strategic business manager for ELH systems.

“Pushing 20,000 ft of liner string with more than half of it loaded down by production equipment while transitioning tortuous geometry and fighting gravity and friction is a real challenge for our operators in the Rockies,” he continued. “When customers add swellable packers and hydraulic fracturing equipment to the horizontal stretch, extreme drag against jagged edges, ledges and seats from previous drilling requires extreme compression at the liner top. Running along the floor of a horizontal, open hole, operators also work against geological anomalies, swings and dips in the wellbore.”

The breech lock system takes its name from the bolt action rifle, which uses lugs at the front of the breech so that the force of compression focuses in the bullet (in this case, the liner),  toward the chamber (open hole), Mr Nida explained. The system can handle up to 200,000 lbs of weight-down compression in the 5 in.-by-7 in. tool size.
Deepwater environments, where heavily faulted or fractured intervals can cause unstable conditions in the face of high equivalent circulating densities (ECD), pose different challenges for operators. These low-gradient formations are high risk for fluid loss, explained Abdolreza Gharesi, ELH product manager for Halliburton. “Pressure regression from depleted zones or geological phenomena may compromise borehole stability, causing fluid loss into the formation, and possibly resulting in a loss of the well if circulation is not achieved,” he said. Such conditions are often found in mature wells and in overpressured formations in deepwater.

The VersaFlex ECD system was developed to maintain circulation and keep pressure off unstable formations. The ECD hanger, designed with a small outer diameter (OD) with no inner-diameter restrictions, increases the flow path between the previous casing and the hanger body so that mud and fluid are circulated out of the hole at a rate that takes pressure off the formation but keeps mud weights high enough for safe debris removal, Mr Gharesi said. “With more room in the bypass area, the formations are less likely to take on fluid, and assist in maintaining circulation.”

Field tests indicate the system reduces pressure drop across the liner top during circulation and cementing. “Reduced pressure is achievable within a wide range of mud weights,” he continued. “This is accomplished by the highly reduced OD not found on industry-standard liner hanger equipment.”

The increased bypass area also allows faster trip-in speeds and opens perimeters previously limited in drill-in with liner applications, he noted.

Above and below: Baker Hughes’ TORXS expandable liner hanger system has no external mobile parts and is designed to withstand operations in harsh environments.

Troubleshooting lost circulation

Baker Hughes has used its expandable liner hanger system, TORXS, to facilitate completions in several offshore oil and gas wells, including HPHT wells operated by PEMEX in the aging Cantarell and Littoral Tabasco reservoir of the Bay of Campeche.

“The TORXS system was designed for extreme applications such as high-pressure wells that have depleted or lost circulation zones and thus require a larger bypass area,” explained Maurilio V Solano, Baker Hughes’ global casing/liner drilling product line manager. “If we can achieve good bypass in the trouble zone, we can circulate under better conditions due to less ECD and less pressure on the annular area,” he said.

The one-trip, hydraulically balanced expandable hanger system provides high torque capability for reaming or drilling while maintaining moving mechanisms inside the liner hanger assembly, not in the annulus like standard Baker Hughes liner hangers.

“A huge benefit of the system is the torque capability and the ability to rotate the system up to 100 RPM,” Mr Solano said. “Conventional liner systems reach a point where they can’t continue to go deeper and can only be pushed in an attempt to make it to TD. The TORXS system allows you to rotate at high torque rates, which keeps the liner moving to bottom.”

Another benefit, he continued, is that the internal pressure can be higher without presetting or releasing the hanger.

“With standard systems, we have the obstacle of not being able to go above 1,800 psi, meaning we can’t get circulation rates high enough for good hole cleaning and cuttings removal,” he said. “With this technology, we can clean out the hole using a high pump rate and high circulation pressures, resulting in a good cement job. If we were to lose all circulation, anything we pump downhole would be lost, leading to stuck pipe, lost rig time and sidetracks, resulting in a huge loss in time and money. However, the benefits gained by running the TORXS system allow better operating conditions in difficult wells, like the ones at Campeche’s Bay.”

For PEMEX, the liner drilling system was deployed in two offshore fields. In the more challenging case, stuck directional drilling tools and leaking of diesel-based mud into the formation were causing fluid loss. The fluid level was at 4,265 ft, forcing the operator to consider abandoning the well. The TORXS expandable hanger, with its high torque capability and better bypass area, used in conjunction with an 8 ½-in. EZCase bit, allowed the liner to be deployed through a window and lost-circulation zone to reach bottom.

After drilling through the trouble zone with the liner, PEMEX was able to drill the next section with seawater, resulting in savings due to a reduction in diesel-based mud and drilling time.

In another well in the same area, the expandable hanger system was used to hang 8,860 ft of liner through a window and through the lost-circulation zone in a 64° deviated well and drill down with the liner the last 243 ft.

The second field, which involved an HPHT reservoir from 15,000 ft to 18,000 ft, used these systems to ream the liner to bottom in long horizontal sections. The hanger-setting mechanism is located in the liner hanger running tool and not in the landing collar like some conventional liner systems. This allows easier manipulation and operation of the running string in these horizontal sections, according to Baker Hughes.

“It was necessary to drill with the liner at Cantarell field, beneath the Bay of Campeche in Mexico, so we could set the casing at the base of the Lower Paleocene before touching the fragmented Breccia formation,” said Uriel J Perez Ramayo, drilling superintendent for deepwater operations for PEMEX.

“This was essential because this zone is drilled with complete lost circulation due to wellbore collapse at the upper end of the formation.

Another drilling challenge is the transition zone, which has some water swellable shales that make drilling with water nearly impossible.

“That is why liner drilling becomes a key factor,” Mr Perez Ramayo continued. “It was necessary to bypass and case this transition zone with diesel-based mud but continue drilling the next section with seawater as a mud system. This translates to cost savings and reduced drilling time; typically from 50 days to about 10 to 12 days on that section. Drilling with diesel-based mud is not only expensive, but the lack of diesel-based mud supplies due to bad weather or the short supply of diesel increases the drilling costs tremendously.”

Mr Solano believes that completing these wells would have been more challenging to PEMEX without this technology. “As wells become increasingly complex, more operators are requiring this type of technology,” he said.

MetalSkin and HOMCO are registered terms of Weatherford International Ltd. HydraSkin is a trademarked term of Weatherford International Ltd.

VersaFlex is registered term of Halliburton. TORXS and EZ Case are trademarked terms of Baker Hughes.

Activities related to oily and liquids-rich plays in the onshore US have risen significantly since 2008. From 2001 to 2008, fewer than 20% of US land rigs were drilling in these plays. Today, oil and liquids-rich targets, including the Eagle Ford (horizontal gas), Marcellus (West Virginia, southwest Pennsylvania), Granite Wash (horizontal gas) and Cana-Woodford (horizontal gas), represent two-thirds of the market’s total rig count.

Supply/demand likely to keep drilling levels high; US onshore rig count expected to increase by 15%

By Katie Mazerov, contributing editor

Amid macro-economic uncertainty and market volatility, analysts are putting the industry on a promising-to-bullish track for 2012 as oil prices remain solid, rig counts rise and the offshore industry turns the tide from the doldrums it was in a year ago.

Despite a downturn in North American shale gas production, most industry watchers are seeing an uptick in activity as evidenced by significant discoveries in the North Sea and Gulf of Mexico (GOM), the continued ramp-up offshore Brazil, steady growth in the West Africa and Asia Pacific markets, and an active and growing international liquefied natural gas (LNG) trade.

The global supply of oil, considering OPEC spare capacity, remains challenged. John Keller of financial services firm Stephens Inc said he believes drilling activity outlook for 2012 is promising.

After a year marked by post-Macondo jitters, heightened regulations and the Arab Spring, analysts believe the industry is ready for a healthy return to stable growth.

“In investors’ minds, macro fears are trumping everything else at this point, whether it’s slowing economic growth, the potential for recession or fears about European debt,” said John Keller, vice president and oilfield services research analyst for Arkansas-based financial services firm Stephens Inc. “But through all these fears, when you look at oil prices, the global outlook for drilling activity as we go into 2012 remains pretty promising.”

From a supply and demand perspective, international supply remains challenged, he said. “The fallout from the split among the OPEC countries earlier this year, with Saudi Arabia moving forward with development plans in light of desired production cuts by other OPEC members, hasn’t fully started to ramp, yet. That will underpin growth in that region, as will continued development in Iraq.”

From left, John Keller, Marshall Adkins and Collin Gerry

There is some uncertainty about the impact on supply and oil prices by the anticipated return to production in North Africa following the Arab Spring. “The wild card is how quickly Libya will recover,” said Marshall Adkins, managing director of energy research at Raymond James & Associates.

“But even when we factor Libya coming back online mid-2012 and a global recession, which implies the OECD (Organization for Economic Cooperation and Development) will be in recession, the global oil model is just about as bullish as I’ve seen in decades.”

The global jackup market is poised for a rebound, with Asia and the Middle East leading the way, according to Collin Gerry of Raymond James & Associates. Global jackup utilization has increased to 90% (top), and the number of jackup rig years contracted per quarter has accelerated above pre-recession levels (bottom).

Barring a severe recession emanating from Europe, supply and inventories are low enough to keep oil prices firm, he added. Oil prices also will hold up if governments opt to print more money in response to over-leveraged situations.

“Fundamentally, from a supply/demand standpoint and from a global money situation, oil will continue to be the main driver of activity, particularly in North America, where drilling is expected to see double-digit growth, mostly in the liquids-rich and oil plays,” Mr Adkins said.

Due to typically slower growth rates, the international market will see growth of 6% to 9%, he continued. Higher natural gas prices in most international markets will support continued production in shale and other unconventional gas plays, particularly in Australia and South America.

The global jackup market is poised for a rebound, as utilization has increased from 82% to 90%, signaling an increase in rig pricing, Collin Gerry, vice president, Oilfield Equity Research at Raymond James. “Almost all jackup activity is driven by Brent oil prices, which have remained above $100/bbl,” Mr Gerry said.

Asia and the Middle East lead the jackup market. “Currently, there are 100 jackups in Asia, including India, China and Southeast Asia, which is at the high end of the historic demand range,” he noted.

“The nuclear disaster in Japan and moves by Germany to shut down reactors also will bolster the outlook for LNG,” Mr Keller said. “Oil prices are the driver for international activity simply because LNG internationally tends to be priced off oil prices or some function of oil prices.”

Gulf of Mexico

Oil will continue to be the focus of activity in the GOM, but ongoing and heightened regulations and the still-slow pace by the US government to issue permits cloud the post-Macondo picture.

“The GOM remains a political football on outlook, but it will really boil down to how quickly permits continue to be issued, and sustainability of the level of permitting will determine how that market plays out,” Mr Keller said. “When you’re a major operator looking out across the globe, where access to hydrocarbons is becoming more restricted due to geopolitical events and nationalization, the GOM still looks very good and the resource potential is there.”

A positive development has been the recent large ultra-deepwater discoveries by ExxonMobil, Chevron and BHP Billiton in the highly pressurized Lower Tertiary geological formation.

Dane Groeneveld

“Even before 2010, we saw companies reducing their exploration and appraisal drilling campaign budgets,” said Dane Groeneveld, regional director for NES Global, which provides engineering services and specialist staff support for the energy industry worldwide. “The situation was already difficult; then Macondo happened.

“But we are seeing a return to more work in the Gulf, with operators allocating more time and resources in the geoscience departments for future developments,” he continued. “As a result, we are seeing an increase in rig rates and support for more drilling going into 2012.” NES Global is being asked to find development geologists, reservoir engineers and drilling engineers for work on developing assets in these leases. “The uptick this year will be a continuing trend over the next few years,” Mr Groeneveld said.

Philip Weiss

Permitting remains an issue, however. The active deepwater rig count in the Gulf had moved up to more than 20 by early October, higher than it was last year but still well below pre-Macondo levels. “We’re seeing a lot of interesting prospects with significant potential, but because of the government’s slow pace in issuing deepwater permits, we haven’t been able to move these discoveries and previous discoveries forward, which is disappointing,” said Philip Weiss, senior analyst, energy for Argus Research.

“Operators are sitting on a lot of nonproductive capital because they can’t get these projects moving,” he continued. “We have 23 (active deepwater) rigs in the Gulf now, but there are questions about what will happen when that work is completed. There is not a pipeline of other projects with permits in place. That increases the risk that rigs could once again be realizing reduced dayrates while waiting for work. Both operators and rig owners suffer under those circumstances.”

Meanwhile, new regulations mandating such activities as unannounced spill drills and stronger disclosure requirements have been implemented. On 1 October, the US Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) split into two agencies. The Bureau of Safety and Environmental Enforcement (BSEE) will be responsible for inspections, enforcement and safety of offshore oil and gas operations. The Bureau of Ocean Energy Management (BOEM) will oversee energy leasing and planning on the Outer Continental Shelf (OCS), along with offshore leasing, resource evaluation, review and administration of oil and gas exploration and development plans.

Shale – shift to oil continues

The disparity of oil prices holding steady at $80 or above and low natural gas prices continues to drive the shift by North American operators from dry gas plays to reservoirs characterized by a mix of hydrocarbon gas and natural gas and liquids and/or oil. The expected drop in the gas rig count will be offset by the increase in the oil rig count, with the overall US rig count expected to increase by approximately 15% next year, then 10% to 12% annually for the next few years, Mr Adkins noted. “Canada will mirror that trend,” he added.

Ironically, the technologies developed for dry gas plays are driving the growth in liquids plays such as the Bakken and Eagle Ford, both showing a marked increase in rig counts. “In a very rational way, the industry is chasing oil prospects with the technology it developed for the Barnett, Haynesville and Woodford plays that are now seeing a downturn,” Mr Keller said. “Five years ago, roughly 80% of the rig count in the US was deployed in natural gas plays. Now, it’s much more of an even split.”

Also significant is the horizontal component of the oil rig count. “Today, more than half of the oil rig count is drilling horizontally, compared to 25% to 30% at the beginning of 2008,” he noted.

Data from Smith Bits STATS show the Eagle Ford rig count at 213 in early October, up from 134 at the end of 2010, and the Bakken count up to 191 from 157, Mr Keller noted. The same is true in the Permian Basin, where Smith Bits puts the rig count at 330, from 258 at the end of last year. “The Permian Basin has been a significant growth area for the US in 2011,” he noted. “While the play is generally considered conventional, it has some unconventional formations, and operators are using a lot of horizontal drilling and hydraulic fracturing technology to access multiple zones in one wellbore.”

John Spears

Overall, activity in the Eagle Ford, Bakken and Permian Basin will see a 20%-plus growth in 2012, said John Spears, president of Spears & Associates, who agrees that the adoption of shale gas technology has been significant. “Nearly 100% of the drilling in the Bakken and Eagle Ford plays is horizontal,” he said.

Mr Spears projects there will be 2,100 active land drilling rigs in the US in 2012, up from about 1,880 active rigs this year, with utilization around 70%, up from 64%. “The count will include 200 new rigs, most of them high-spec, advanced technology rigs for horizontal and deviated drilling,” he said. He predicts gas drilling will fall 2% to 3% next year as operators continue to migrate from dry gas to other markets.

“US operators also are seeing well costs rise 15% to 20% per year, and dayrates are up about 20% over a year ago, due in part to the growth in advanced-technology rigs,” Mr Spears noted. “The biggest increase in well costs will come from hydraulic fracturing operations, which are up 40% due to tight availability and lead times for crews, and to some degree, environmental issues.”

In Canada, the rig count will increase 8% to 10%, with the total active rig count around 460 in oily plays, he continued. Alberta, which includes the Cardium and Duvernay plays, will continue to account for two-thirds of that, followed by Saskatchewan, which includes a portion of the Bakken formation, then British Columbia.

Beyond North America

The North American shale boom has spread to several international markets, including Southeast Asia, Latin America and Europe, thanks to more favorable international natural gas prices and the export of technology. “The US has been the incubator for the world, and now we’re starting to see emerging markets link up with Western companies,” Mr Spears said. “Because of the active LNG market and international pipelines, international gas prices are up to three times higher than they are in North America. “

In Asia Pacific, Australia, with extensive shale reserves in the Canning Basin, has emerged as the most aggressive player in the shale sector, said Usman Ahmed, vice president and chief reservoir engineer, Reservoir Development Services for Baker Hughes. The country is engaged in an ambitious program to develop shale natural gas resources for export into Southeast Asian markets. Australia’s risked gas in place (GIP) is estimated at 1,381 TCF.

China and India, with risked GIP estimated at 5,000 TCF and 500 TCF respectively, hold extensive shale gas reserves; however, it is anticipated that India will develop faster than China, Mr Ahmed said. “The Indian government has sent out requests for proposal and expects to be drilling the first shale gas wells by mid-2012,” he said. The primary shale basins are located in the country’s northwest and southern regions. Baker Hughes also is working with the Indonesian government on some pilot wells.

“Shale development in China is hindered by two main problems,” Mr Ahmed noted. “The country’s highly populated areas make production more logistically challenging. Even greater difficulties are encountered because most of the shale basins in China are located in areas where there is a significant lack of water, for example, in the Tarim Basin.”

The latest region to enter the shale market is Latin America, most notably Argentina, where the risked GIP is estimated to be 2,732 TCF, and Mexico, where the risked GIP is estimated to be 2,362 TCF. Activity is also anticipated in Brazil, Chile and Bolivia. Halliburton executed the first horizontal, multi-stage hydraulic fracture shale gas completion in Argentina’s Neuquén Basin for Apache Energy in August this year.

All regions are expected to outpace Europe, where extensive shale reserves exist, but production is much slower due to more stringent regulations, Mr Ahmed noted. Poland, where the Baker Hughes rig count was nine at the end of September, is currently the major European shale producer. Risked GIP in the country is estimated at 792 TCF. “Discussions to develop shale in Poland began about three years ago, and the country is now the most active on the continent, primarily because of the government’s energy-friendly policies and willingness to eliminate red tape,” he said.

Cuadrilla Resources, an independent oil and gas company in the UK, recently announced the discovery of a 200-TCF shale gas formation in the Bowland play in northwest England. The company reportedly will submit a development plan to the government in 2012 and hopes to begin production in 2013.

But the big challenge for international shale development is equipment, Mr Ahmed continued. “Regardless of how promising the shale reservoirs are in these regions, there is a severe shortage of equipment from the service sector,” he said. “Manufacturing can’t keep pace with demand. The delivery timetable for frac trucks in North America is six to nine months but can be up to 17 months in other markets.” Lack of personnel remains an ongoing issue as well, but the equipment lag time is giving markets more time to ramp up the work force, he said.

North Sea

Exploration and potential recovery opportunities remain strong in the Norwegian sector of the North Sea. Estimates of recoverable assets for the Avaldsnes/Aldous oil and gas field, discovered on Norwegian Continental Shelf last year, have increased to 1.2 billion to 2.6 billion bbls, making it potentially the third-largest North Sea find and the largest since the mid-1980s. “We are now realizing the prospects for this field are huge,” said Andrew Vinall, technical director for UK firm Hannon Westwood. The field is situated in 115-meter water depths, with reservoir depth at less than 2,000 meters.

The discovery is boosting the overall outlook for the region, despite a reduction in drilling activity in the UK sector. “We feel the number of wells is going to hold up, especially in Norway,” Mr Vinall said. “There are more rigs under construction planned for in Norway than any other North Sea sector.” The active rig count in Norway as of early October was 32; no rigs are stacked, he said. “Utilization in northwest Europe is around 94% for jackups and 90% for semis.”

Several factors, including the surprise 12% tax increase implemented by the British government, have resulted in a major decline in exploration and appraisal (E&A) drilling in the UK sector, where the active rig count is similar to Norway, but with five rigs stacked, Mr Vinall said. Eleven rigs are on E&A wells.

While utilization has remained steady in the UK, more wells are being switched to development drilling. “Also, the UK Department of Energy and Climate Change has been slow to authorize wells this year, and several companies that had very active drilling programs in previous years have been acquired, and the new owners are not as active,” Mr Vinall said.

The region’s increasingly complicated geology, with deeper, high-pressure, high-temperature (HPHT) characteristics, means wells are taking longer to drill than in previous years, he indicated.

Malcolm Webb

Operators are optimistic the UK tax situation can be relieved through incentives, according to Malcolm Webb, chief executive of Oil & Gas UK, an industry group representing the UK offshore oil and gas industry.

“Activity is relatively flat, and the exploration well count this year is particularly low,” Mr Webb said. “We haven’t seen a great exodus, but we are seeing a lot of dismay. The big projects with robust economics are still going ahead, but other, smaller projects are stranded, and we need to overcome that problem or we could see capital being attracted to other parts of the world in preference to the UK North Sea basin.” The basin still holds an estimated 24 billion bbls of oil and gas reserves.

The tax increase has impacted some of the smaller, more technically challenging plays, such as HPHT fields and marginally productive mature reservoirs, Mr Webb noted. “A number of gas projects have been impacted because the price of gas is roughly half the price of oil here.”

The UK government in March raised the corporate tax rate on UK oil and gas from 50% to 62%, and raised the marginal rate on the oldest fields (those that began producing before 1993) up to 81%.

“The government decided that in view of the current economic climate, it should scrap the ‘green tax’ that was designed to reduce demand by making fuel more expensive at the pump,” Mr Webb said. To replace that revenue, the government then imposed higher taxes on producers.

The industry is working with the government to come up with fiscal incentives that would spark incremental production and allow projects to move forward. “If we can come to some resolution on that and gain some bankable assurance from the government that it will pay its share of decommissioning costs, that will be a very positive move for the basin and will help us improve the attractiveness for investment,” Mr Webb said.

On the UK regulatory front, the Oil Spill Prevention and Response Advisory Group (OSPRAG) submitted its final report in September, with most of the recommendations already being implemented, including introduction of a device (see p14) that can cap a free-flowing well in a matter of days, Mr Webb said.

Of concern are moves by the European Commission to take centralized regulatory control over offshore oil and gas E&P operations in Europe. “We are in discussions about that now. We believe control should be left to national regulators who are already doing a very competent job,” he said.

Asia Pacific

Natural gas is the driver for growth in the Asia Pacific region, with Australia engaged in seven LNG projects targeted for Southeast Asian markets. The country’s aggressive coal seam gas (CSG) industry is fueling the growth on the East Coast, paralleling the North American shale gas boom, NES Global’s Mr Groeneveld observed.

“The big spike in hiring activity a few years ago has continued, and we are expecting another big spike at the back end of 2012. The activity is attracting drilling and oilfield service firms from as far afield as Canada, with the major service companies also ramping up their presence,” he said.

Drilling on Australia’s Northwest Shelf and the Timor Sea has also increased, along with developmental drilling in Papua New Guinea to support recent onshore and offshore exploration activity, Mr Groeneveld said. Offshore activity for gas drilling also is gearing up in Malaysia and Thailand. NES Global has offices in Singapore, Malaysia, Vietnam, Thailand and Indonesia, where there has been marked growth on the drilling side of the business. China remains an expanding market for onshore and offshore gas production, he said.

Africa

Operators and contractors in North Africa are anticipating a return to business as the region rebounds from the Arab Spring uprisings, which effectively shut down drilling in Libya. Companies also are exploring entry into Tunisia, where 20 rigs are operating, and continue to show interest in Algeria, a major supplier of natural gas for Europe.

Exploration activity in West Africa, with a number of deepwater fields in Equatorial Guinea, Nigeria, Mozambique, Angola and Ghana, has seen steady growth in the past year, thanks in part to the redeployment of idle rigs to the region from the GOM. “The deepwater potential makes West Africa one of the exciting new frontiers, mirroring Brazil,” Argus Research’s Mr Weiss said.

One of the most prolific is the Jubilee field offshore Ghana at a water depth of 1,250 meters. The field is estimated to hold recoverable reserves of more than 600 million bbls and an upside potential of 1.8 billion bbls.

With 35 active jackups in West Africa, utilization is somewhat challenged by geopolitical issues in some countries, Mr Gerry of Raymond James noted.

However, Mr Groeneveld said West Africa has been a big growth area for NES Global. “We’re seeing 40% year-on-year growth both from the major operators as well as smaller companies. We are placing a lot of professionals into exploration and development phases and for actual project execution for various facilities. We’re also seeing companies sending more environmental professionals and seismic crews to the region for early exploratory drilling and due diligence.”

EDC’s Rig 52 works onshore Egypt, where utilization is firming up.

Situated at the crossroads of Europe, Africa and Asia, the Mediterranean is a microcosm of how geopolitical and economic events can impact oil and gas recovery. From North Africa to Central Europe, the resource-rich but politically evolving region has seen its share of political tension over the decades.

This year, the story has been the Arab Spring, with the uprisings in Egypt and Libya resulting in drilling and production disruptions. In Libya, especially, the impact of the prolonged political unrest on production was immediate and profound as drilling came to a standstill.

Looking ahead to 2012, operators and drilling contractors are anticipating a market rebound in these two pivotal North African countries. Egypt is returning to production, and the expected stabilization in Libya has raised hopes there for renewed activity. Those developments, along with increased activity in some of the region’s growing markets such as Tunisia and Central Europe, are putting a generally positive spin on the near-term drilling outlook.

“The political situation is stabilizing, and we are very optimistic going forward,” said Jens Byrialsen, managing director of Egyptian Drilling Company(EDC).

Offshore, the Mediterranean is still oversupplied with jackups. EDC’s Setty jackup mobilized out of the Mediterranean in July to Gabon, where it has a three-year contract.

“Onshore, we are seeing dayrates increasing slightly, and utilization is firming up. Egypt has seen some very significant oil and gas discoveries recently that will strengthen that market and attract more companies.

“In Libya, depending on how quickly the political situation is resolved, the potential is there, and we are hopeful we can get our rigs up and running,” Mr Byrialsen continued. EDC shut down and evacuated all three of its onshore rigs in Libya. The company also has one land rig operating in Syria, and while operations have remained steady, Mr Byrialsen is concerned about potential political unrest in that country as well.

Egypt and Libya will be key growth areas for the Mediterranean, along with some emerging smaller markets, he said.

The company has a fleet of 70 rigs, most of them operating onshore Egypt. The offshore rigs include eight jackups, five of which are EDC-owned, and three are under management contracts for Maersk Oil and the Egyptian Natural Gas Holding Company (EGAS). Six jackups are operating in Egypt; the other two are in Gabon and Qatar.

Offshore, dayrates have struggled to keep up, in part because the region remains oversupplied with jackups, Mr Byrialsen said. “Even some reasonably high-spec jackups are sitting idly in the Mediterranean. In the Gulf of Suez, dayrates have softened in recent years, and they remain soft with no indication of an increase.” At the same time, the market will likely have to phase out a significant number of older jackups, he noted.

Complicating the jackup picture is the shrinking shallow-water opportunities in Egypt. “The Egyptian part of the Mediterranean is where we expect to see a serious increase in activity,” Mr Byrialsen said. EDC has no plans to move into the deepwater sector or to add any newbuilds to the jackup fleet.

CROSCO’s Emsco 605 rig will work for Bankers Petroleum in Albania’s Patos-Marinza field.

Another company preparing for an uptick in the wake of Arab Spring is Croatia-based CROSCO, an onshore and offshore integrated drilling and well services contractor. “The return of the North African markets to full capacity will be the biggest development for us over the next 48 months,” said George Kovacic, a consultant for the company.

“Events have happened quickly on both sides of the disruption,” he said. “Within a two-week period, there was an oversupply of jackups in the region, and now, in another two-week period, we have seen that oversupply balance out. The planned, ongoing projects will be the first operations back on track.”

The company, with its subsidiary Rotary Drilling Company, has more than 50 land drilling, working and geoservices rigs, one jackup and one semisubmersible. Several are working in the Mediterranean region.

Those include three drilling rigs under contract in Libya. All three were shut down in March. CROSCO also has two owned and one managed rig in Egypt and has plans to move into Tunisia. The first of the drilling rigs in Egypt, the EMSCO 605, is already being mobilized back to work following the disruption in that country. The company also has an ongoing operation in Turkey.

The North African market is rich in oil but also exports a large amount of natural gas to Europe, Mr Kovacic said. Italy has long-term natural gas contracts with both Libya and Algeria.

CROSCO’s ZAGREB 1, a semi that has been active in the Mediterranean, will be available in early 2012 after undergoing a five-year survey and maintenance program.

“We’re feeling very positive about the future,” Mr Kovacic said. “A healthy market in the region is in everyone’s best interest. Everyone needs the revenue that will be generated.”

Adriatic and the Balkans

CROSCO has extensive operations along Adriatic coastal and Balkan nations, with ongoing drilling and well services operations in Croatia, Hungary, Bosnia-Herzegovina and Slovenia, and a jackup in Italy, where the company held, and may still hold, the record for the deepest offshore well drilled in Europe, at nearly 24,000 ft.

ZAGREB 1, a semisubmersible that has been active in the Mediterranean region, is undergoing a five-year survey and maintenance program and will be available in January 2012. CROSCO also anticipates an increase in operational activities in Croatia.

Given the complexity of the Albanian region, Bankers Petroleum is using a thermal pilot drilling program to navigate the field.

The company’s most prolific Central European operation is in Albania, where it has two rigs operating – and will be deploying a third – for Bankers Petroleum in the Patos-Marinza field, the largest onshore oilfield in continental Europe, with an estimated 7.5 billion barrels of oil in place.

The field produces primarily medium- to heavy-grade oil with an average API of 8° to 10°, said Gregor Schoenberg, senior staff drilling engineer for Bankers Petroleum. Since the company entered the Albanian market in 2004, production has gone from 600 bbl/day to 14,000 bbl/day. Production, most of it for export, has increased by approximately 75% in the past 18 months.

“We’re bringing Western technology and expertise into an area that was initially drilled and produced using very rudimentary methods” Mr Schoenberg said. “We are much more efficient because we have science on our side; we are also much more environmentally conscious.”

Vertical drilling has been done in the field since the 1920s, but production had declined to very low levels prior to Bankers’ commencement of operations in the country. The Albanian government has been very receptive to the influx of Western technology, and the ramped-up production has been good for the local economy, Mr Schoenberg added.

This Bankers Petroleum map shows the Patos-Marinza field’s current export markets. The field is the largest onshore oilfield in continental Europe, with an estimated 7.5 billion barrels of oil in place.

Bankers, using older rigs that have been modernized, now has four rigs operating in the field, drilling eight horizontal wells per month. A fifth rig, which is being supplied by CROSCO, will begin service in November and will help push the number of new horizontal producers per month to 10. Measured drilling depths are typically 2,500 meters, with 500- to 700-meter horizontal legs. The reservoirs feature multiple layers in three zones – the upper Gorani zone, middle Driza zone and Marinza – each with several sub-sections.

Thermal drilling pilot

“These are not cookie-cutter wells,” Mr Schoenberg said. “The region is geologically very complex, with layers that come and go throughout the field, making it technically challenging to navigate. One of the biggest challenges for us is avoiding the existing vertical wells that were drilled in the past.”

KCA DEUTAG’s SPEED RIG, manufactured by subsidiary Bentec, is a lightweight, high-speed compact rig designed to be efficient in desert conditions.

The company recently embarked on a thermal pilot drilling program for some of the heavy oil in place. “We believe there is huge potential in this play for heavy oil production,” Mr Schoenberg said. While the initial pilot uses a “huff and puff” process of alternating steam injection with production, future plans could include a typical steam-assisted gravity draining (SAGD) process.

This involves drilling parallel holes on legs within a few meters of each other and injecting steam into the upper leg. Gravity then pushes the steam down into the production leg to make the fluid flow more easily.

Bankers also has a fleet of 12 service rigs – with plans to bring in two more – for well cleanout, workovers and water shut-off work and is bringing in additional coiled-tubing units. The company also has retained assets in the heavy-oil Kucova field in Albania, which holds an estimated 296 million bbls of oil in place.

KCA DEUTAG, headquartered in Aberdeen, is anticipating strong growth in its onshore business in North Africa following the Arab Spring uprisings, Rodrigo Rendon, head of business development, said. The company owns and operates 16 of the 54 rigs that were working in Libya before the shutdown.

CROSCO’s IDECO 301 mobile rig is operating on the Patos-Marinza oilfield in Albania.

“We successfully and safely evacuated our employees and have kept local security to oversee our rigs in-country, which are located in the desert, somehow away from the main areas of unrest,” Mr Rendon said. “The timetable is difficult to pin down, but we anticipate a return to some kind of activity in 2012.”

Algerian market growing

The company also has three rigs active in Algeria that are working, among others, for Dublin-based Petroceltic International, and plans to double the count next year with the introduction of three additional newbuild rigs. “We see Algeria as a growing market,” Mr Rendon said. “The country has large proven oil and gas reserves and is a major supplier to Europe. We are also working at further enhancing our relationship with Sonatrach, the Algerian-owned oil and gas company.”

The increase in activity will involve deployment of the SPEED RIG, primarily 1,500 hp, manufactured by KCA DEUTAG subsidiary BENTEC. The AC-driven, lightweight, compact rig was designed to be highly efficient in desert conditions. It features a 36-hr move time between wells and a top drive with 25% higher torque than equivalent models, according to the company.

KCA DEUTAG’s Rig T-212 is operating in Algeria. The company has three rigs active in Algeria and plans to double its rig count there next year with three newbuilds.

KCA DEUTAG also is exploring the possibilities of entering the other markets and countries and regions in Africa where it currently does not have a footprint, for example, in East Africa and Tunisia. The company has appointed Stuart Anderson as business development manager for Africa. “We are offering a proposition of quality and performance to ensure that our clients are able to drill their wells safer, quicker and in a cost-effective manner,” Mr Anderson said.

The main challenges in the region include security and limited rig capacity, meaning the demand is far greater than the supply. Also of top priority is ongoing development of relationships with the national oil companies and international players, he noted.

In the offshore arena, Grup Servicii Petroliere (GSP), a subsidiary of Romania-based Upetrom Group, provides drilling and construction services in the Black Sea and Mediterranean Sea. The company owns a fleet of seven jackups that have been modernized in the last three years, Bruno Siefken, senior vice president of Upetrom Group, said.

Black Sea challenges

“Most of the drilling we do is conventional, but the Black Sea has some deepwater high-pressure, high-temperature (HPHT) wells, and we have future plans to add a semisubmersible to the fleet to move into deeper waters,” Mr Siefken continued.

GSP was the general contractor for the Engineering, Procurement, Installation and Commissioning (EPIC) project for TPAO, Turkey’s national oil and gas company. The company recently completed drilling four wells with a platform rig in the Akcakoca gas field of the Black Sea, about 150 km from Istanbul.

GSP hopes to relocate that rig to Greece to drill and work on 10 exploratory wells for Energean Oil Company in the Kavala oil and gas field, pending the resolution of that country’s financial debt crisis, Mr Siefken said. In addition, Energean is planning several exploration wells.

GSP’s Bigfoot 3 is working for the Akcakoca Project in the Black Sea.

GSP has two jackups in the Black Sea, one that is being refurbished and another that is set to begin drilling an exploration well in offshore European Turkey. GSP Saturn, another jackup that was rebuilt in 2009, has been deployed to Kaboudia field in Tunisia for Numhyd.

“We have established a base in Tunisia and from there plan to expand into other North African countries, mainly Libya, as soon as that market comes back online,” Mr Siefken said. “We feel that with the formation of new governments in Egypt and Libya, offshore drilling activity will rebound stronger than before.” Prior to the Arab Spring, GSP had one rig operating in Libya for Japanese oil company JAPEX.

GSP’s jackup design allows for easy mobility between the Black Sea and Mediterranean Sea through the Bosphorus Strait. “Our rigs have leg extensions that can be mechanically disconnected to clear the bridges in Istanbul, that are only 58 meters high,” Mr Siefken said. “We can take 15 meters off our rig height. This technology gives us the advantage of moving between the two seas in a cost-effective way, providing us a high rig occupation rate.”

ENSCO 5006, a deepwater semisubmersible with 6,000-ft capability, is working in Israel. There is an increasing demand for deepwater-moored semis in the Eastern Mediterranean, said Steven Brady, Ensco vice president, Europe and Mediterranean.

Ensco has had jackups operating in shallow water off Tunisia for some time, said Steven Brady, vice president, Europe and Mediterranean. The ENSCO 85, a 300-ft MLT 116-C jackup, is working for PA Resources, a Swedish oil and gas operator. Through its acquisition of Pride International earlier this year, Ensco also has a deepwater semisubmersible working for Noble Energy offshore Israel.

“Some world-class gas reserves have been found in the region, and there is optimism that this trend will bring significant drilling opportunities,” Mr Brady said. Ensco has not been significantly impacted by the events of the Arab Spring. “We were careful to quickly institute safety measures when some of the uprisings began several months to protect our people and assets,” he added.

“But for some of the uprisings and the Greek debt crisis, we might have had more demand for offshore rigs in Libya and also Greece, where we have contracted some of our jackups for Aegean Energy; however, that is hard to quantify,” he continued. “As the situation in Libya and the broader region stabilizes, we hope to see more opportunities with customers.”

Deep and HPHT environments are among the technical challenges in the region. “There are some unique drilling challenges in the Nile Delta area where Egyptian operators have some deep, high-pressure gas work requiring HPHT-capable and experienced rigs with two million-lb hookload capacity,” Mr Brady said. “Also, we are seeing increasing demand for a deepwater-moored semi with 6,000-ft capability such as the ENSCO 5006 in the Eastern Mediterranean, in offshore Egypt, Israel and Cyprus.”

SPEED RIG is a trademark of KCA DEUTAG/Bentec.

Click here to view the embedded video.

Click here to view the embedded video.

As the 15 November deadline for SEMS compliance on the US OCS approaches, Hercules Offshore will have about 20 rigs operating in the Gulf of Mexico, including the Hercules 173 jackup. Under the OOC SEMS Taskforce, leaders from all facets of the industry contributed to a SEMS toolkit to assist companies in complying.

HOUSTON - Facing an impending deadline, companies from all corners of the industry capitalized on an unprecedented opportunity to help themselves reach a shared goal: to facilitate the safest and most environmentally sound workplace while mitigating the potential dangers inherent to drilling operations.

The US Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) – recently replaced by the Bureau of Safety and Environmental Enforcement (BSEE) – announced in October 2010 mandatory practices required to operate on the US Outer Continental Shelf (OCS). The 15 November 2011 deadline gave the industry little more than a year to complete what initially seemed like an insurmountable task: comply with BOEMRE’s call to implement a mandatory safety and environmental management system (SEMS), a program that operators are required to develop and maintain with the cooperation of contractors and other third-party service providers.

Although the use of a safety and environmental management system is not a new idea, the regulatory mandate sent waves through the industry; the considerable task was going to require more than a revision in protocols. “SEMS had its first place in the Gulf of Mexico as API RP 75 (SEMP) in the early ’90s. It was a voluntary program at that time,” Bill Walker, HSSE adviser at Cobalt International Energy, said. “The concept is not radical or new.”

Rowan Companies’ crewmen review paperwork before beginning a job on the EXL I high-specification jackup, which is drilling for McMoRan in the Gulf of Mexico. Among changes to existing elements and additional requirements, SEMS II proposes a formal approval of all job safety analyses.

With the support of the Offshore Operators Committee (OOC), the Center for Offshore Safety (COS) and IADC, in conjunction with leaders from oil and gas companies, drilling contractors and other contractor companies, the industry united to create a thoroughly SEMS-compliant environment. A collaborative effort was forged to create a SEMS toolkit to advance E&P activities on the OCS. “With the lessons that we have learned from the offshore disasters, we will continue to make a difference in safety,” Jack Isbell, safety specialist at Rowan Companies, said. He participated in the SEMS Taskforce Competence Subcommittee and in developing the SEMS Compliance Readiness Worksheet. “The SEMS is an effective method for making that difference. It’s a more systematic way to work safely and protect the environment, and when you have a lot of very complex systems working, that systematic method is necessary.”

The implementation process cultivated not only the collaboration of various departments within each company but also among competitors. An expansive task force emerged from a modest meeting of seven people from different companies in February, but without a sponsor. At a second meeting in March, the OOC stepped up to sponsor the group, which then facilitated a number of meetings and the formation of subcommittees addressing different aspects of SEMS implementation. By June, about 150 people from all facets of the industry were participating on the OOC SEMS Taskforce, which went on to create the SEMS Toolkit.

The introduction of SEMS regulations to the US OCS is a process that is still unfolding. Implementation of a SEMS program was just one major variable that operators and contractors had to overcome; moreover, the industry is subject to government interpretation and revisions of the regulation, which could call for further cooperation within a highly competitive industry.

On top of that, the recently proposed SEMS II, which modifies and adds to the current regulation, will create its own challenges. Among other things, the new proposal calls for: mandatory third-party audits, providing all workers with stop work authority, documenting employee participation in SEMS development, formal approval of all job safety analyses, designation of an individual having “ultimate work authority” and guidelines to report of unsafe working conditions. The comment period on the proposed rule closes 14 November, and a final rule isn’t expected until spring 2012 or later.

What is SEMS?

In 1994, the then-Minerals Management Service (MMS) recognized API RP 75 to fulfill the principles of a safety and environmental management program. Oil and gas companies operating on the OCS were encouraged to voluntarily adopt the recommended practice, which was intended to reduce the risk and occurrence of accidents and pollution on offshore oil and gas drilling and production facilities. Regulators identified four elements of the original 12 elements of RP 75 that were necessary in an effective program, based on incident investigations and performance reviews with operators.

The SEMS final rule includes API RP 75’s 12 sections and an additional section to address the responsibilities of companies’ general management. The rule applies to current and future OCS operations and facilities under the jurisdiction of the US Bureau of Safety and Environmental Enforcement.

In 2009, the then-MMS proposed a rule to mandate that leaseholder/operator management systems include those four elements: hazard analysis, management of change, operating procedures and mechanical integrity. “Prior to 2010, BOEMRE looked at regulating four of the now-13 requirements,” said IADC industry compliance specialist Julia Swindle, who has been participating in the development of the SEMS Toolkit under the OOC SEMS Taskforce. “Then Macondo happened, and now they’re including all 13,” she said. An additional section was added to the original 12 elements to address the responsibilities of companies’ general management.

The October 2010 SEMS final rule, which includes API RP 75’s 12 sections, applies to current and future OCS operations and facilities under BSEE’s jurisdiction, including drilling, production, construction, well workover, well completion and well servicing. BSEE and the Bureau of Ocean Energy Management (BOEM) replaced BOEMRE on 1 October.

Operators are responsible for having a SEMS in place, and contractors need to be prepared to respond. “Although contractors are not required to have a SEMS for their own operations, their cooperation is necessary for operators to be in compliance; therefore, it is in contractors’ best interest to anticipate operators’ needs and proactively cooperate with operators,” Dr Brenda Kelly, IADC senior director of accreditation and certification, explained. Dr Kelly leads the SEMS Competence Subcommittee under the OOC SEMS Taskforce. Under the final rule, each operator needs a written agreement with each contractor they are working with to document safety and environmental policies and practices.

“Part of the challenge is that although operators must comply with the BSEE regulations, they can interpret how to satisfy them. A contractor must be prepared to follow the operator’s SEMS program,” Dr Kelly said. One benefit of SEMS is that all companies will be held to the same minimum standard, Ms Swindle added. “It is a system that will hold all lessee/operators and, by default, contractors on the OCS to the same requirements and level the playing field,” Ms Swindle said.

IADC HSE Case Guidelines

Recognizing that many members had based their SEMS on the management system guidance provided in the IADC HSE Case Guidelines for MODUs, IADC performed a gap analysis of the guidelines against API RP 75 and the BOEMRE Final Rule.

The results of the gap analysis were made available to members in early 2011, according to Alan Spackman, IADC vice president – offshore technical and regulatory affairs. “The analysis found only minor gaps,” Mr Spackman said, “and these were formally closed with the adoption of amendments to the HSE Case Guidelines for MODUs in October 2011.

Rowan Companies’ Ralph Coffman jackup is contracted to work for McMoRan in the Gulf of Mexico. For SEMS compliance, it is in contractors’ best interest to cooperate with operators, who are responsible for meeting the requirements of the mandatory regulation. In preparation to meet operators’ requirements of contractors, Rowan has conducted on-site training on rigs, and training courses are being revised to take SEMS into account.

Implementation

Some contractors initially reacted to BOEMRE’s announcement in October 2010 with a wait-and-see approach. However, some also found that their existing safety and environmental management programs paralleled the new regulations. “Having had a SEMS for a number of years and, at the time, being in the process of revising it to meet stricter safety standards, I felt that we were in a good place,” Mr Isbell said.

Jennifer May, director corporate HSE and management system for Hercules Offshore, expressed a similar sentiment and noted that Hercules has had a safety and environmental management system in place since 2007. “We did a gap analysis, and we were very fortunate to find we didn’t have very many gaps,” Ms May, who is a member of the SEMS Taskforce Contractor Guidance Subcommittee, said. “What it has brought to the surface is the execution piece. On paper, people have great systems, great policies, but it’s getting those policies into the hands of the rig crews and getting them to embrace it and use it. That’s the struggle.”

Translating a policy into everyday practice entailed significant time and resources over the past year. “Our engineering department has had a team working on SEMS. Our operations department has a compliance team working on SEMS. HR, training, all the departments that make this company operate have had dedicated personnel on the SEMS implementation,” Ms May said. While the interpretation of the regulation began to take shape through discussions and drafted policies, contractors and operators continued the implementation process through practice and execution in the form of training sessions. “We’ve spent a lot of face time with the rig crews,” she added.

Rowan hosted two SEMS-specific training sessions at Houston’s Hotel Derek in October, specifically for rig supervisors, offshore installation managers, engineers and HSE technicians. “The management system can be that transfer of experience and understanding that can be done off-site. Are we going to be able to slip and cut drill line at a hotel? Not quite, but we can ensure that they understand how the new rule and its intent will make their rig a safer place,” Mr Isbell said. “They will be able to take the information and apply that logic and understanding to the individual jobs and to the task of slip and cut drill lines.”

Rowan also conducted on-site training on rigs, and training courses for new-hires are being revised to take SEMS into account.

Mr Isbell pointed to the necessity of supervisors’ leadership in building support for and compliance with SEMS. “As great as a training or class may be, the key to the proper use of the management system will be in our supervisors and their continued support of the SEMS,” he said.

A floorman works on Rowan’s EXL III jackup, which also is drilling for McMoRan in the GOM. SEMS II proposes to provide workers with stop work authority and for companies to develop guidelines for workers to report unsafe working conditions. The comment period for SEMS II ends 14 November.

Operators’ involvement

While contractors have a sense of the general requirements that are necessary for compliance, operators’ requirements can vary. Fortunately, Rowan has encountered some common ground among its customers. “(Operators) have been fairly uniform with the requirements and expectations. I think that we have the work of the API, the OOC and IADC to thank for making sure that, of 10 different operators, there are not 10 different sets of expectations,” Mr Isbell said.

Communication also has been a constant key to success in SEMS implementation. “The relationship between the operator, the service contractor and the drilling contractor requires a lot of communication, and SEMS just underscores that and brought it to the surface in the form of a regulation,” Mr Walker noted.

Although the SEMS Taskforce initiative began with operators, they realized that compliance would require cooperation from their contractors. “When the group got together, it was a group of operators,” Ms Swindle said, “but they realized that this was a bigger challenge that would require the cooperation of the contract companies that they work with and that, they being responsible (to meet the requirements), needed to help provide guidance for the drilling contractors.”

The SEMS Taskforce brought together leaders from supermajors and other independent operators: Anadarko Petroleum, BHP Billiton, Chevron, Cobalt and ExxonMobil, as well as from the contractor community, such as Ensco, Hercules, Noble Corp, Rowan and Transocean. Baker Hughes also contributed to the toolkit.

Mr Walker, who chaired the Documents and Data Subcommittee, noted the benefit of the joint effort. “The more conformity we can bring to the process, the less work and expenses will be associated with the contractor providing information,” he said. “We worked on safety questionnaires, letters of agreement, and we’re working on other areas where we can make this a more efficient transfer of information or communication between the operator and drilling contractor.”

Most of the toolkit is geared to aid drilling contractors. “The SEMS toolkit was developed as a cooperative effort with over 50 different companies from all different sectors of the oil and gas industry,” Ms Swindle, who helped compose the compliance readiness worksheet, said. “A lot of really smart people contributed to that effort.”

Subcommittees within the taskforce created worksheets, templates and guides ranging from SEMS audit protocol and training matrices to documentation worksheets and agreement letter templates. The extensive toolkit, which also includes PowerPoint presentations and a list of definitions with examples, is available for free on IADC’s website at www.iadc.org.

The operators’ involvement in the taskforce has created cohesiveness in the industrywide effort and sets a foundation for continual improvement. “It is a continual implementation and audit process that they’re engaged in,” Mr Isbell said. “They are being very cooperative in saying ‘let’s make sure we have all the requirements met, and how can we go above and beyond the minimal requirements and exceed expectations?’ “

In conjunction with drilling contractors’ SEMS training, Cobalt is also implementing a program for anyone – employees, contractors or visitors – to complete a SEMS orientation conducted by Cobalt rig personnel and HSE advisers. The goal is to make everyone “aware of how SEMS is impacting our day-to-day activities on the rig,” Mr Walker said.

Contractors might consider SEMS in the future construction of rigs. Rowan’s Joe Douglas jackup was under construction as the company was in the process of implementing SEMS. The contractor found it necessary to request certain inspections or certifications earlier to meet requirements.

Effects/outlook of SEMS

Embarking on a SEMS-compliant industry, the path remains bumpy for all parties involved. Although many contractors and operators began compliance efforts more than a year ago, “nobody can guarantee they will be in compliance” until BSEE performs an audit, Ms Swindle stated. “BOEMRE made it clear that they want to use auditors that do not have any conflicts of interest, but it seems the only way to do that may be to go outside of the industry. It’s going to be a huge learning curve for everybody.”

Mr Walker agreed that challenges might surface from BSEE’s interpretation of the SEMS language. “Our approach is to do our due diligence to implement, to the best of our abilities, all of SEMS, and then as we receive guidance, we will make accommodations for any changes that may be needed,” he said.

Some contractors remain optimistic in overcoming obstacles and in maintaining a joint effort with operators. “We will take any cases, where shortcomings have been identified, as opportunities to grow, revise, implement and evaluate changes to improve our management system,” Mr Isbell said. “There are going to be some growing pains.”

Because many contractors and operators who operate on the OCS also operate in other drilling markets, the lessons learned from mandatory SEMS implementation in the US are making their way around the world. “Our management system that’s compliant to SEMS is already corporation-wide,” Ms May said, putting SEMS into play onshore the US and on Hercules’ rigs in the Middle East, Africa and Southeast Asia. “For consistency sake, it’s better to have one management system that meets industry best practice.” Rowan also uses SEMS through all operations, including on rigs in the Middle East, Southeast Asia and the North Sea.

Cobalt’s SEMS-compliant HSE management system is also global. “The only caveat is if we are working in a part of the world where, for whatever reasons, regulatory or logistically, there’s some part of our HSE management system that cannot be directly applied,” Mr Walker said. “We might have to make some adjustments to it, but we will not in any case work in a downgraded situation.”

For companies based outside the US or not operating on the US OCS, some industry leaders foresee SEMS or similar programs becoming a reality for them as well. “I am fairly confident that the companies that operate in those regions will have adopted either the requirements that you see here in the Gulf of Mexico or some very similar,” Mr Isbell said. “It’s been said that ‘as goes the Gulf of Mexico, so goes the rest of the industry.’ A lot of that is because the Gulf of Mexico is an excellent training ground and excellent place for development of leadership.”

Future construction of rigs might also take into consideration the SEMS-compliant environments in which they will enter. Rowan’s construction of the Joe Douglas jackup was under way as the company was in the process of implementing SEMS. Given the company’s initial system that was largely already compliant with SEMS, the jackup did not face additional hurdles, but the contractor did move up some parts of the SEMS process.

“We needed to request certain inspections or certifications sooner, whereas we might have been able to have waited until ‘X’ number of months before the rig went to work to request a certain inspection or certification,” Mr Isbell said. “It helped us to be more prepared, and be more prepared earlier.”

The driving forces behind SEMS implementation can be traced back to the priorities of the program: human life and the environment. While it is not possible to quantify the value of the program, SEMS is intended to promote a high-quality workplace to avoid accidents that could result in injuries to personnel and environmental consequences. “If (SEMS) is utilized, it can’t help but have a positive difference on the rig, and you will see it. It’s a trickle-down effect,” Ms May said. “You’ll see efficiencies such as higher productivity, less downtime, overall quality, less property damage and fewer incidents because people are using it.”

Conclusion

An event of alarming magnitude might instigate the establishment of preventive measures, but the utilization of those practices is just as important. “The most significant regulatory change in our industry has been from Piper Alpha and now Macondo,” Ms May said. “However, legislation in and of itself is not the complete answer. We must consistently and persistently do the things that we say we are going to do as provided in a management system to ensure incident-free operations.”

Legislation and, more importantly, the industry’s united front are transforming the drilling environment into a safer one. “I think the participation that we had (in the SEMS Taskforce) was excellent and really precedent-setting for this industry. This is a very competitive industry, and a lot of companies are careful to maintain what they consider to be their competitive edge,” Ms Swindle said.

The deadline to implement SEMS might come and go without much fanfare, but the date marks the beginning of a new era for the industry. “15 November will be the first day of a new era in safety and environmental management in the Gulf of Mexico and other places under BOEM jurisdiction,” Mr Isbell said. “It’s a new era in safety and protection of the environment.”

Rowan Companies’ Jack Isbell and IADC’s Brenda Kelly and Julia Swindle address industry challenges and initiatives related to the SEMS regulations in exclusive video interviews with DC.

Brian Petty, executive vice president – government affairs

Jones act legislation

IADC is coordinating a lobbying strategy in response to US House legislation introduced in September 2011 at the behest of the Jones Act Coalition. The legislation, HR 2946, would require any foreign-flag MODU intending to operate under US jurisdiction to be re-flagged as US. This could cause extreme difficulties for many drilling contractors due to financing constraints and the need to transfer effective control of the asset to an owner that can meet the required citizenship criteria.

IADC is supported by Shell and Maersk in opposing this legislation. Similar legislation was introduced in the last Congress and failed. It’s expected that this bill will also fail.

Discharge Reform Act

IADC was among 14 organizations that wrote to US House members expressing strong support for the Commercial Vessel Discharges Reform Act of 2011, which will provide a uniform federal framework for the regulation of ballast water and other vessel discharges.

Legislation to establish a consistent, practical and science-based national program for the management of vessel discharges is urgently needed, the groups stated. “The current statutory system is a confusing, duplicative and inconsistent patchwork in which two federal agencies (the Coast Guard and EPA) and more than two dozen states regulate the same vessel discharges in overlapping and sometimes contradictory ways,” according to the letter.

The absence of a clear and effective federal framework constrains the movement of essential maritime commerce, jeopardizes American jobs, multiplies regulatory burdens on businesses and workers, puts the environment at risk and forces taxpayers to pay for duplicative and contradictory government programs.

The groups believe the reform act will fix the situation and urged congressional leaders to take action. The letters were addressed to the chairmen and ranking members of the committees on Transportation and Infrastructure; on Coast Guard and Maritime Transportation; and on Water Resources and Environment.

The proposed legislation (HR 2840) was approved by the Transportation and Infrastructure Committee on 13 October, with the recommendation that it be considered by the House as a whole.

Indonesia cabotage law

An Indonesian newspaper reported in early 2011 that the government and lawmakers in that country agreed to exclude vessels in the oil and gas industry from its cabotage law.

According to the report, Yasti Soepredjo, chairman of the House of Representatives Commission V, said that the Transportation Ministry must issue a special regulation to accommodate specific activities of foreign vessels that serve the offshore oil and gas sector.

Foreign-flagged vessels that would be excluded from the cabotage rules are those engaged in seismic, drilling and offshore construction activity in oil and gas. Indonesian shipowners do not engage in these activities because of the high investment costs involved and short contracts, said Johnson W Sutjipto, chairman of the Indonesian National Shipowners Association. “We are not against them operating in Indonesia. We need them,” he was quoted as saying.

Indonesia enacted its cabotage law in 2005, but industry has been trying for years to convince the government that enforcement would bring dire results. The commission was told, for example, that Indonesia could lose $7 billion in oil and gas production if enforcement went ahead. Indonesian Petroleum Association vice president Sammy Hamzah has said the law could cost the country 200 million bbl of oil and $13 billion in investment.

EU energy policy

The International Association of Oil & Gas Producers (OGP) urged the European Commission to take caution in its transition to a low-carbon energy mix, saying the EU can’t afford to be out of pace with the economic development of the rest of the world. The comments were included in a letter sent in late April to the EU Task Force on Resource Efficiency. The letter was signed by Barry King, chairman of the OGP EU Committee; Mr Petty serves on the committee.

The letter also recommended allowing for swift appraisal of the EU’s shale gas potential and emphasized that “affordability, flexibility and ensuring resilient energy supplies should be the primary policy goals of the Resource Efficiency effort.”

UK shale gas report

The UK House of Commons’ Energy and Climate Change Committee put its support behind shale gas and hydraulic fracturing in a 2011 report looking at the impact shale gas could have on water supplies, energy securities and greenhouse gas emissions.

According to the report, the inquiry found no evidence that hydraulic fracturing poses a direct risk to underground water aquifers as long as the well is constructed properly. The committee concluded that a moratorium on fracking in the UK is not justified or necessary at present.

UK Parliament member and committee chairman Tim Yeo was quoted as saying, “There has been a lot of hot air recently about the dangers of shale gas drilling, but our inquiry found no evidence to support the main concern – that UK water supplies would be put at risk. There appears to be nothing inherently dangerous about the process of fracking itself, and as long as the integrity of the well is maintained, shale-gas extraction should be safe.”

The report also concluded that shale-gas extraction could reduce the UK’s dependence on imported gas. The British Geological Survey estimates that the UK’s onshore shale gas resources could be as large as 150 billion cu meters, equivalent to roughly 1.5 years of total UK gas consumption. The committee also called on the government to encourage the development of the offshore shale gas industry in the UK, believing reserves there could “dwarf” onshore supplies.

US-India treaty

IADC and 16 other trade and business groups jointly sent a letter in July 2011 to the US government urging progress on US-India bilateral investment treaty (BIT) negotiations “so that US companies and their workers will not lose out on important economic opportunities and protections in the highly important and fast-growing Indian market.” The letter was sent to Secretary of State Hillary Clinton and US Trade Representative Ron Kirk ahead of the US-India Strategic Dialogue and Trade Policy Forum.

Negotiating a strong and high-standard BIT with India will produce substantial increases in productive investment by US companies, US exports and other new market opportunities for the US, the letter stated. Moreover, BITs are a vital tool to protect important US investments overseas that promote US exports and economic growth.

A BIT with India would provide strong protection for US property and help open a major market for key US goods and services. It also would help level the playing field for US companies and their workers. India already has 48 BITs in force, including with England, France, Germany, South Korea and Russia.

The lack of a US BIT undermines US companies’ opportunities to compete on an equal basis against tough competitors from around the world.

Unconventionals task force

John Beswick, PR Marriott Drilling, continues to represent IADC on OGP’s Gas Communications Task Force in Brussels. The group’s goal is to identify questions raised by those opposing the exploration of unconventional gases, such as coalbed methane and shale gas, to defend industry from adverse publicity and promote the benefits of E&P development.

Shale gas is the principal target of industry opponents, and threats are serious enough that it could jeopardize the continuation of unconventional gas development in Europe, with repercussions elsewhere if opponents succeed. The main issues are safety of drinking water in the area; chemicals used in fracturing operations; induced seismicity; water use and disposal in fracturing operations; land rights; economic impact on the area (employment); environmental issues such as noise, contamination and dust disturbance; and shale-gas emissions.

In France, the ecology minister put in place a moratorium on shale gas E&P in February 2011 pending a study commissioned by the French government. A Dutch court has ordered the suspension of the Bergermeer gas storage project, the largest in Europe, citing objections by environmentalists and local residents’ fears of tremors from gas injection into the depleted field. Shale-gas development in the Netherlands is also planned, and the impact of this ruling on shale gas is uncertain.

In the UK, Cuadrilla Resources suspended fracturing operations in a shale-gas license until a report is published on low levels of induced seismicity. There is also increasing opposition reported in Germany. All European national governments and regulators are watching the various developments and decisions by other governments that may affect the way they approach the future licensing of unconventional gas development.

This level of opposition and threat has prompted a major effort by OGP, operators and other interested organizations to present a strong rebuttal. OGP has developed a presentation summarizing the reality of the issues at hand.

EU/UK Working Time Directive

Following on last year’s victory when the Scottish appeals court sided with the industry on the Working Time Directive, a hearing of the offshore unions’ appeal in the UK Supreme Court took place on 26-27 October 2011. The 2010 unanimous court decision was a clear vindication for the offshore E&P industry, which argued that the equal time rota for its employees was lawful. Industry’s UK lawyers remain very optimistic that the employers group, including IADC, will prevail.

A decision by the UK Supreme Court is expected at the end of this year. It remains to be seen whether the unions would then take a further appeal to the European Court of Justice.

Mike Killalea, group vice president/publisher

At a time when the industry is rethinking and, some would say, revolutionizing its approach to drilling, the IADC Advanced Rig Technology (ART) Committee is working to move well-construction technology to the next level. Under the leadership of chairman David Reid, National Oilwell Varco (NOV), the committee comprises three subcommittees: Drilling Control Systems (DCS), led by Terry Loftis, Transocean; Reliability and Guidelines (R&G), Robert Urbanowski, Precision Drilling Oilfield Services Corp; and Future Technology (FT), Dustin Torkay, Archer.

The DCS Subcommittee is working in tandem with the SPE Drilling Systems Automation Technical Section (DSATS) to identify the best method to interface downhole tools with surface systems. In conjunction with DSATS, DCS plans to propose and publish an industry guideline for integrated applications.

To pursue this objective, DCS established four work groups:

• Transfer of Tool Ownership (led by Craig Brooks, NOV): to determine prioritization in changing or shutting down tools, when, for example, multiple pieces of machinery are under automated control. In addition, the group will establish fail-safe modes and other issues;

• User Interface Standardization (Clinton Chapman, Schlumberger): to determine whether UI standardization can be integrated into a driller’s console, if desired;

• Well State/Phase Definition (Fred Florence, NOV): to help define states or phases of the drilling operation. DCS aims to define where downhole communication and integration brings value for specific phases of well construction;

• Cascade Effect of Control (Cesar Peña, Tesco): to measure the impact of cascading intelligent controls systems, such as EDS or Autodriller with DCD.

DCS is seeking volunteers for each of the work groups. Contact Mr Killalea at mike.killalea@iadc.org.

R&G continues to build on its past efforts, including the Technology Value Guide (TVG), which provides definitions for 35 pieces of advanced rig equipment, from top drives and multi-activity to AC drives and automatic drillers. The definitions were developed by members of the R&G Subcommittee.

The TVG also features illustrations of each piece of equipment and links to training providers. The TVG is available through the Additional Resources link on the ART Committee website.

Finally, the FT Subcommittee looks to the past to learn for the future. FT holds workshops and prepares industry papers across a range of topics. Most recently, the FT Subcommittee held two well-attended workshops, the first on stick-slip mitigation, which resulted in a paper presented at the 2011 SPE/IADC Drilling Conference in Amsterdam. The paper was published in the March/April 2011 edition of Drilling Contractor and is available online at www.drilling
contractor.org/stick-slip-workshop-highlights-mitigation-technologies-needs-8781.

Subsequently, FT organized a workshop on shale-gas drilling. Results of this workshop will be presented at the 2012 IADC/SPE Drilling Conference in San Diego, Calif.

A major workshop finding is that technology is expected to overcome most if not all challenges associated with shale-gas development, lowering development costs and minimizing operational footprint. Several operators, the paper will reveal, have initiated research programs, either internally or in collaboration with third parties, to develop more effective stimulation technology, enhanced reservoir “sweet spotting” techniques, or low-cost drilling technology.

Several universities have also initiated new research related to shale-gas development. The paper will refer to ongoing developments in this respect.

Condition monitoring workshop

FT’s next workshop will focus on rig condition monitoring and is scheduled for 19 January 2012 at NOV’s facility at 7909 Parkwood Circle in Houston. Watch the ART Committee website for details.

ART, European style

A major ART goal is to offer drilling professionals outside North America the opportunity to participate. While IADC’s advanced telecommunications systems make it convenient for members to participate in meetings via web and phone, differences in time zones sometimes discourage remote attendance.

Consequently, the IADC ART Committee will hold a half-day meeting and workshop on 12 June in Barcelona, just before IADC World Drilling, also convening in Barcelona. The event will feature a combination of presentations and discussions. Watch the ART Committee website for more information.

Steve Kropla, group vice president – operations & accreditation

Understandably, for the past 18 months, much of the resources of IADC’s Operations & Accreditation Group have been focused on the plethora of activities that has sprung up worldwide in response to the Montara and Macondo incidents (see Page 104). The investigations, inquiries, regulatory initiatives and industry responses have taxed IADC’s resources like never before. Nevertheless, while Macondo may have changed our world, it didn’t end it, nor stop the broad spectrum of activities that IADC had been engaged in previously.

The industry has continued to grow at a breakneck pace, with the US rig count returning to near-record recent levels, increased focus on shale oil, shale gas and the effect of the looming “big crew change” and more than 140 new offshore rigs either planned, on order or under construction.

IADC’s Operations & Accreditation Group has responded to these demands in part through increased staff to handle environmental concerns over hydraulic fracturing and OSHA regulations dealt with by our Land Division, and by creating a position of industry compliance specialist to help contractors with additional regulations being promulgated that would affect both land and offshore operations. We have also added an industry affairs consultant to provide technical support in Australasia and to supplement IADC’s existing Asia Operations. We also have continued to work closely with other industry groups, from API to OGP and the Offshore Operators Committee to respond to industry needs.

As can be seen in the detailed individual staff summaries that follow, each operating unit within the group – the Offshore Division, Land Division, Regional Operations and the Accreditation & Certification Department (ACD) – have all been engaged in a multitude of efforts both on behalf of IADC and in support of our various standing committees.

IADC’s Offshore Division remains involved in a number of environmental, regulatory and technical matters affecting our offshore contractor members, as well as renewed interest by regulators worldwide in the IADC HSE Case Guidelines for Mobile Offshore Drilling Units. The division has also liaised regularly with members and our accreditation unit to help contractors comply with the new SEMS requirements.

To meet increased demand for its services, ACD has undergone a reorganization to allocate resources specifically to program development, customer service, and quality assurance and quality control (QA/QC). Including the responsibility for training provider audits, QA/QC will be facilitated through a contract giving ACD access to DNV’s global network of professional, independent auditors.

IADC’s Regional Operations continue to focus on the sharing of industry information through venues such the European Operations Forum, Middle East Operations Forum and Asia Operations Forum. This year, IADC also introduced its Land Operations Forum in the US.

Our standing technical committees also remain robust. Anticipating the swell of new employees required by the newbuilds coming in, the Training Committee has renewed its focus on defining critical employee competencies and methods for contractors to assess them.

Responding to industry interest, the Underbalanced Operations and Managed Pressure Drilling Committee created a new subcommittee on dual-gradient drilling. The Well Control Committee has initiated a comprehensive cycle of curriculum revisions and updates. At the same time, the committee is pondering possible requirements for annual retraining.

The HSE Committee, in addition to ongoing maintenance of IADC’s Incident Statistics Program, has focused on additional metrics and exploring how companies can enhance their HSE culture. The Environmental Subcommittee has focused on issues of sustainability and its EPAP benchmarking study.

This brief introduction barely scratches the surface of the breadth of IADC activities and initiatives, which are reported in detail in the sections that follow.

Alan Spackman, vice president – offshore technical and regulatory affairs

As in 2010, a significant portion of 2011 was spent on Macondo-related efforts. For activities related to Macondo, please see page 108. However, numerous other initiatives relating to offshore regulatory and technical issues are ongoing. Below is a summary.

MODU Code

The government of Brazil proposed that IMO amend the 2009 MODU Code to codify practices for alternatives to traditional lifeboat drills for MODUs. Arrangements similar to those proposed by Brazil have been accepted by several flag-State administrations; adoption of Brazil’s proposed amendments would validate and facilitate adoption of these alternative arrangements. Brazil’s proposal was approved as an addition to the IMO’s work plan by the Maritime Safety Committee at its May 2011 meeting and assigned to the Ship Design and Equipment Subcommittee for the development of regulatory text.

The Republic of the Marshall Islands has submitted its Deepwater Horizon Marine Casualty Investigation Report to the IMO. The report, along with a report from the US Coast Guard (USCG), are expected to be reviewed by the Flag State Implementation Subcommittee, which is likely to recommend additional amendments to the MODU Code.

NOSAC

The National Offshore Safety Advisory Committee (NOSAC) was established to provide advice to the Commandant of the Coast Guard in matters relating to safety in offshore industries. Its members serve two-year terms and do so without remuneration, so the costs associated with the committee are minimal.

In late 2010, the US Department of Homeland Security (DHS) allowed the committee’s charter to lapse. It was ultimately renewed in February 2011. As of January 2011, all appointed members of the committee had completed their term of appointment and no new appointments have been made by DHS from recommendations made over a period of several years by the Coast Guard. Given the delays, it is questionable if those candidates whose names were put forward by the Coast Guard for appointment have continued interest in serving.

Discharge system – EPA

The USCG and Environmental Protection Agency (EPA) established a Memorandum of Understanding (MOU) regarding implementation and enforcement of the National Pollutant Discharge Elimination System Vessel General Permit (VGP), which applies to domestic and foreign vessels, including MODUs, within the three-mile territorial sea of the US and addresses 26 discharges that are incidental to the normal operation of a commercial vessel.

Per this MOU, the EPA is responsible for interpretations of the VGP, including the terms used; whereas the Coast Guard will incorporate the verification of compliance with the VGP into its existing inspection protocols and procedures, which verify vessel compliance with safety, security and pollution prevention regulations.

ISO

ISO issued a draft international standard (DIS) for the second edition of ISO 19901-7: Stationkeeping Systems for Floating Offshore Structures and Mobile Offshore Units. It was approved on 10 August 2011 with no dissenting votes and after resolution of technical comments will progress to the final draft international standard (FDIS) stage.

It was originally intended that the amendments would be issued as a “minor revision”; however, due to the size of the amendment, the ISO Secretariat demanded that the amendments be progressed as a DIS. The proposed amendments are:

• Incorporate informative text from API RP 2SK 3rd Ed. on anchor design and analysis and mitigation of vortex-induced motions;

• Update guidance on synthetic rope mooring to be consistent with the recent amendment to API RP 2SM;

• Correct text in section 7.4.4, wind actions, and section 8.4.3, riser considerations;

• Standardize use of the terminology “most probable maximum”; and

• Include an updated Norwegian annex and new Canadian annexes.

The subcommittee hopes to bypass the FDIS stage by obtaining 100% approval at the DIS ballot and directly publish a new edition. The subcommittee has asked its members to focus on editorial corrections to the changes as if this were an FDIS and agreed that any technical comments that do not relate directly to the proposed changes can be deferred to the next revision.

Separately, the ISO standard on Site-specific assessment of mobile offshore units – part 1: Jackups (ISO 19905-1) was approved with 19 members voting for the standard and three abstentions. The same ballot approved the standard as an EN standard for use in Europe.

IMO – liability for offshore oil and gas spills

At its April 2011 meeting, the IMO Legal Committee urged that an informal group, led by Indonesia, continue to examine issues related to the establishment of a new liability and compensation for oil pollution damage resulting from offshore oil exploration and exploitation.

During committee discussion, one delegation forcefully objected to the IMO taking on this subject while two others expressed reservations. Numerous other delegations expressed support for the Indonesian proposal. IADC and OGP are participating in this group.

The committee also recommended that the IMO’s Council and the Assembly adopt an amendment to the organization’s strategic direction to allow this matter to be considered formally and for the development of a new instrument to be added to the committee’s work program. The council subsequently declined to do so but suggested that the committee further examine the issues.

Indonesia hosted an international conference in Bali on 21-23 September 2011 to further discuss the issue and gain support for its initiative. IADC was represented at this meeting by Derek Morrow. Also attending were OGP and representatives of companies with operations in Southeast Asia. These included PTTEP, Petronas and Repsol. National representatives from Australia, Egypt, Indonesia, Malaysia, Norway, the Philippines, Singapore and the US attended. IMO’s secretariat, however, was absent.

The IMO’s Legal Committee may once again examine this issue at its April 2012 meeting.

Similar initiatives, at a regional level, have been proposed in Europe and for the Arctic.

IMO – lifeboat systems

The IMO adopted new regulations that will require the evaluation of virtually all lifeboat release and retrieval systems. In adopting a new SOLAS regulation III/1.5, it was agreed that, for ships constructed on or after 1 July 2014, on load release and retrieval systems must comply with the provisions of the Life-Saving Appliance (LSA) Code.

Governments are encouraged to assure compliance with any ship constructed after 20 May 2011. For existing ships, it was agreed that on-load release mechanisms should be evaluated for compliance with the amended LSA Code no later than 1 July 2013 and that mechanisms not complying with the amended LSA Code must be replaced or modified no later than the next scheduled dry-docking after 1 July 2014 and no later than 1 July 2019.

IMO – MEPC

The IMO Marine Environment Protection Committee (MEPC) met in July 2011 and adopted several measures that will require action by MODU owners and operators, including energy efficiency measures under MARPOL Annex VI, revised MARPOL Annex V (garbage) regulations, biofouling guidelines and guidelines related to recycling of ships.

Mandatory measures to reduce emissions of greenhouse gases from international shipping were adopted by parties to MARPOL Annex VI. Amendments to MARPOL Annex VI regulations add a new chapter making mandatory the Energy Efficiency Design Index (EEDI) for most new ships (currently not including MODUs) and the Ship Energy Efficiency Management Plan (SEEMP) for all ships. The regulations are expected to enter into force on 1 January 2013.

The EEDI is a non-prescriptive, performance-based mechanism allowing ship designers and builders freedom to use the most cost-efficient solutions to comply. The SEEMP establishes a mechanism for operators to improve the energy efficiency of ships. MODU operators will need to develop SEEMPs for their units.

The MEPC also adopted the revised MARPOL Annex V Regulations for the prevention of pollution by garbage from ships; amendments are expected to enter into force on 1 January 2013. Main changes include the updating of definitions; the inclusion of a new requirement specifying that discharge of all garbage into the sea is prohibited, except as expressly provided otherwise; and expansion of requirements for placards and garbage management plans to fixed and floating platforms engaged in exploration and exploitation of the seabed.

The first set of international recommendations to address biofouling of ships was adopted as well. The guidelines will address the risks of introduction of invasive aquatic species through the adherence of sea life, such as algae and mollusks, to ships’ hulls. MODU operators should consider adopting procedures to reduce the likelihood of transfer of such species during rig moves.

The MEPC adopted the 2011 Guidelines for the development of the Ship Recycling Plan and updated guidelines for the development of the Inventory of Hazardous Materials, intended to assist the implementation of the Hong Kong International Convention for the Safe and Environmentally Sound Recycling of Ships, adopted in May 2009. Although this Convention has not entered into force, MODU owners should consider the implications of both.

Also adopted were MARPOL amendments to designate certain waters adjacent to the coasts of Puerto Rico and the Virgin Islands as an emission control area (ECA) for the control of emissions of nitrogen oxides, sulfur oxides and particulate matter under MARPOL Annex VI Regulations for the prevention of air pollution from ships. The amendments are expected to enter into force on 1 January 2013, with the new ECA taking effect 12 months later.

Guidelines were adopted for reception facilities under MARPOL Annex VI and guidelines addressing additional aspects to the NOx Technical Code 2008 with regard to requirements related to marine diesel engines fitted with selective catalytic reduction systems.

The MEPC also approved, for future adoption, draft amendments to the NOx Technical Code 2008, relating to engines not pre-certified on a test bed and to NOx-reducing devices. It also agreed on terms of reference for the review of the status of technological developments to implement the Tier III NOx emission standard.

USCG – risk-based inspection of modus

As its first post-Macondo initiative, the USCG has implemented a new policy for risk-based inspections of foreign-flagged MODUs operating under US jurisdiction.

In addition to the annual inspections required to obtain a certificate of compliance, which is required for operations under US jurisdiction, MODUs will be inspected more frequently based on a risk-based scoring system, similar to the Port State Control program for traditional ships. Scoring categories are:

• Owner/operator performance;

• Vessel’s flag-state performance;

• Class Society performance;

• Vessel history; and

• Vessel particulars (e.g., rig type and age).

Each time a MODU moves to a new well location, the USCG will evaluate the rig for inspection based on the overall score. Rigs with a high enough score will be subjected to more frequent inspections. Resources permitting, the USCG also will be conducting random, unannounced examinations on 25% of the rigs in a specific Captain-of-the-Port zone.

USCG – STCW amendments

The USCG published a supplemental notice of proposed rulemaking on 1 August (76 FR 45908) regarding implementation of the 2010 amendments to the International Convention on Standards of Training, Certification, and Watchkeeping for Seafarers (STCW Convention) and the STCW Code, and other non-STCW changes to update the regulations. This rulemaking will delineate the requirements for international and domestic credentials in the Code of Federal Regulations for all US mariners. Since this rulemaking will provide a noticeable split between STCW credentials and those used for domestic purposes, the USCG is holding public meetings to obtain comments.

IADC solicited member input and submitted comments to the docket.

MLC 2006

Members were urged earlier this year to begin planning for the entry into force of the International Labour Organization’s Maritime Labour Convention 2006. The Convention will enter into force 12 months after it receives its 30th ratification, as the 19 countries that have ratified the Convention to date have already fulfilled the minimum threshold level for tonnage.

The Convention requires that ships of States Party to the Convention obtain a Maritime Labour Certificate. To obtain the certificate, the flag-State must provide a Declaration of Maritime Labour Compliance (DMLC-Part I), which identifies a list of matters subject to inspection, identifies all national requirements necessary for implementation of the Convention, refers to any ship-type specific requirements, and clearly records any matters subject to “substantial equivalence” or exemption determinations.

Based on DMLC-Part I, the ship owner must prepare a DMLC-Part II that will identify all measures that will be in place to ensure ongoing compliance with the national requirements, as well as measures to ensure continuous improvement in labor conditions onboard the ship. Because of the scope of matters addressed in DMLC-Part II, most drilling companies will need to coordinate efforts to address company policies and procedures with regard to: human resources, training, safety, payroll and scheduling, claims management, insurance, legal, newbuild projects, medical and collective bargaining.

The flag-State’s competent authority or recognized organization will certify the DMLC-Part II and, after satisfactory inspection, issue the Maritime Labour Certificate.

For MODUs, many vexing issues remain unresolved: in particular, whether the flag-State will apply to the Convention to non-propelled units; and the degree to which, if at all, the flag-State will include the client’s personnel and third-party personnel within the definition of “seafarer” subject to the provisions of the Convention.

Once the 30-country threshold is reached, there will be only 12 months to complete the inspection and certification process for tens of thousands of vessels. The facilities of both the flag-States and recognized organizations will be hard-pressed to complete the process. Thus, members have been urged to begin the process. Many companies will need to press their flag-State authorities for answers regarding their interpretations regarding the scope of the Convention and available “substantial equivalence” or exemption determinations, as well as to obtain preliminary DMLC-Part I’s for their units. Countries already party to the Convention in which MODUs are registered include: Bahamas, Denmark, Liberia, Marshall Islands, Norway, Panama, Singapore, and St Vincent & the Grenadines.

OGP – drilling hazard site surveys

OGP issued new guidelines for conducting offshore drilling hazard site surveys describing good practice for conducting geophysical and hydrographic site surveys of proposed offshore drilling locations. The document also covers the use of exploration 3D seismic data to enhance or replace acquisition of a site survey.

The guidelines explain the requirements that different types of offshore drilling units have on a site survey. The new report also emphasizes the differing site survey requirements of shelf and deepwater environments.

Objectives of the site surveys and the site survey process are included in the guidelines, as well as suggestions on all phases of a site survey. These include initial desk studies and planning, data requirements and geohazard analysis and reporting.

Ken Fischer, regional vice president – Middle East and Africa

UBO & MPD Committee

The IADC Under-balanced Operations & Managed Pressure Drilling Committee has issued a notice pertaining to manufacturers’ testing of rotating control devices (RCDs).

“As manufacturers test their system in compliance with Spec 16RCD, the pressure ratings are reduced. For some applications, particularly using oil-based fluids, or at elevated fluid temperatures, additional fit-for-purpose testing should be considered,” committee chair Sara Shayegi, Shell, said.

API Spec 16RCD, Specification For Drill Through Equipment – Rotating Control Devices, stipulates design verification testing requirements for RCDs. Because many manufacturers test their equipment based on this specification, pressure limits using a common standard can be determined, and equipment from various manufacturers can be compared. Results from this testing may show lower operating ranges compared with previously published product specifications.

Those considering the use of RCDs are encouraged to consult with manufacturers for the latest pressure testing results based on API Spec 16RCD. For some operations, fit-for-purpose testing beyond design verification tests prescribed in API 16RCD may be advised.

A requirement for fit-for-purpose testing is being considered for future editions of the specification.

Dual Gradient Drilling Subcommittee

A Dual Gradient Drilling (DGD) Subcommittee was organized in 2011 under the UBO & MPD Committee to develop best practices and build interest in the technology. John Cohen of AGR Subsea serves as subcommittee chairman, and Kristin Falk, Ocean Riser Systems, is vice chair.

The group also seeks to improve understanding of various DGD methods and their limitations and benefits, and serve as a forum for information exchange.

“The DGD Subcommittee, like its parent, the IADC UBO & MPD Committee, will first work to facilitate the safe exploitation of hydrocarbons. Unlike the UBO & MPD Committee, the new subcommittee will focus on the offshore environment,” Mr Cohen said.

The 2011 IADC Dual Gradient Drilling Workshop was held in May in Houston, examining the types, challenges and benefits of DGD, emphasizing well control and testing the concept. The 2012 Dual Gradient Drilling Seminar will be held in March in Milan, Italy.

Contracts Committee

The IADC Contracts Committee continued its efforts to revise the model contract forms used in US land operations in 2011. Revisions to the daywork form are nearly complete and will be presented to the IADC Board of Directors for adoption. When the daywork form is complete, similar revisions will be incorporated into the footage and turnkey forms; these will also be presented for Board approval.

In view of new regulatory requirements and operating practices in the Gulf of Mexico, a similar project was initiated in February for the daywork form used in US offshore operations.

One key area pertains to the provision of rigs for emergency response operations. The full effect of requirements to send rigs and crews to assist in these situations has yet to be evaluated and addressed.

“There are many important considerations emanating from last year’s tragedy. These will need to be addressed in the IADC model contract form,” Rowan Companies’ John Buvens, vice chairman of the committee, said.

Middle East Operations Forum

Nabors Drilling International hosted an IADC Middle East Operations Forum (MEOF) meeting in their new Jebel Ali facility in May.

Mr Fischer conducted the meeting and reported on IADC activities and programs relevant to operations in the Middle East.

Mr Kropla also participated in the IADC reports, as did Jason McFarland, VP – membership and publications, and Linda Hsieh, Drilling Contractor managing editor.

The keynote discussion topic was “The Role of an HSE Case in an Effective HSE Management System and the Use of the IADC HSE Case Guidelines,” presented by Wayne Ralph, Noble Drilling.

Another MEOF meeting was scheduled for late October, just prior to the SPE/IADC Middle East Drilling Technology Conference & Exhibition, in Muscat, Oman. Hosted by KCA DEUTAG, the MEOF will feature a discussion on “Competency Management in an Expanding Market.” KCA DEUTAG and Weatherford Drilling International will make presentations.

Oman workshop

Mr Fischer facilitated a workshop held in May in Muscat, Oman, on “Using the IADC KSA Templates to Implement a Competence Assurance Program.” The event was held in cooperation with the Oman Leaders in Safety Forum, a contractor group of Petroleum Development Oman. Thirty people representing 17 companies attended.

The agenda addressed adapting KSA templates to the operations of specific companies, elements of a competence assurance program and using the IADC Competence Assurance Accreditation Program for third-party verification.

South Central Asia Chapter

In January, the South Central Asia (SCA) Chapter held the 2011 IADC South Central Asia Drilling Technology Conference & Exhibition in Mumbai. Transocean’s Deepak Munganahalli and ONGC’s UN Bose, SCA Chapter chairman, served as co-chairmen of the conference. The event featured various technical presentations and panel discussions of interest in India.

In May, SCA Chapter members met with their US-based counterparts during OTC. The annual meeting, chaired by Mr Bose, allows for discussion of issues confronting contractors in India. The agenda included reports on offshore safety regulations, current and pending tax rules and provident fund applicability. Additionally, the group heard a status report on employment visa restrictions.

Joe Hurt, regional vice president – North America and lead staff land HSE issues

New assistant director Paul Breaux joined IADC in mid-2011 as assistant director – land operations to provide support for the HSE Committee and land division. He is also the lead staff for the Rig Moving Committee. Mr Breaux began his career in the oil & gas industry as a site medic and safety coordinator in 1998 and has served as HSE director for Dorado Oil Services.

OSHA outreach team

The Rocky Mountain Oil and Gas Safety Outreach Team met in May 2011 to discuss the formulation of safety standards for the oil and gas industry. The team – established under a grant given to the Rocky Mountain Education Center of Lakewood, Colo. – was tasked by OSHA to formulate specific industry rules and regulations that pertain to all phases of oil and gas operations in the continental US.

Currently, safety standards for upstream oil and gas fall under either the general industry or construction standard, depending on the phase; thus, there are no specific standards for the industry to follow.

Besides the main committee, three subcommittees were established: OSHA CFR Oil & Gas Regulatory Compilation Update 2011, Oil & Gas Upstream Job Task Analysis and Trainer Qualifications.

OSHA also issued a grant to Red Rocks Community College in Colorado, an OSHA-authorized training center, to develop an oil and gas-specific outreach training course. The course would be similar to the OSHA 10- and 30-hour outreach training courses based on OSHA regulations for a specific industry – e.g., General Industry (29CFR1910), Construction (29CFR1926) and Maritime (29CFR1015). Drilling operations are regulated under 29CFR1910 while other upstream operations fall under either 29CFR1910 or 29CFR1926, depending on the process being undertaken.

Red Rocks Community College, in association with the Rocky Mountain Education Center, met in August to solicit industry input in the development of the curriculum for an OSHA 10-hour course specific to oil and gas. The meeting addressed three issues: defining course content that would cover all regulations that apply to the oil and gas industry, applying a hazard assessment approach to the course design and defining trainer qualifications to teach the OSHA oil and gas course. The courses would be offered only by OSHA-authorized training centers.

It was determined that the outreach group would develop three courses, the length of each to be determined later and based on course content. The three levels of courses would be: awareness orientation (which could be satisfied by the SafeLandUSA orientation), OSHA training (which would expand the orientation course time and content to meet workers’ need for training), and OSHA supervisor/safety leadership training. The meeting leader commented that, once the course content is developed, it could be used as a template for developing a vertical standard for the upstream oil and gas industry.

Wyoming OSHA

In August 2011, members of the Wyoming Oil & Gas Industry Safety Alliance (WOGISA) Regulatory Subcommittee met with Wyoming OSHA to review proposed changes to the Wyoming Oil and Gas Drilling Safety Regulations.

Wyoming OSHA laid out its concerns and asked industry representatives what practices or changes to the wording in current regulations were needed. Main issues that arose were:

1. Wyoming OSHA is proposing to require fire-resistant clothing (FRC) on all drilling locations once the well is spudded. In addition, vendors and other non-rig personnel within 75 ft of the wellbore must wear FRCs unless the personnel are in office locations (i.e., toolpusher bunkhouse).

2. It was proposed that the use of Geronimo-type derrick escape devices be disallowed.

3. Although current regulations require specific training, there will be a statement in the new rules that “all required training shall be documented.”

There will be a 45-day period for public comment on these proposals before they are submitted to the state OSHA commission, which will meet in December 2011.

OSHA – employee reporting

OSHA proposed updating Appendix A to Subpart B of its Injury and Illness Recording and Reporting regulation. The major part of the proposed rule change was to move from the Standard Industrial Classification system to the North American Industry Classification System. Although this should not affect the upstream oil and gas industry, OSHA also included changes in employer reporting requirements.

Under the proposal, employers would be required to report to OSHA within eight hours all work-related fatalities and all work-related in-patient hospitalizations, and within 24 hours all work-related amputations. OSHA defines amputations as loss of a limb or other external body part, including a fingertip.

The current regulation requires an employer to report to OSHA within eight hours all work-related fatalities and in-patient hospitalizations of three or more employees. OSHA hopes that this increase in employer reporting will provide them with better opportunities to investigate workplace incidents.

OSHA also continues to consider whether to include the loss of an eye in these reporting criteria.

OSHA – noise proposal

OSHA proposed and later withdrew its proposed “Interpretation of OSHA’s Provisions for Feasible Administrative or Engineering Controls of Occupational Noise.” The proposal would have clarified the term “feasible administrative or engineering controls” as used in OSHA’s noise standard.

Due to concerns raised about the proposal, Dr David Michaels, assistant secretary of labor for occupational safety and health, acknowledged that it requires much more public outreach and resources than originally anticipated.

“We are sensitive to the possible costs associated with improving worker protection and have decided to suspend work on this proposed modification while we study other approaches to abating workplace noise hazards,” he said.

Dr Michaels met in January 2011 with the offices of Sens. Olympia Snowe and Joseph Lieberman, members of the Senate Committee on Small Business and Entrepreneurship. The two senators co-chair the Senate Task Force on Manufacturing.

OSHA said it will continue to review comments that have been submitted.

OSHA – FRC

IADC staff continues to address OSHA’s letter of interpretation requiring employers to provide fire-resistant clothing (FRC) to workers. Members are represented on the API task group that is developing a hazard assessment recommended practice. At this meeting, OSHA pledged to work with industry in developing a PPE hazard assessment tool for the upstream industry.

FMCSA – HOS

The Federal Motor Carrier Safety Administration (FMCSA) proposed in early 2011 to require all motor carriers currently required to maintain Records of Duty Status (RODS) for Hours of Service (HOS) recordkeeping to use Electronic On-Board Recorders to monitor their drivers’ compliance with HOS requirements.

All motor carriers currently required to use RODS would still be required to obtain and keep records of Duty Status reports. However, they would be relieved of the requirements to retain supporting documents to verify driving time.

FMCSA also proposed to require all motor carriers – both RODS and timecard users – to systematically monitor their drivers’ compliance with HOS requirements. Motor carriers would be given three years after the effective date of the final rule to comply with these requirements.

Rig Moving Committee

The Rig Moving Committee has completed a competency program for swampers that is pending final approval. The committee is now developing a competency program for gin-pole truck operators and reviewing principles and requirements of the Compliance, Safety, Accountability (CSA) 2010 pilot program.

Health, Safety and Environment Committee

The Health, Safety and Environment Committee has been reviewing and sharing information on company programs on corporate responsibility, compliance, company culture and SEMS compliance.

The Environmental Affairs Subcommittee has been reviewing cooling water discharge issues, as well as environmental data tracking.

Jason McFarland, vice president – publications and membership

Ethics Committee

The IADC Ethics Committee met in March 2011 to discuss ways in which ethics and compliance training can be tailored for different companies, and the next meeting is expected to convene in November. Additionally, Ensco’s Brady Long, who has led the committee as chairman since its inception in 2007, has been succeeded by James Sanislow, Noble Drilling Services.

Technical Publications Committee

The IADC Technical Publications Committee held three meetings in 2011 and will meet again in December to work on upcoming publications. The group has published two books since its inception in 2005 – “Casing and Liners for Drilling and Completions” (2007) and “Managed Pressure Drilling” (2008). The publication of several additional books is anticipated for 2012, on underbalanced drilling, cementing and coiled tubing.

Leon Robinson continues to chair the committee, assisted by vice chairs Mark Morgan, Chevron, and Gary Young, Encana Oil & Gas.

Nigeria Chapter

IADC established the Nigeria Chapter, based in Lagos, in 2011. It brings together IADC members from indigenous and international companies to promote safety, training and environmental stewardship, as well as enhance industry relations with the general public.

“Nigeria presents both challenges and opportunities for the oil and gas industry. The Nigeria Chapter will play a vital role in furthering the awareness of local policies and regulations affecting oil and gas drilling, production and service companies operating in the region,” IADC president Dr Lee Hunt said.

Chapter officers are: chairman, Alex Illah, Transocean; vice chairman, Adeniji Ramoni, Saipem; secretary, Olushola Ismail, Oando Energy Services; and treasurer, Ben Agadagba, Lonestar Drilling.

Mark Denkowski, managing director – accreditation and certification

Dr Brenda Kelly, senior director – accreditation and certification

ACD restructuring

Mr Denkowski joined the IADC Accreditation & Certification Department (ACD) in 2011 as the department’s managing director. He has assumed overall management responsibility for the unit, which was restructured into functionalized areas of program development, customer service and quality assurance/quality control.

Dr Kelly continues to head up the program development function under the new title of senior director – program development. She now focuses on new program development, as well as updating and maintaining program documents and other instruments associated with IADC’s competency and accreditation programs.

Elfriede Neidert, quality control/quality assurance coordinator, is responsible for scheduling and following up on training provider audits, as well as overseeing the department’s ISO-certified quality management systems.

The customer service function consists of accreditation coordinators Marlene Diaz, Janet Lara, Joseph Washington and Loundia Riggs. Ms Riggs focuses on ACD implementation of IADC’s new database system, plus backup support for the system and new IADC website support. She continues to handle incoming training records and provides customer support.

Julia Swindle has moved into a new role as industry compliance specialist, still reporting to Mr Denkowski. Ms Swindle continues to support program development, with an emphasis on application, forms and audit check lists updates, and to coordinate activities of the Training, HSE and Well Control committees. She also participates in regulatory and compliance meetings and conferences to bridge the gap between IADC’s Operations and Accreditation departments.

Well Control Committee/WellCAP program revisions

In 2011, the IADC Well Control Committee initiated tougher requirements for WellCAP to strengthen well control competencies and enhance program integrity while removing ambiguities or lack of uniformity among existing program processes.

Program changes approved include modifying procedures for combining courses, implementing tougher testing protocol and clarifying instructor qualifications at the introductory, fundamental and supervisory levels.

Additional approved improvements include shortening the recertification cycle and revision of the WellCAP supervisor-level drilling curriculum.

Program changes implemented are:

• Procedures for combining WellCAP courses − WellCAP drilling courses are no longer permitted to be combined with wireline, coiled tubing or snubbing courses or any other courses that do not have similar operational approaches to well control. Drilling courses may continue to be combined with workover/completion courses.

• WellCAP testing protocol − All final WellCAP examinations are now clearly defined as “closed book.” Course quizzes and intermediate examinations may be “open-book” format provided the final examination is comprehensive and closed-book. If intermediate examinations are to form a final composite score of a student’s course performance, all intermediate examinations must be closed-book. Collectively, the intermediate examinations must provide a comprehensive assessment of the student’s knowledge and understanding of the specific WellCAP course content for which assessment is being conducted.

• Instructor qualifications for introductory level courses – During the application process, instructors providing training at the introductory level are now required to meet qualifications previously required of fundamental- and supervisory-level instructors. Introductory instructors must provide evidence of satisfying two of three optional qualifications: valid supervisory-level well control certificate, presentation skills or relevant teaching experience, or operational experience or technical skills.

• Acceptance of IWCF Certificate as WellCAP instructor qualifications (fundamental and supervisory levels) − The IWCF supervisory well control certificate will be accepted as evidence of WellCAP instructor qualifications if the certificate is being provided as evidence of instructor qualifications. This is contingent upon the certificate being issued by a training provider/IWCF assessment center other than the one for which the instructor is employed or working.

Public comments were solicited and reviewed by the Well Control Committee before implementing these revisions.

Well Control Roundtable

Approximately 40 people attended the Well Control Roundtable and Workshop, sponsored by the Well Control Committee, in December 2010.

The program was organized around two panels, one on “The Future of Well Control Training” and the other on “How Simulators Can Enhance Well Control Training.”

During the first panel, operator and drilling contractor representatives discussed current well control training and ideas on ensuring competency.

Steve Smith, Saudi Aramco, said he believes that the lack of a clear understanding of certification, qualification and competence is impeding the development of well-defined plans for well control training and competence assessments. He also expressed concerns over the industry’s inability to introduce what he called the “adrenaline factor” into classroom training, citing an urgent need to ensure that employees respond appropriately during well control events.

Flexibility of the WellCAP program was identified as a training strength by Arabian Drilling’s Harin Hattangady, although he added that this flexibility can potentially be misused. Another concern was the limited emphasis on preventing well control events, particularly in training for assistant drillers and drillers. He believes that simulators and interactive computer-based training (CBT) are important tools for future training.

Panel participants also declared it time to rethink the current approach to well control training. Many suggestions were offered for enhancing training and for developing and assessing employees’ competencies. They included:

• Strengthening current training standards and audit processes;

• Adding more well event prevention training;

• Utilizing more team activities;

• Reviewing and modifying curriculums as needed to ensure delivery of fit-for-purpose training;

• Increasing the amount of simulator time in supervisory-level courses; and

• Developing techniques for introducing the “adrenaline factor” into training.

Use of simulators, CBT and e-learning for pre-well control course refreshers and pre-assessments, along with readily available continuing education materials at the worksite, were identified as tools for helping employees to retain knowledge and skills.

Third-party assessments, course pre-assessments and use of simulators to assess not only well control knowledge and skills but also employees’ ability to make decisions were discussed. It was recommended that employees identified as weaker performers be required to undergo annual well control training.

In the second panel, participants discussed ways to enhance well control training through the use of simulators. Among the key suggestions were to:

• Use simulators more in training and assessing employee knowledge, skills and abilities;

• Develop more stringent simulator exercises and assessments; and

• Improve administrative and recordkeeping processes by taking advantage of simulators’ ability to record student performance, check on student identity and provide an audit trail for both instructor and student activities on the simulator.

“The roundtable discussions confirmed our well control community’s concern for employees’ well control competencies and their eagerness to address these concerns head-on,” Dr Kelly said.

A workshop for WellCAP instructors followed the roundtable. Participants received continuing education credits to apply toward maintaining WellCAP instructor approval.

Simulator manufacturers also held workshops with their user clientele to demonstrate simulator capabilities.

WellCAP Review Panel

John Breidenthal, Chevron Energy Technology Co, and Darryl Bourgoyne, Louisiana State University, were elected to the IADC WellCAP Review Panel in March 2011. Mark Mazzella, BP, continues his role on the panel.

The newest members of the review panel are Malcolm Lodge, Transocean, and Karl Shearer, Diamond Offshore Drilling.

Accreditation audits

In response to the rapid growth of IADC-accredited training programs in Mexico, the association began in September 2010 a concentrated audit effort across that country. The intent was to reassure association members and training program students that IADC’s accreditation programs offer the same quality wherever the training is delivered. The audit effort will continue until all training providers in Mexico have been audited.

In Mexico and elsewhere, IADC began to take disciplinary action against training providers who either did not respond to corrective/preventive actions requested after site audits or only partially responded. Disciplinary action included suspension and revocation of accreditation; timelines were determined by the severity of the nonconformity.

“IADC is committed to maintaining accreditation programs of the highest standards. Accreditation staff will continue to take steps to ensure the integrity of the programs,” Mr Denkowski said.

Jens Hoffmark, regional vice president of European Operations

EOF June meeting

OGP, along with representatives from four European regulators groups, attended the IADC European Operations Forum (EOF) in June 2011 in Copenhagen. The Netherlands Oil and Gas E&P Association (NOGEPA), Norway’s Petroleum Safety Authority (PSA), Germany’s State Authority for Mining, Energy and Geology and the Danish Energy Agency joined approximately 20 representatives from drilling contractors and oil companies for the meeting.

Steve Cromar, ConocoPhillips, and Annabel Holroyd, OGP, discussed the status of the Global Industry Response Group (GIRG) initiative and the expected EU initiatives covering the oil and gas sector. Mr Cromar stressed that ongoing commitment from the industry is required and that active international communication is essential.

Gert-Jan Windhorst of the NOGEPA and George Galloway, GeoTechInvest and a consultant for NOGEPA, spoke about HSE initiatives in Holland since Macondo.

Magne Ognedal of Norway’s PSA distributed copies of his agency’s Macondo report summary issued in June 2011.

A group Q&A discussion followed touching on topics such as the use of dispersants, competence and capping devices.

EOF September meeting

Eleven drilling contractors, five regulators representing Norway, Denmark and Holland, and one oil company representative participated in the September 2011 EOF meeting in Amsterdam, together with IADC staff.

Newbuild rigs were discussed, as approximately 120 new rigs will be entering the market over the next few years. This will require about 12,000 new crew members. Contractors and a training school proposed the creation of a basic training program – an idea that was passed on to the IADC Training Committee.

Mr Spackman offered an update on post-Macondo initiatives, with a focus on the discussion papers on USCG and BOEMRE reports, as well as BOEMRE’s proposed SEMS 2 rule.

Mr Denkowski spoke about IADC’s accreditation programs, noting that the Offshore Competency Training Program has been renamed Personnel Offshore Safety Training to reflect its focus on training. The program is expected to be rolled out in early 2012.

Mohamed El Halimi from the Danish Energy Agency (DEA) offered a presentation on how DEA is monitoring and studying Macondo reports to ensure lessons are learned with the objective to further improve HSE legislation.

PSA’s Mr Ognedal also was present. He explained that PSA has generally concluded that there is little need for changes to existing Norwegian regulations.

Chit Hlaing, operations assistant – Asian operations

AOF October 2010 meeting

Mr Kropla updated the Asia Operations Forum (AOF) on IADC’s and industry’s response to Macondo at a meeting in October 2010 in Singapore. Contractor members also discussed issues of immediate concern in the Asia Pacific region. In attendance were representatives from Aban Offshore, Atwood Oceanics, Frigstad Offshore, Jasper Offshore, Maersk Drilling, Nabors Drilling, Seadrill, Transocean and Vantage Drilling.

AOF March 2011 meeting

AOF convened again in Singapore in March 2011 to discuss pressing issues in the region and receive an update of IADC activities. Two special presentations were offered as well, one on compliance with the US Foreign Corrupt Practices Act (FCPA) and the UK Bribery Act, and the second on updates and developments on the cabotage issue and local content requirements in Indonesia.

For the first presentation, two guest speakers from Hogan Lovells International Law Firm discussed key provisions of the FCPA and Bribery Act, key differences between their requirements and practical advice on how companies operating outside the US and UK can avoid violations.

For the second presentation, Hing Ming Wong, Transocean, provided updates on the legislative and regulatory problems in Indonesia.

The next AOF meeting is scheduled for 22 November, in conjunction with the IADC Critical Issues Asia Pacific Conference & Exhibition in Kuala Lumpur, Malaysia. Denys Hickey, head of Energy & Offshore Group Asia Pacific Region, Ince & Co Singapore, will make a guest presentation on regulatory challenges and international law developments.

Derek Morrow, IADC industry affairs consultant, also will provide updates on transboundary oil damage & pollution legislation.

Indonesia Local Content Workshop

IADC held a workshop in Singapore in late June to address the “35% local content requirement” in the Indonesian market and to help drilling contractor members understand ways of fulfilling that obligation.

PT Patra Mitra Konsulindo, an Indonesian consulting firm, helped conduct the training session, which covered the legal aspects and basic principles of local content calculation on procurement of materials, goods and services and how to prepare service cost structures and fill in local content in bid documents. Participants also were able to ask pressing questions about the requirements and get them answered directly.

Contractor members in attendance were Atwood Oceanics, COSL Drilling, Diamond Offshore, Ensco, Maersk Drilling, Mermaid Drilling, Northern Offshore, Rowan Companies, Seadrill, Songa Offshore, Transocean, UMW Standard Drilling and Vantage Drilling.

IADC staff, including (from left) Dr Lee Hunt, Brian Petty, Steve Kropla and Alan Spackman, have worked on a multitude of political and regulatory efforts since Macondo to ensure the position of the drilling industry is appropriately represented.

Over the past year, IADC continued to work with the US Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE), recently replaced by the Bureau of Safety and Environmental Enforcement (BSEE), as well as other regulatory and industry groups from the US and around the world, to get the global drilling industry back on track in Macondo’s aftermath. The association recognized that, going forward, nurturing the relationships we forged during 2010 with these government and industry organizations will be critical to our members’ success in this interdependent world.

“The opportunity exists for all stakeholders to continue to grow that relationship into a collaborative enterprise in a non-crisis situation. Working together, we can build a better industry with greater responsibility,” IADC president Dr Lee Hunt wrote in the September/October 2011 issue of Drilling Contractor.

Also at the forefront this year was ensuring that the voice of our industry is heard and that regulations developed in reaction to Macondo reflect our industry’s true safety records.

With BOEMRE, IADC’s efforts ran the gamut from crusading for an end to the drilling moratorium and for expediting the slow pace of drilling permit approvals, to ironing out ambiguous and inconsistent offshore drilling requirements, to responding to the first of many regulatory proposals.

Testimony in support of the industry was provided before multiple groups, such as congressional committees, the US Chemical Safety Board and the National Academy of Engineering, and motions against lawsuits brought by environmentalists continued to be fought in the legal arena.

With industry groups such as API and the International Association of Oil and Gas Producers (OGP), collaborations were undertaken to assure governments and regulators that the industry can carry out offshore drilling in a safe manner. IADC is actively participating, for example, on OGP’s Wells Expert Committee, established as a result of the Global Industry Response Group (GIRG) initiative.

In recent months, IADC also has been actively engaged with the Offshore Operators Committee’s (OOC) SEMS Task Force, a collaboration that resulted in a toolkit to help operators and their drilling contractors comply with BSEE’s requirements for mandatory safety and environmental management systems.

The following is a summary of these Macondo-related activities and more over the past year. Efforts are extensive, and most are ongoing.

A panel session on “Post-Macondo: Defining the ‘New Normal’ for Drilling Offshore” was held at the IADC World Drilling 2011 Conference & Exhibition in June in Copenhagen. IADC president Dr Lee Hunt (second from right) moderated the session. Panelists were (from left) Alan Spackman, IADC; Martin Fruergaard, Maersk Drilling; and Magne Ognedal, PSA Norway.

BOEMRE/BSEE/BOEM

Although US Interior Secretary Ken Salazar officially lifted the drilling moratorium in October 2010, for months it seemed as if a “permitorium” had taken its place. A study undertaken in late 2010 by industry groups, including IADC member companies, found that staffing constraints at BOEMRE were curtailing drilling permit approvals.

At the same time, a lack of clarity concerning new requirements led to further delays.

Late last year, as part of formal comments filed to BOEMRE on the interim final rule on offshore drilling safety, IADC and other industry groups urged the agency to open its regulatory process to the public and reiterated an invitation to participate in API’s open standards-setting process. The comment emphasized that notice and comment rulemaking would help make the agency’s rulemaking more efficient and likely achieve a safety benefit. It also would assist BOEMRE in promulgating more legally defensible regulatory actions.

Further, the agency was urged to issue a final rule to reverse its decision to interpret “should” as “must” with regards to more than 14,000 discretionary, non-mandatory provisions in 80 API standards. There is no regulatory basis for adopting a blanket requirement for all discretionary language to become mandatory, the trade groups pointed out. Further, mandatory compliance with discretionary API standards provisions is impossible in many cases.

To highlight this issue, industry groups provided detailed commentary on key standards – Spec 6A, RP 65-2, RP 53, MPMS Chapter 7, 20.1 and 21.1. These documents represent an important subset of the referenced standards and include valves, blowout preventers, cementing practices and measurement techniques. The commentary pointed out how conflicts would arise if “must” were substituted for “should.”

The document submitted to BOEMRE also highlighted nearly 30 additional technical issues raised by the agency’s interim final rule and urged the regulators to publish a final rule responding to these concerns.

Lease prospects

In December 2010, Secretary Salazar announced that areas in the eastern Gulf of Mexico (GOM) – areas under a congressional moratorium – as well as the mid- and south Atlantic planning areas were no longer under consideration for potential development through 2017. The explanation provided was that critical BOEMRE resources must be devoted to planning areas that already had leases for future development.

Industry groups, including IADC, soon sent a letter to the chairmen and ranking members of the House and Senate Appropriations committees asking Congress to provide additional resources to BOEMRE to increase staff, training and inspectors.

“It is imperative that BOEMRE is provided the necessary resources to review and process permits to drill OCS waters, and to maintain a vibrant leasing program in the OCS,” the groups stated.

It was also pointed out that the former Minerals Management Service (MMS) collected more than $22 billion in revenue from the oil and gas industry in 2008, a portion of which could go toward increasing staff and funding at BOEMRE.

Professor Jorge Piñon from Florida International University poses a question at the 2011 IADC Environmental Conference in Trinidad. Mr Piñon also made a presentation at the event examining the experience and qualifications of operators with production sharing agreements in Cuba.

Later in the year, IADC joined other organizations in filing comments urging the US government to reconsider its decision to exclude those areas from the Programmatic Environmental Impact Statement (PEIS) for the 2012-2017 OCS Leasing Plan, as well as from the 2012-2017 leasing program itself.

It was pointed out that keeping these areas out of the PEIS would keep them off-limits to potential development until at least 2017. This is a shortsighted move considering the increasing demand for energy in the US. Including these areas in the PEIS does not guarantee their inclusion in the final leasing program. However, an area must be analyzed pursuant to the National Environmental Policy Act (NEPA) in order to be included in a five-year program.

Industry also urged BOEMRE and other agencies to ensure understanding of their roles in the Multi-Sale Environmental Impact Statement (EIS) addressing Central and Western GOM lease sales for the 2012-2017 leasing program. On 1 October 2011, the leasing responsibilities of BOEMRE were assigned to the newly formed Bureau of Ocean Energy Management (BOEM).

BOEMRE jurisdiction over contractors

In the media as well, IADC worked to ensure that industry’s position was represented. In July 2011, IADC executive VP – government affairs Brian Petty commented in a Dow Jones newswire article that BOEMRE “doesn’t have the experience or resources to regulate this whole arena of contractors. At the end of the day, it’s up to the operator to inspect any flaw or episode.”

The comment was made in response to then-BOEMRE director Michael Bromwich saying that the agency will pursue fines, penalties or charges against drilling contractors and service providers where actions of the companies are “egregious.” Mr Petty noted that the bureau’s actions would create confusion in determining liability for drilling projects. It could also make it difficult for contractors to get insurance and, as a result, push them toward doing more business in foreign waters.

In an October 2011 Dow Jones article, Mr Petty again spoke on behalf of the industry to assert that fining contractors who worked for BP on the Macondo well lacks precedent and may be illegal.

By pursuing contractors, regulators “give a green light for others to go after them – on the same basis and on the same level” as primary operators, he said. Decades of precedent support the idea that only operators should be targeted for rule violations, he emphasized.

The comment was given as US regulators were looking to hand out punishments for contractors’ roles in the Macondo spill. Mr Bromwich said contractors should be held accountable and said fines were coming in the “very near future.”

The Outer Continental Shelf Lands Act allows the government to collect $40,000 per day per violation.

Sen. David Vitter, R-La., supported drilling contractors’ position and questioned the legal basis for fines. “There needs to be a full accounting of the legal analysis behind (the Department of) Interior’s expansion of authority,” Sen. Vitter said.

On 12 October 2011, BSEE notified Transocean and Halliburton of the initiation of civil penalty proceedings against their companies.

BOEMRE restructuring

In October 2011, BOEMRE split into two independent bureaus – the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE).

The BOEM’s programs include offshore leasing, resource evaluation, review and administration of oil and gas exploration and development plans, NEPA analysis and environmental studies. Tommy P Beaudreau, previously BOEMRE senior adviser, leads this newly formed agency, while Mr Bromwich is temporarily leading the BSEE, whose functions include the development and enforcement of safety and environmental regulations, inspections, offshore regulatory programs, spill response, and training and environmental compliance programs.

Ocean Energy Safety Advisory Committee

Don Jacobsen of Noble Drilling Serviceswas among industry personnel selected to be part of a 15-member Ocean Energy Safety Advisory Committee. The group provides the US Interior Department and BOEMRE with guidance on improving offshore drilling safety, well containment and spill response.

In addition to Mr Jacobsen, other offshore industry personnel appointed to the committee are Charlie Williams, Well Engineering and Production Technology, Shell; Paul Siegele, Chevron’s Energy Technology Company; and Joseph Gebara, Technip USA. Former Sandia National Laboratory director Tom Hunter leads the body as chairman.

Ron Sass from the James A Baker III Institute for Public Policy explains the current characteristics and behaviors in the greater Caribbean basin and Gulf of Mexico at the 2011 IADC Environmental Conference in Trinidad. IADC has embarked on a One Gulf initiative to ensure preparedness in case of any oil spills offshore Cuba.

National Commission

Through late 2010 and into this year, IADC continued to liaise with the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling.

Mr Petty met with staff members of the presidential commission ahead of a formal hearing, providing the commission with various documents, including IADC’s safety case template. Previous congressional testimony by IADC on international regulatory systems and the safety case also was provided.

In answer to commission questions on a “check list” for critical systems in deepwater drilling, Mr Petty provided information on IADC’s efforts with API through the Joint Industry Task Force (JITF) and the recommendations that were developed for Secretary Salazar.

Commission staffers were also advised that BOEMRE should be left to devise a post-Macondo regulatory system without congressional-specific direction, and OSHA should not be involved in inspecting offshore facilities.

Mr Petty, along with IADC group VP – operations & accreditation Steve Kropla and Van Scoyoc Associates’ Jan Schoonmaker, also met with commission staff to discuss considerations associated with implementing a safety case system in the US. Other items of discussion included a possible role for IADC in training new BOEMRE inspectors, real-time monitoring and development of leading indicators for industry safety performance.

Congressional action

In late 2010, IADC and industry groups fought against language in a House bill that would have extended offshore permit reviews from 30 days to 90 days. A joint letter was sent to the chairmen and ranking members of the Senate Committee on Appropriations and the Subcommittee on Interior, Environment and Related Agencies in December.

The justification provided for the extension was that additional environmental reviews were needed. Industry pointed out that this claim ignores the significant amount of review required under the current regulatory regime for offshore development.

It was also misleading to claim that BOEMRE has only 30 days to review an exploration plan. The 30-day clock begins only after the agency deems the exploration plan complete; moreover, it has 15 more days before this timeline begins to decide whether to ask for additional information. If gaps are identified, additional information can be requested before the proposal is finalized.

“This proposal to extend the exploration plan review period would only serve to exacerbate the confusion – jeopardizing jobs across the region and threatening to send much needed investment capital overseas,” the letter said.

API

API Standard 65-2 (“Isolating Potential Flow Zones During Well Construction”) was issued in December 2010, and API RP 96 (“Deepwater Well Design Considerations”) was balloted in mid-2011 and is being revised in consideration of comments received.

API Standard 53 (“Blowout Prevention Equipment Systems for Drilling Operations”) will be changed from a recommended practice to a standard because BSEE is expected to incorporate the standard into new regulations. “It’s a substantial rewrite of the old RP 53 with a lot of added meat,” said Alan Spackman, IADC vice president – offshore technical and regulatory affairs.

Additionally, API and IADC will be jointly issuing Bulletin 97, primarily an interface document between the drilling contractor and lease operator. It too is being revised in consideration of comments received. The document has been tailored for US-specific concerns, and further work would be needed to adapt it for use in other regions. “We’re happy to help anyone in an operating region if you need to develop national guidance,” Mr Spackman said.

SEMS compliance

IADC collaborated with the OOC’s SEMS Task Force to produce a collection of tools to help contractor companies prepare for safety and environmental management systems (SEMS) implementation. Lease holders and operators on the US Outer Continental Shelf are under a 15 November deadline to develop and implement a SEMS program. IADC and the Center for Offshore Safety worked with the task force to develop a toolkit for drilling contractors and operators. It includes:

• An audit checklist;

• Matrices of regulatory mandated training for drilling/marine/production;

• Knowledge and skills documentation worksheet;

• Operator-contractor agreement letter templates;

• Terms/definitions – clarification document; and

• Compliance readiness worksheet.

These tools present the collective views of industry professionals who reviewed the SEMS rule and identified where the regulation points to the contractor as needing to take specific actions and supply documents or records of those actions to the lessee in support of the lessee’s SEMS.

These tools also can be used by lessees who do not have SEMS in place as they work to develop their SEMS.

“These tools provide guidance for contractors in reviewing their company’s internal safety and environmental management policies, procedures, operations and personnel to help ensure the company’s readiness to meet SEMS requirements and the expectations of their lessee’s SEMS plan,” said Brenda Kelly, IADC senior director – accreditation and certification and chair of the OOC SEMS Competence Subcommittee.

The toolkit is available on the IADC website.

In a related matter, IADC’s offshore operations is developing comments in response to BSEE’s proposed additions to its SEMS regulations. The additional proposed provisions would address: stop work authority, employee participation in SEMS development, designation of an ultimate work authority, reporting of unsafe working conditions, job safety analyses and independent third-party audits. According to Mr Spackman, the proposal is a further confusion regarding operator/contractor responsibilities under BSEE regulations and creates Swiss cheese-like holes in the SEMS by carving out issues based on jurisdictional boundaries that were agreed between MMS and the Coast Guard.

OGP Wells expert committee

IADC is providing member and staff support to two task forces on the OGP Wells Expert Committee (WEC), formed in 2011 as a result of the GIRG initiative. The aim is to provide recommendations on industrywide improvements in the wake of Macondo and Australia’s Montara spill.

Jean-Paul Buisine, Transocean, and Peter Dansen, Maersk Drilling, are members of the BOP Reliability and Technology Development task force, chaired by Steve Haden, BP, with Mr Buisine as co-chair. IADC’s Mr Kropla is co-chair of the Human Factors – Training, Competency and Behaviours subgroup, chaired by Gareth Williams, BG Group. Mr Kropla is also a member of the BOP subgroup.

In addition, Allan McColl, Maersk Drilling, and Michael Fry, Transocean, participated in the July WEC meeting in London.

Other WEC groups include a Database task force designed to collect industrywide information on well control incidents and an International Standards task force responsible for identifying and prioritizing relevant API, ISO and other industry standards. The overall WEC effort is chaired by Steve Cromar, ConocoPhillips.

The WEC held its inaugural meeting in London in June 2011, with follow-up meetings in August in Houston and in September and October in London. Subsequent monthly meetings are planned for the remainder of 2011.

OGP Safety Committee Workshop

In April 2011, Mr Spackman was among speakers from BP, Statoil and others at the OGP Safety Committee Workshop in Kuala Lumpur, Malaysia. He provided an overview of the IADC HSE Case Guidelines, including recent updates, and urged national oil industry groups to develop bridging arrangements to assist the drilling industry in the implementation of safety cases.

If followed, the IADC guidelines provide a safety case acceptable to regulators and will reduce proliferation of differing approaches by new safety case adoptees, Mr Spackman said. In late 2010, the guidelines were updated to identify shortcomings related to bridging arrangements, particular risks of deepwater wells, and evaluation of routes to temporary safe refuges and evacuation systems. The guidelines remain under continual review to address other gaps as they may be identified.

With bridging arrangements, Mr Spackman said they are either required or expected in areas where a safety case is required by regulation, but only high-level guidance (UK Step Change and OGP) is currently available internationally. IADC believes that the uncertainties regarding individual and mutual roles and responsibilities for the security, safety and protection of the environment must be clarified for each enterprise.

IADC continues to support national and regional initiatives to develop guidance on bridging arrangements, such as the API-IADC Well Construction Interface Document (WCID).

Petroleum engineering students from the University of Trinidad and Tobago were invited to attend the 2011 IADC Environmental Conference to experience first-hand the industry’s commitment to environmental concerns.

G20 GMEP

IADC was among international organizations invited by President Obama’s National Security Council to participate in two G20 Global Marine Environmental Protection (GMEP) group meetings over the past year. The first was held in Moscow in February, and the second was held in Paris in July. Mr Kropla represented IADC at both meetings.

The G20 consists of finance ministers and central bank governors from 19 countries, plus the European Union, representing the world’s largest economies. The GMEP workgroup was established as an initiative on offshore oil and gas exploration and development and marine protection as the result of a proposal made by Russia after Montara and Macondo.

Besides IADC, other international organizations that participated in the meetings were the International Maritime Organization, the Organization for Economic Cooperation and Development, the International Energy Agency, the Organization of Petroleum Exporting Countries, the North Sea Offshore Authorities Forum, the International Energy Forum and OGP.

At the February meeting, the organizations made presentations on current activities and initiatives that might contribute to the workgroup’s mandate to exchange information about best practices for preventing and responding to incidents related to offshore oil and gas exploration and development, as well as maritime transportation.

Mr Kropla’s presentation focused on continued refinement and growing acceptance of the IADC HSE Case Guidelines; IADC’s work in establishing industry training standards through its accreditation programs such as WellCAP, Rig Pass and Ballast Control & Stability; and the association’s involvement with international initiatives such as the JITF and OGP’s GIRG initiative.

The meeting agenda included presentations on BP’s Macondo Accident Investigation report, the US Presidential Commission’s report on the BP spill, and the Australia Commission of Inquiry’s report on the Montara spill.

The GMEP also continued development of a questionnaire on methods of sharing best practices with its members and select international organizations and international experts. Responses to the questionnaire, along with a review of international marine environmental regulation of offshore oil and gas exploration, production and transportation, are being considered to make final recommendations.

This work was continued at the July meeting, where a “business practices seminar” was held to allow for more direct input from industry. BP, China Offshore Environmental Services (part of China National Offshore Oil Corp), Shell, Petrobras, Statoil, ENI, Total and Saudi Aramco each made presentations detailing the environmental protection efforts undertaken in their operations. Abu Dhabi National Oil Company, ConocoPhillips, ONGC, PEMEX and Repsol also attended.

Mr Kropla spoke about IADC’s conferences worldwide, particularly those related to HSE, well control and the environment. He also discussed plans to revise the HSE Case Guidelines, the WCID and the WellCAP curriculum.

The second day’s members-only meeting aimed to refine the latest draft of the issue paper on sharing best practices for marine environmental protection. IADC submitted technical comments concerning an overstatement of the water-depth capability of jackups and clarifying WellCAP as an accreditation system rather than a “well control school.” The comments were accepted.

He also offered these recommendations:

• Support the use of industry-developed standards, particularly API and ISO Technical Committee 67;

•Establish a website to act as a clearinghouse for resources for sharing best practices for training materials, technical reports, conferences, etc; and

• Acknowledge and support the work of industry organizations engaged in the dissemination of best practices.

The GMEP was encouraged to make the website available to non-G20 members as the goal should be to provide a route to information people might not encounter otherwise.

ISO

In early 2011, the Management Committee of the International Organization for Standardization’s (ISO) Technical Committee 67 agreed to a detailed and prioritized action plan on standards that should be revised or developed in view of learnings derived from the Macondo and Montara incidents.

The plan requires considerable effort and resources. Some of the work can be viewed as typical of the ongoing work of the committee, while other work addresses new subjects, e.g., a “wells integrity – umbrella document,” guidance on “development and implementation of HSE management systems” and “competence of personnel.”

High-priority work includes revision or development of standards for:

• Reliability modeling and calculation of safety systems;

• Testing of well cements;

• Isolating potential flow zones during well construction (based on API Std 65-2);

• Drill-through equipment (based on revised API Spec 16A and ISO 13533);

• BOP equipment systems for drilling wells (based on the new API Std 53);

• Deepwater well design considerations (based on API RP 96); and

• Remotely operated tools and interfaces on subsea production systems (based on revised API Spec 17H).

Lower-priority items affecting MODUs include:

• Expansion of the scope of ISO 13702 to address blowout scenarios on MODUs;

• Revision of ISO 15544 on requirements and guidelines for emergency response, and

• Revision of the ISO 19901-7 (stationkeeping systems) to “ensure the standard adequately covers the stability of drilling vessels and that the vessel’s movement (intact or in damage condition) for ultimate capsize could not harm the drilling riser (sic).”

IRF

IADC continues to liaise with the International Regulators Forum (IRF), presenting updates at their regulatory meetings on industry activities since Macondo. Mr Kropla participated in two presentations at IRF’s Summit Workshop in Stavanger, Norway. The first focused on IADC’s global perspective, and the second was given jointly with OGP.

The IADC presentation was given in response to questions posed by IRF regarding IADC’s past and planned activities, critical issues facing the industry and expectations of the international regulators.

The joint presentation with OGP included Mr Kropla and Mr Cromar of ConocoPhillips, appearing in his capacity as chairman of OGP’s Wells Expert Committee. The session, “Well Control and BOP Issues,” was introduced by Magne Ognedal of PSA Norway. The presentation was offered in response to a request made by IRF to both OGP and IADC urging an evaluation of the functionality, reliability and vulnerability of BOP systems. This issue was one of the strategic items on which various regulators agreed to at last year’s IRF meeting in Vancouver.

When introducing Mr Kropla and Mr Cromar, Mr Ognedal expressed great expectations of the work launched by the industry to overcome the challenges presented by BOPs and well control.

“The natural course for us was to approach the industry,” Mr Ognedal said. “So we contacted the IADC and the OGP with a number of questions about existing systems and equipment. Today’s review of recommendations from the industry shows that much good work is being done. We now face the long and demanding route from studies and recommendations to actual implementation.”

Earlier, Mr Kropla participated in the IRF’s first extraordinary meeting in the group’s 17-year history in late 2010. Representatives of regulatory agencies from Australia, Brazil, Canada, the Netherlands, New Zealand, Norway and the United Kingdom attended.

The industry panel highlighted activities of IADC, API, OOC and OGP. IADC’s presentation focused on its involvement with the JITF, primarily on the Equipment and Procedures workgroups, on proposed implementation of a safety case system in accordance with the IADC HSE Guidelines, and the WCID.

NAE testimony

IADC, along with a number of producer and service companies, appeared at a hearing in March 2011 of the US National Academy of Engineering’s (NAE) Subgroup on Regulatory Oversight. The hearing was held as part of NAE’s inquiry into Macondo, which was requested by the US Department of the Interior.

The hearing in Houston focused on the potential value of introducing a safety case system in the US. Representing IADC at the meeting, Mr Kropla appeared on a panel discussion that included Charlie Williams, Shell; Bill Arnold, ConocoPhillips; William Daugherty, ATP Oil & Gas; and Richard Williams and Aaron Swanson, Baker Hughes. Testimony later in the day included Cory Loegering, Apache; Michael Denkl, Schlumberger; and Jeremy Thigpen, National Oilwell Varco.

Panel participants were asked to respond to questions posed by the NAE committee. These included views on the potential benefits of a safety case, modifications that might be considered for safety case implementation in the US, and potential barriers to implementing a safety case system in the US.

Other questions focused on views toward establishing an industry-operated safety institute and how it might function, as well as whether operating companies should be required to participate in well control containment groups and provide real-time monitoring of operations.

Congressional testimony

In March 2011, Jim Noe of Hercules Offshore testified in Washington, DC, before the Energy & Power Subcommittee of the House’s Energy & Commerce Committee. His message was clear: The Obama Administration is working to dismantle an entire industry, and we can’t let them succeed.

“The Administration has knowingly and irresponsibly put policies in place that have undermined thousands of good-paying jobs in the offshore oil and gas industry … and repeatedly ignored federal court orders that struck down the administration’s job-killing policies and attempts to create new law by executive fiat,” the testimony stated.

It is imperative that domestic oil and gas production in the Gulf of Mexico be resumed immediately, Mr Noe said, adding that a de facto moratorium had already forced Seahawk Drilling into bankruptcy, “destroyed by the misguided and heartless policies of this Administration.”

Moreover, the cancellation of offshore lease sales made the domestic production situation even worse. Businesses are being forced to look for work outside the US, leading both drilling rigs and highly trained personnel to depart.

“Offshore exploration provides affordable energy for all Americans and supports jobs in every corner of America. We must not let this industry die,” Mr Noe said.

CSB testimony

Mr Spackman testified in December 2010 in Washington, DC, before the US Chemical Safety Board (CSB) as part of its investigation into Macondo’s causes. He reviewed IADC’s HSE Case Guidelines for MODUs and described why a safety case based on these guidelines is appropriate for US deepwater drilling operations. He also pointed out that the guidelines facilitate acceptance across regulatory jurisdictions where a safety case is required; they also reduce proliferation of differing requirements by new safety case adoptees.

Additionally, he described the API-IADC WCID and how it adds the elements of well basis of design, well execution plan and critical well activity risk assessments to the traditional HSE management system bridging arrangement. Further, IADC was developing recommendations for changes to the guidelines based on results of gap analyses with API RP 75 and BSEE’s SEMS Final Rule.

Mr Spackman also urged the agency to assess its resources in developing an approach to implementing the HSE case. A means for ongoing dialogue with industry is needed, and a multi-year roadmap recognizing the complexity of that implementation should be formed.

He added that the US Coast Guard, which also holds regulatory jurisdiction over offshore E&P activity, should establish dialogue with BOEMRE, particularly on matters traditionally under Coast Guard jurisdiction.

IADC MODU HSE Case

In October 2010, the IADC HSE Case Users Group adopted several minor amendments to the IADC HSE Case Guidelines for MODUs in immediate response to information gaps identified from the Macondo incident. These amendments provide clarifications and point to additional areas of emphasis, particularly with regard to bridging arrangements. They have been incorporated into the guidelines and are available on the IADC website.

In October 2011, the Users Group adopted additional amendments to the guidelines to address gaps identified through a gap analysis against the provisions of API RP 75 and BSEE’s SEMS rule. These addressed: temporary refuge and escape routes, drawings and schematics, design and commissioning of new facilities, management of change, job safety analyses and record retention. The text of the amendments is available on the IADC website and will be incorporated into the guidelines in the near future.

Job creation

In light of President Obama’s address to Congress and the US in September 2011 on jobs creation and reducing unemployment, IADC joined more than a dozen other industry groups to urge the president “to improve efficiency and the rate of permitting activity in the Gulf of Mexico to a rate that is commensurate with industry’s ability to invest.”

The groups noted that increasing the permitting rate would simultaneously create high-paying jobs and increase revenues into federal coffers. A recent study showed that increased E&P in the Gulf would create 230,000 jobs and increase US GDP by more than $44 billion.

The return to normal following the drilling moratorium has been characterized by a lack of urgency. Meanwhile, the Gulf is losing business to foreign markets. “The rate of approval of exploration plans is down 85%, and the median approval time has slipped from 36 days to 131 days,” the industry groups said. “Rigs are actually leaving the Gulf for greater business certainty in places like Egypt, Congo and Nigeria,” the letter stated.

Legal action

IADC continued to monitor the flood of anti-drilling lawsuits filed by environmental organizations since Macondo.

In late 2010, IADC, API, IPAA and the US Oil & Gas Association (USOGA) filed a motion to intervene in a lawsuit brought by the Center for Biological Diversity (CBD) challenging Secretary Salazar’s decision to lift the drilling moratorium. CBD claimed that the Secretary should have prepared an environmental impact assessment (EIA) prior to making that decision and that the court should order the moratorium to stay in place until an EIA has been completed.

The associations’ motion to intervene emphasized that, as it normally takes at least 12 months to prepare an environmental impact statement, what the CBD seeks would effectively mean a complete cessation of deepwater oil and gas drilling in the Gulf of Mexico for months.

Ensco lawsuit

IADC closely monitored and supported the lawsuit filed by Ensco against the US government that ended in a resounding win for the industry. In February 2011, Ensco won a motion for a preliminary injunction against BOEMRE, which was ordered to take action on five of Ensco’s pending drilling permit applications within 30 days and to report its compliance to the court. In granting the motion, US District Court Judge Martin Feldman noted that Ensco showed:

• A substantial likelihood of prevailing on the merits;

• A substantial threat of irreparable injury if the injunction is not granted;

• The threatened injury outweighs any harm that will result to the non-movant if the injunction is granted; and

• The injunction will not disserve the public interest.

The judge noted that, under the Outer Continental Shelf Lands Act, the government is under a duty to act by either granting or denying a permit application within a reasonable time. “Not acting at all is not a lawful option,” the ruling stated.

The court also agreed that 30 days is “a common-sense marker” of the speed at which applications should be approved or denied – the same as the 30-day period Congress mandated in which BOEMRE must act on exploration plans. Before Macondo, permits were processed in about two weeks. Yet five permits relating to Ensco’s deepwater rigs had been pending from four to nine months – a time frame the judge called “unreasonable, unacceptable and unjustified.”

“Beginning to process permit applications will restore normalcy to the Gulf region and repair the public’s faith in the administrative process,” the judge wrote.

Prior to Ensco’s lawsuit, IADC filed an amicus brief in mid-2010 in support of Hornbeck Offshore Services’ lawsuit against Secretary Salazar; the case won a ruling from Judge Feldman lifting the original moratorium.

“The question is not whether the drilling moratorium will have a severe effect on the economy of the Gulf Coast. No one doubts that. The question is more basic: whether the local economy can even survive the moratorium,” the brief stated.

It also cited news reports and comments from public figures and citizen groups warning of dire economic consequences.

European Commission

IADC closely monitored the drafting of a Macondo report that was presented to the European Parliament in 2011. The report was drafted under the leadership of UK chair Vicky Ford and advised by OGP, with input from other members of the European Parliament and industry representatives. It has been accepted by the Parliament and referred to the European Commission, which plans to propose related legislation.

In presenting the report, Ms Ford emphasized that issuing E&P licenses is the prerogative of EU member states, and Europe should favor a site-specific, goal-setting approach to managing offshore safety. She also stressed that some 90% of oil and 60% of gas is produced offshore and that oil and gas are crucial to Europe’s energy security. Any approach to offshore safety also must involve neighboring countries because there is much E&P in non-EU countries as well, she said.

The need for a true safety culture was emphasized, as was the value of a more qualified inspection network. However, it is not clear that the EU’s control would lead to real added value, Ms Ford said, and it should not draw extensively on scarce national resources.

Further, substantial investments have already been made in capping and containment equipment. The European Maritime Safety Agency has no expertise in spill prevention and should not regulate offshore installations.

Although the report recognized that operators should be financially liable for spills, it also noted that the obligation could be met in different ways; regional mutual funds may be a model. Moreover, care must be taken so that smaller operators are not excluded from the market.

Ms Ford also concluded that an E&P moratorium in the Arctic is not appropriate as Arctic exploration began in the 1920s. Regulators should provide permits only when they are confident that the risks are being addressed.

EU Commissioner Antonio Tajani responded that any EU action will seek to avoid destabilizing the current regime and will be based on existing best practices.

UK Parliament

In early 2011, the UK Parliament concluded that there should not be a moratorium on deepwater drilling on the UK Continental Shelf (UKCS) but recommended that the UK Health and Safety Executive (HSE) prescribe that there be two blind shear rams on all BOPs on the UKCS because the equipment provides a final line of defense against spills. The recommendations were part of a UK parliamentary report in January 2011.

Another finding of the report was that the Offshore Pollution Liability Association (OPOL) limit of $250 million is insufficient. If there is an oil spill resulting from drilling activities, liability legislation must ensure that those affected are compensated, the report said.

However, the UK Parliament also agreed that oil spill response procedures in the UK are robust and recognized that a drilling moratorium would increase the UK’s reliance on imports of oil and gas, potentially decreasing the national security of supply. Calls for increased oversight of the UK offshore industry by the European Commission should be rejected in favor of multilateral approaches to regulation and spill response, the report concluded.

NSOAF

In September 2010, IADC hosted a group of regulators from the North Sea Offshore Authorities Forum (NSOAF) in Amsterdam to discuss industry and IADC efforts following Macondo and Montara.

Mr Kropla provided the briefing with assistance from Mr Spackman, following an introduction by IADC president Dr Hunt. The presentation focused on key IADC activities, including participation in the JITF and other industry initiatives.

Regulators in attendance hailed from Norway, the Netherlands, the Faroe Islands, Germany and the United Kingdom.

In March 2011, IADC again met with NSOAF regulators for a briefing and dinner in Amsterdam. Mr Kropla provided an update addressing industry efforts since the previous meeting.

Additionally, regulators from Denmark, the Netherlands, Norway and the UK provided perspectives on recent developments and challenged drilling contractors to improve their safety and equipment. This resulted in a candid discussion in which contractors detailed the robustness and comprehensiveness of their safety management systems.

IADC president Dr Lee Hunt (left) speaks with Humberto Rivero, Cuba ambassador to Trinidad & Tobago, at the 2011 IADC Environmental Conference, 12-13 May, in Port of Spain, Trinidad.

Cuba: One Gulf

In September 2011, IADC and the Environmental Defense Fund (EDF) Cuba Program jointly hosted a delegation to Havana, Cuba, to meet with Cuban government and oil industry officials. Accompanying IADC and EDF was William Reilly, co-chairman of the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling.

The purpose of the visit was to continue a dialogue between US experts and their Cuban counterparts in evolving regulations and best practices that will promote safe deepwater drilling in the entire Gulf of Mexico, not just the US and Mexico but Cuba as well.

Dr Hunt and Mr Petty represented IADC on the delegation. Dan Whittle of the EDF and Richard Sears, who served as chief scientist for the Deepwater Horizon Commission, also participated.

The IADC/EDF delegation met with the Minister of Basic Industries, Tomas Benitez, and with the managing director of the Cuban national oil company CUPET, as well as the director of the ministry responsible for regulating the oil and gas sector and other senior officials in the oil and gas industry.

An overview of Cuban exploration plans was presented, followed by information on Cuba’s permitting procedures and regulatory requirements. A trip to a Great Wall Drilling rig was included. The rig had just completed Cuba’s longest horizontal reach well from a land location to a subsea reservoir.

Further, CUPET officials, along with representatives of international oil operators with drilling concessions in Cuba, attended a half-day conference with Mr Reilly, who summarized lessons from Macondo. Mr Reilly expressed his view that Cuba’s oil industry had diligently prepared a thorough plan for permitting and regulation of deepwater drilling. He later communicated this opinion to the press and to US government officials upon his return from Havana.

Mr Reilly also publicly recommended that CUPET be permitted by US authorities to become a producer/operator member of IADC in order to further advance their knowledge and capabilities in deepwater operations and safety.

According to Dr Hunt, IADC’s “One Gulf” initiative is being undertaken by the private sector because the 50-year-old break in diplomatic relations between the US and Cuba and the US economic embargo against Cuba inhibits, if not prevents, government experts from participating in the effort to protect US and Cuban common safety and environmental interests.

Various international press accounts of the delegation’s visit to Cuba can be read on the IADC website.

Mexico’s CNH

Representatives of BOEMRE and Mexico’s Comisión Nacional de Hidrocarburos (CNH) met in New Orleans in July 2011 to exchange information regarding each agency’s regulatory practices and procedures. IADC, Noble Drilling Services and Shell were invited to make presentations regarding the use of safety cases to promote operational safety.

Mr Spackman presented the conceptual model for the HSE Case and explained how it is used by other offshore petroleum regulators. Peter Bridle of Noble Drilling Services explained how Noble implements the safety case, particularly with respect to hazards analyses, assignments of responsibilities, work process design, etc. Joseph Murphy, Shell, explained how Shell implements their HSE management system with respect to hazards analyses, assignments of responsibilities, work process design, etc, via formal interfacing/bridging arrangements.

Other topics addressed at the event included inspections; compliance and enforcement of safety and environmental and safety regulations; incident management; and safety and environmental management systems.

COS

Following publication of the report of the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling, API established the Center for Offshore Safety (COS) with the goal of creating a central arena for all deepwater offshore stakeholders to pursue excellence in offshore safety. Still in its formative stages (Shell’s Charlie Williams, chairman of the COS Governing Board will speak at the 2011 IADC Annual General Meeting), the COS Governing Board hosts several drilling contractors and IADC as members.

Representing drilling contractors are Mo Plaisance, Diamond Offshore Drilling; Alan Quintero, Transocean; Peter Bridle, Noble Drilling; Mark Burns, Ensco; and Dr Hunt, IADC.

The first project of the COS is the creation of an auditing checklist and accreditation of third-party independent inspectors. COS also is incorporating the SEMS Toolkit developed by the OOC with the assistance of IADC.

Arctic Council Task Force

Mr Petty represented IADC on the US delegation to the first meeting of the Arctic Council Task Force for Arctic Marine Oil Pollution Preparedness and Response, held 17-18 October 2011 in Oslo, Norway. The task force was commissioned to promote awareness of and cooperation in sharing information, response equipment and personnel across the Arctic in response to a major spill event. IADC’s attendance as a private-sector participant was requested by the US Coast Guard to provide industry perspectives on suitability of equipment, equipment stockpiles and logistical considerations in identifying, mobilizing, deploying and demobilizing equipment.

In her invitation to IADC, Coast Guard Rear Admiral Cari Thomas, who headed the US delegation, noted that IADC’s insights and knowledge specific to the drilling industry would enhance discussions at the meeting.

Shell, representing IPIECA, was the only other industry participant invited.

Beside the Coast Guard, the other federal agencies represented in the delegation were the US BSEE and the National Oceanic Atmospheric Administration. Government representatives from all Nordic countries, as well as Canada, US and Russia, also made presentations.

Operator requests have led to the manufacture of more advanced and durable fluids. “Green” lubricant chemistries are emerging that hold the promise of both environmental and technical performance. Courtesy of Panolin

Just as the environmentally responsible use of lubricants in daily offshore rig operations and use of zero-spill methods is an ongoing responsibility of the drilling contractor, progress in available chemistries of lubricants is an ongoing effort on the part of industry suppliers. Increased options from suppliers are helping contractors marry environmental responsibility with performance.

More than 250 types of lubricants are used in daily offshore rig operations in appreciable volumes, including engine oils, hydraulic fluids, thruster fluids, pipe dope, gear oils and greases. According to Jon Pearce, marine and energy lubricants product manager for Castrol, the newer rigs being built today have large 3,000-gal hydraulic power packs on the drill floor that sit directly above the moonpool or on the drill floor directly above the sea. The new semisubs have complex hydraulic systems that incorporate heave compensation, and derrick and hydraulic rig mains can have 10,000 gal of oil in them. “When a 6-in. hose burst on one of those, it released 5,000 gal onto the deck of the rig in 20 seconds. It’s not just about system volumes, it’s the huge flow rate that affects the scale of a spill.”

According to lubricant suppliers, switching out the use of older lubricant technology fluids to newer alternatives can deliver comparable if not better performance. The fact that the industry has experienced disappointments with “green” lubricants makes spreading the word of chemistries suited for offshore rigs even more important.

“Historically, green lubricants existed, but they had quite a bad name because typically they didn’t work well in the applications for which they were designed. That’s been quite a hurdle to get over because people think that green lubricants aren’t as good as a conventional product,” Susannah Linington, environmental specialist for Castrol, said. “We found that products that were designed using vegetable oil were great environmentally but technically don’t give the performance required for offshore rig applications.”

There has been a huge development in the type of chemistries used during the last few years that offer both environmental and technical performance,” according to Ms Linington. “A lot of the activities in which we are involved is educating people that the new types of green lubricants are designed with completely different base chemistries that give both the desired environmental performance and the technical performance that works in specific applications,” she said.

Chauntelle Baughman, account manager for Hydraquip, agrees, noting that the greatest challenge in the acceptance of biofluids has been an overall lack of education on the subject and that every effort should be made to promote education on biofluids through the energy industry. “Knowledge of basic fluid properties and their toxicity will position contractors and operators to make environmentally considerate decisions,” she said. “While companies are aware that biofluids are available and becoming increasingly mandated, there is still much confusion about terms such as biodegradability and toxicity and how standards are defined.” Hydraquip is a distributor of hydraulic components and a line of Panolin biodegradable lubricants.

Environmental regulations have been the primary driver behind the use of biofluids. Operator requests have led to the manufacture of more advanced and durable fluids. The use of environmentally friendly fluids overall has largely been the result of governmental regulations restricting and reducing environmental impact, according to Ms Baughman.

In addition to meeting various environmental regulations around the world, advantages to using the green lubricants include fire resistance, rust prevention, longer lubricant life, better system performance over time, and stability in high-heat applications.

Biofluid development

Several environmental risk areas exist onboard an offshore drilling rig. Systems that result in high levels of discharge or a high probability of entry into the sea (red) are considered to be high risk. Applications that contain relatively small lubricant volumes and from which, under fault conditions, the lubricant could not enter the sea are considered to be very low risk (green). Between these extremes are those systems that present significant risk, as anything spilled or leaked directly enters the sea (orange).

According to Mr Pearce, about 20 years ago the industry started working on hydraulic oils based on vegetable oils as an environmentally friendly alternative to mineral oil, and the equipment in which they were used had to be designed around the oil because of their performance limitations. There was never widespread adoption, and the fluids were used only where needed.

“Hydraulic systems were the first systems for which the industry required green solutions,” Mr Pearce commented. “But it became apparent that other equipment (specifically items sitting below the water line on floating rigs, such as thrusters) have leakage because they are deliberately pressurized to keep water out. As a result, there is more focus on what can be called operational discharges as opposed to big spills. As this need surfaced, the solution called for a whole range of green products.”

These oils were less toxic and did not create as much of a sheen but were not truly biodegradable, Mark Miller, chief executive officer for fluids manufacturer Terresolve Technologies, said. “This was a first step in environmental improvements; it was a better technology for environmental performance but was a step down in equipment performance.”

In the late 1990s and early 2000s, readily biodegradable oils surfaced on the market. “I would not say that there was a wholesale shift, but a lot of the pioneers looked to find an environmental alternative for applications in the offshore rig arena,” he continued. “Then along came the perfect storm.”

This was the coincidence of three elements. First, the technology was evolving to where it was suitable for use on drilling rigs. Second, drilling contractors and service companies were looking for further improvements in the environmental arena. Finally, there was a groundswell of US and international agencies pushing for the industry to go greener, according to Mr Miller.

Until recently, most biodegradable hydraulic fluids, gear oils and greases were based on vegetable-oil technology. These technologies are useful in certain applications but typically are poor for use on offshore drilling rigs because 1) rig equipment runs very hot, and vegetable oils cannot take extreme temperatures, 2) there is a good possibility that the lubricants will get wet as the rig and equipment operate in a humid environment, and 3) the change-out interval is very lengthy, according to Mr Miller.

People moved away from the vegetable oil-based fluids in two directions: synthetic ester and biopolyolefin technologies. Terresolve went forward with biopolyolefin technology because it is biodegradable, non-toxic, non-sheening and can take heat, cold and contamination from water and old oil. Hydraquip and Castrol went with synthetic esters. Hydraquip’s synthetic fluid is made from saturated esters and is readily biodegradable, non-toxic, and zinc-free. Castrol also has a suite of synthetic-based hydraulic fluids and lubricants that includes a topside hydraulic fluid and a thruster-specific fluid.

A hindrance to mass use of biofluids

“Some suppliers don’t get the industry all that well, and products that fail give us all a black eye,” Mr Miller noted. “We have to explain that there are fluids out there with different characteristics. Some of them are very good and durable, and some of them fall apart when they get wet. When you’ve got a billion-dollar piece of machinery that’s making $300,000, $400,000 or $500,000 a day, you can’t risk downtime,” he said.

Ms Baughman agreed. “Not all biofluids are created equal. There are some that react poorly to high temperatures, some that are unstable in certain environments, and some that have poor performance characteristics. There have been performance reliability issues in the past because there is a general lack of education regarding the different types of biofluids and which of those fluids are best suited to specific applications.”

Advantages of “green” lubricants vary depending on the type of biofluid being used. “We look at the weaknesses of certain biofluids, but we never stop and say why it is worth it,” Mr Miller said. “Green lubricants typically have better lubricity that equates to reduced wear and reduces operating temperatures, which can prolong equipment life. These lubricants also have a higher viscosity index (how the thickness of oil changes with regard to temperature), so the fluid will stay within the designed thickness and viscosity over a broader temperature range.”

Understanding the terminology

“I think it’s fair to say that the majority of the industry associates environmental performance with biodegradability. To state that something is inherently biodegradable is getting accepted, when in fact, any oil-based product is inherently biodegradable. It just takes a long time to degrade,” Mr Pearce noted. “The level of awareness needs to be raised about what is and isn’t environmentally responsible.”

“People seize on just one statement like saying that something is biodegradable,” Ms Linington said. “Food grade is a misconception. Many say, ‘oh, it will be fine’ when confronted with food grade as an option. But humans are very different organisms than algae. What can be perfectly safe for a human to eat can be very toxic to an algae or a smaller organism living in the plankton. That’s why it’s important to test the product in seawater.”

“There is no scientific definition of what environmental responsibility is,” she continued. “People have different conceptions of what is considered environmentally responsible. It’s important to say that this product is going into the marine environment, and therefore, the marine environmental impact will be at the point that it goes into the sea. Biodegradation, toxicity and bioaccumulation need to be considered and they need to be measured in seawater, not fresh water or soil, which are quite easy tests to pass.”

“It’s important that contractors ask lubricant suppliers the right questions,” Ms Linington continued.

First, what is biodegradation? “It seems like a simple question that should have a simple answer,” Ms Baughman commented. Actually, there are two standards for biodegradability: inherently biodegradable and readily biodegradable. “While some fluids are biodegradable, that does not necessarily indicate that they are non-toxic. According to the US Army Corps of Engineers standard, a hydraulic fluid is considered to be non-toxic if a specific ratio of the hydraulic fluid to water is used and less than 50% of the test organisms die within 96 hrs,” she said.

“Ideally, you want 60% of any of the chemicals within a formulation to have broken down naturally when they go into the sea,” Ms Linington said.

“Inherently biodegradable” means that the product has the propensity to biodegrade; no specific time frame or degree is given for the breakdown. Petroleum-based lubricants may be inherently biodegradable; however, they persist in the environment for years and require long-term remediation.

“Readily biodegradable” fluids break down rapidly when they enter the environment. Four types of readily biodegradable fluids are conventional vegetable-based fluids, synthetic esters, polyalkylene glycol and polyolefin.

Vegetable-based fluids are readily biodegradable, but, when exposed to heat, begin to break down to the point of destruction; they can only withstand operating temperatures under 160°F and they become unstable when exposed to water or moist environments.

Synthetic esters are also readily biodegradable and non-toxic and are available in two categories: saturated and unsaturated. Unsaturated ester products tend to oxidize quickly, while saturated ester products resist oxidation. Some synthetic fluids may form acids as a result of exposure to moisture, but all acids created are not the same. Hydrolysis of esters does not always lead to corrosive acids; sometimes acids formed can improve anticorrosion capabilities, according to Ms Baughman.

Polyalkylene glycol exists in both biodegradable and non-biodegradable form. It is intolerant of conventional petroleum oils and vegetable oils, is very soluble and is typically incompatible with seals and filters used in marine equipment.

Biopolyolefin is biodegradable, non-toxic and tolerant of water and contaminants. It is stable in all temperature ranges, climates and seal compatibilities. It is also compatible with conventional petroleum and most other biodegradable products.

The second important question relates to toxicity. Toxicity is the degree to which a substance can damage an organism. It can refer to the effect on a whole organism, such as an animal, bacterium or plant, as well as the effect on a substructure of the organism.

Mineral oil is quite toxic, especially in combination with conventionally used additives, Ms Linington said.

“We test all components in our formulations on four different species across the food chain. It’s important that you test all levels from algae to fish at the top of the food chain,” Ms Linington commented. “The last thing we look at is bioaccumulation potential, the potential for a chemical to build up in the fatty tissue of an organism and gradually over time have toxic effects. This can go right up the food chain into humans … bioaccumulation is something that people tend to ignore; they focus on biodegradation.”

Regulations regarding lubricants

Environmental legislation related to lubricants surfaced in the 1990s, according to Ms Linington. Today, regulatory guidelines specifically related to hydraulic fluids and lubricants have been issued in the northeast Atlantic region, the Gulf of Mexico, Norway, and Canada. Also, any pollution in international waters is covered by the International Convention for the Prevention of Pollution from Ships (MARPOL).

“Really you’ve got three situations, two of which are covered by regulations (blowout preventer control fluids and oil spills into the sea),” Mr Pearce said. “Small-scale oil releases (such as from thrusters and hydraulic line leaks) fall in between existing regulations.”

Finding formulations that work

While “green” lubricants have been available for some time, significant advances have been made in their chemical composition, according to Ms Baughman. When selecting a biodegradable fluid that meets the needs of the offshore drilling industry, things to look out for include the fact that synthetic esters are often grouped together despite the significant performance and longevity differences between saturated and unsaturated.

Whether the product is saturated is determined by chemical bonds within the fluid itself. Unsaturated esters have multiple open bonds that interact with oxygen quickly, leading to oxidation (aging) of the fluid. Aging is the cause of extreme thickening and gumming of the fluid, along with deposits of shellac, which lead to catastrophic system failures, according to Ms Baughman.

“Ask the fluid manufacturer for the Iodine Number,” she said. “It identifies the number of open bonds available, so the higher the Iodine Number, the greater the number of bonds that can interact and oxidize. Generally speaking, a saturated ester product has an Iodine Number of less than 15.”

Another thing to determine is whether the fluid will be compatible with seals in existing equipment. The biofluid supplier should be able to provide testing documentation and manufacturer approvals, Ms Baughman said.

Also, hydrolytic stability should be considered when selecting a biofluid, she continued. Hydrolytic stability is the ability of a fluid to resist decomposition in the presence of water. To measure the degree of hydrolysis in a biodegradable ester, for instance, the total acid number (TAN) should be reviewed. When oils are mixed with water and heat, they are cleaved, or bonded, and new chemicals are formed as a result of this reaction. These chemicals can include glycols and fatty acids. When looking at TAN results, a high number indicates that a large number of ester molecules have cleaved, meaning that the chemical composition of the fluid has changed.

In the case of mineral-oil-based lubricants, the TAN should not exceed 2 mgKOH/g (milligrams of potassium hydroxide per gram) but the TAN values of biodegradable alternatives may increase up to 5 mgKOH/g without leading to any problems, Ms Baughman said.

“It is important to note that before hydrolysis of synthetic products will cause any issues in a hydraulic system, the amount of water needed for that hydrolytic process to take place will cause major cavitation, corrosion and other catastrophic issues before the fluid even begins to react…. In principle water is a harmful contaminant, reducing the life of the hydraulic fluid and the mechanical components,” she said.

Cost versus performance

“The reality is that a good-quality biodegradable fluid is going to cost more than a good-quality petroleum oil,” Ms Baughman said. “But you’re going to get a lot of benefits from the biofluid like improved performance, potentially longer change-out intervals and better operation at reduced environmental risk. So, in the long term there is actually a cost savings.”

Making the effort

Most operators and contractors would agree that it’s better to stay ahead of the curve when it comes to understanding environmental properties of chemicals used in daily operations, discerning levels of discharge and probability of spills, selecting the best chemical options based on the level of environmental compliance and equipment performance, and maintaining zero-spill solutions.

“I think the industry overall is doing a phenomenal job from the environmental perspective. I firmly believe that the industry has not given itself enough credit for all of the environmental initiatives that it has taken and accomplished,” Mr Miller remarked.

A contractor in search of alternatives

While some “green” chemistries have not performed as expected, there are environmentally safe rig fluid alternatives that do work. According to Mr Miller, Noble Drilling had been looking for a non-toxic hydraulic fluid for use in the exposed areas on its rigs; several products were tried, but in the end, they did not meet Noble’s needs because they broke down quickly in the harsh offshore environment.

“Despite the fact that they experienced a significant failure, Noble was still willing to try it again,” Mr Miller said. “They did a limited program with us which was a sweeping success. Now they are starting to do some change-outs across their fleet.”

“I like to say that today’s chemistries are not your daddy’s biofluids,” Mr Miller quipped. “There were no doubt problems with earlier versions of the green fluids. The lubricants industry has realized that the needs of a drill rig are different than some of the other applications. We have to be smarter and make our fluids more durable… Some of us have taken that challenge, gone back to the lab and made the fluids work better.”