Extreme Deepwater Wells Push Drillers To Begin Using Managed-Pressure Methods

Dual-gradient drilling has long been described as the drilling method of the future for challenging offshore wells. Now there are indications that it could start being used with some regularity, with multiple-well campaigns possible as early as next year.

This method of managed-pressure drilling has been used a handful of times on a floating drilling rig, mostly to precisely manage the pressure in wells while drilling in weak, low-pressure formations prone to major fluid losses. Currently, Chevron and Statoil are seeking to use the system for deep, difficult, high-pressure formations in the US Gulf of Mexico.

A drillship leased by Chevron, Pacific Santa Ana, is testing dual-gradient equipment on the ocean bottom while drilling a conventional well, and the company has leased a second drillship from Pacific Drilling, Pacific Sharav, that was built to accommodate dual-gradient drilling equipment.

Statoil is seeking a permit to drill what could be the first dual-gradient well in the deep waters of the Gulf of Mexico, using another version of the managed-pressure method. “When we came here to the Gulf of Mexico, it was a perfect match with the challenges we had here,” said Uno Holm Rognli, vice president of drilling and wells in the offshore US for Statoil. “We started a program locally to develop this system” for conditions in the Gulf.

It is the next step for the method used by Statoil off Norway, and by three companies in water 7,500 ft deep off Cuba. In both places it was used to successfully drill wells where pressure was so low, and the rock so fragile, that wells drilled using conventional methods were plagued by major fluid losses.

While a few pioneers are working on dual-gradient drilling, there is a broader, growing base of operators using managed-pressure systems offshore. These are closed-loop systems with metering to allow precise measurement of change in fluid flows and chokes that allow them to apply backpressure when needed.

Petronas and Petrobras are embracing managed-pressure drilling to deal with offshore wells where total fluid loss makes some wells impossible to drill using conventional methods. Managed-pressure equipment allows them to drill through sections of wells with cavernous underground hazards that can cause major fluid loss by using managed-pressure methods such as mud-cap drilling.

The Brazilian oil company has adapted it for deepwater drilling and plans to equip 16 drilling rigs to be able to do it by 2016.

“Managed-pressure drilling is a key technology to help us put into production some of our vast offshore projects,” said Jose Umberto Arnaud Borges, offshore well project manager exploratory well construction at Petrobras. The rigs are equipped to precisely control downhole pressure within limits that would be too tight to drill using conventional methods.

Dual-gradient drilling is a variation of managed-pressure drilling created to widen those constricted drilling windows by eliminating or reducing the impact of the tall column of fluid returning up the riser. Dual gradient was chosen by Statoil, which is considering using other managed pressure methods, because it allows the company to better handle problems on difficult wells such as lost circulation, hole instability, and fluid influxes, said John-Morten Godhavn managed-pressure drilling specialist at Statoil Gulf of Mexico. “We need better control of the bottomhole pressure and a better kick detection to manage it better,” he said.

The deepwater Gulf could represent a high-profile test site for dual-gradient technology that has been quietly nurtured by a small community of experts whose careers have been intertwined with dual gradient since the late 1990s. That was a time of intense interest in the technology, with ideas ranging from using gas injections to hollow glass balls to reduce the weight of the fluid rising in extended risers.

Chevron is using a method successfully tested in 2001, but as with most dual-gradient methods, it was set aside for years as drillers used other methods to deal with challenges the technique was created to address. Chevron picked it up again around 2009 and decided to build a full-scale version of the method developed by the SubSea Mudlift Drilling Joint Industry Project.

Ready Now?

Many of the key players in this community were on a panel of 10 at the recent Offshore Technology Conference in Houston discussing: Is Dual Gradient Ready for Prime Time? The answer offered by the panel was that increased use of dual gradient is inevitable based on the drilling challenges presented by many of the best available prospects, but adoption could be gradual.

“We started back 15 years ago. It is a long transition but I think we are close,” said John Kozicz, technology manager at Transocean. “We are entering an era with more managed-pressure drilling and (the industry) will have to take the next step and that will be dual gradient.”

Roger Stave, senior technology adviser at Enhanced Drilling, formerly part of AGR Group, said he has discussed multi-well drilling campaigns using its EC-Drill method with several operators.

Shell is also considering whether to use some form of dual gradient. At the panel discussion, Brian Tarr, a principal deepwater engineer at Shell, said he sees widespread future use though that may well be after many of its long-time supporters have retired. “It will take 10-25 years before the industry makes full use of dual gradient,” Tarr said. “The ones who do it, they love it and do not want to go back. But that first well is hard.”

In the short term, managed-pressure methods used offshore are likely to be similar to the ones used by many wells onshore. Based on equipment rentals, drillers in the US Gulf of Mexico are quietly adding equipment for better detection of kicks—influxes of fluids and gases that could lead to a blowout—and better managing downhole pressure using basic managed-pressure installations, said Don Hannegan, strategic manager for drilling hazard mitigation technology development at Weatherford.

This transition is not like switching on a light bulb. He compared the rate of change to using a dimmer switch to gradually increase a bulb’s brightness. He said 40% of US land drilling programs are using a basic closed-loop, managed-pressure drilling system today. By basic, he means a rotating control device (RCD) is used to divert fluid beneath the rig floor to a drilling choke, which allows the operator to apply backpressure, when needed, for well control. “I believe that within 10 years, 40% of offshore (shallow and deepwater) drilling programs will be, as land programs are today, drilling with a RCD and a dedicated choke manifold of some type,” he said.

One motivation for this is the need to find more accurate measures of fluid flow increases from wells to detect kicks. Measuring the level of fluids on a platform bobbing in the ocean comes with an error rate of 20 bbl or more. Managed-pressure drilling systems can detect far smaller variations, and the US offshore regulator, the Bureau of Safety and Environmental Enforcement (BSEE), is seeking improvements. “BSEE considers it very important to be able to accurately measure the mud return flow rate, which is critical in early kick detection, and is working with industry on technologies that will aid in this area,” said Lance Labiche, chief of BSEE district operations support for the Gulf of Mexico Outer Continental Shelf Region.

Backers of dual gradient said there is a limit to the problems that can be solved using the managed-pressure approaches used on land where there is no riser to contend with. Based on the attendance at industry meetings on dual gradient, there is growing interest in this approach. But as with many innovative ideas, there are few early adopters.

While Hannegan sees the potential benefits of full dual gradient with a mud pump located on the bottom, he asked, “How many deepwater rigs will be capable of doing that within the next decade, or are operators willing to pay for it?”

The cost of full dual gradient looks high until it is compared with the staggering expenses associated with developing deepwater fields where drilling costs commonly hit USD 1 million per day and a production well costing USD 200 million does not stand out.

To Robert Ziegler, head of wells and production technology for Petronas, the added cost of using dual-gradient hardware could be covered by being able to drill a series of difficult wells on time, with a hole that allows greater long-term production. “Time is everything and hardware is nothing in this world,” Ziegler said.

Cautious Steps

Based on that timetable, the adoption rate for dual gradient will be gradual, even compared with the unhurried pace commonly seen for new technology adoption in exploration and production. When Ken Smith, project manager of dual-gradient drilling implementation at Chevron, describes the future of the technology, he sees dual gradient as inevitable for deepwater drilling, but does not talk about timetables.

Regarding the dual-gradient equipment his company has been using in tests, he said it “has been performing well, and we remain extremely optimistic.” But he also cautioned that the company is working through a long list of tests to identify problems that need to be addressed. Those are being done while Chevron’s dual-gradient-equipped drillship continues to drill using conventional methods.

Many expect adoption of dual gradient to rise because conventional drilling has its limits. As the industry moves into places of deeper water and more extreme wells—the second dual-gradient-ready ship leased by Chevron is designed to drill a well down 40,000 ft in water 12,000 ft deep—the need grows for better ways to manage pressures while drilling.

During the OTC panel discussion, Smith said the industry is getting “closer to the wall” of what can be profitably drilled using current methods. Advances in drilling fluids, reamers, and expandable casing have allowed drilling in increasingly difficult formations, but “we are getting pretty close to the limits” of what can be done without dual gradient, he said.

“In the Gulf of Mexico, we are drilling some of the most technically challenging wells in the world. It is tough to get them down,” he said. Wells that were supposed to take 6 months to complete took 9 months. “It is not hard to do the math on what a 9-month well costs,” Smith said. Even worse, some wells are so difficult they are abandoned.

As the water gets deeper, it gets harder to drill wells because the difference between the pressure needed to control the well, and the amount that will fracture it, shrinks. “This is complicated by the fact that the friction pressures associated with circulating high-density drilling fluid up a small wellbore from 30,000 ft are tremendous. It simply gets worse with depth,” Smith said.

Chevron is seeking to widen the margin by moving the mud pump near the wellhead, expanding the window to what it would be on land, and also precisely measuring and managing pressure levels to stay within the limits. The rewards for full dual gradient include expanding the number of wells that can be safely drilled, reducing the number of delays, and, possibly, well plans resulting in larger, more productive holes.

Full or Partial

Chevron and Statoil are using different versions of dual gradient and have different goals in mind. The variety used by Chevron requires the largest commitment, starting with a drillship equipped to handle three large seawater pumps to drive a subsea pump capable of lifting the drilling fluid from the well up as much as 10,000 ft through a 6-in. pipe. The reward for bypassing the riser, which is filled with seawater-weight fluid during drilling, is the ability to use heavier mud and better control the pressure it exerts on the formation.

That is expected to allow well designs such as those found on land, which would sharply reduce the number of casing strings, allowing a larger hole at the bottom. A few added inches of diameter could be extremely valuable. Tight holes through a reservoir make it more difficult to do completions that maximize early production.

Statoil’s approach is less costly, as are the stated benefits. The EC-Drill places a pump on a joint in the riser that allows drilling fluid to be pumped out and sent up a line. The fluid level in the riser can be moved up and down by varying the pump speed that controls the bottomhole pressure by varying the pressure gradient in the riser. Tracking changes in the pump speed and the fluid level in the riser allows it to detect small variations in fluid flows.

But unlike Chevron’s system, where the pump is located above the subsea blowout preventer, its pump is located about 1,000 ft below the surface. The Norwegian oil company’s goal is to drill wells that could be drilled conventionally, but do it more efficiently.

“This system reduces our nonproductive time,” said Rognli of Statoil. “It will reduce the risks and the contingencies. Maybe today we have one or two contingency liners in the well plan.”

There is a significant reward for drilling wells according to plan. A six-well survey of recently drilled deepwater wells in the Gulf of Mexico found that the average one ran 20 days longer than planned, according to a recent paper presented by Morten Godhavn at OTC.

The Statoil system has a smaller footprint than the Chevron system and requires far less rig modification. “There is a much lower investment cost than with a full-blown dual gradient system,” said Odd Helge Inderhaug, leader of drilling and well technology in research, development, and innovation at Statoil. “One of the main advantages is the simplicity of it. It is a totally different level of complexity.”

“Chevron has talked about saving casing strings. We do not mention that. It may save casing strings but that is not the goal,” he said.

Every Time

Statoil appears to be the company likely to drill the first dual-gradient well in the Gulf of Mexico. It has applied for a permit with the BSEE, and Rognli is hopeful the regulatory body will approve it. “We are in close dialog with the BSEE. We have been presenting it with information and updates,” he said. “They are on top of the technical challenges and understand them. They have said they do not see any showstoppers.”

Labiche of BSEE said he could not speak to any issues related to reviews of dual-gradient technology or applications for permits to use dual gradient in the Gulf of Mexico.

Smith said Chevron is also working with BSEE officials to answer their questions. “This is the second well we have done testing on. We are still demonstrating the equipment and viability of our operating procedures,” he said. “Once we get comfortable with that, and more importantly the BSEE does, then we can get permission to drill a well.” Since a drillship normally drills a couple of wells a year, the initial use could slip into next year.

US regulators have recognized the problems created by shrinking drilling margins and the potential benefits of dual gradient. A 2011 US government backed study posted on the BSEE website said dual gradient can be “safe or safer” than traditional methods. A presentation by Labiche underlined the limits of conventional drilling methods, examining a growing number of deepwater wells drilled over the past decade in which drilling margins are at the minimum safe limit set by the agency. But he said operators need to make a case that they can deliver on the promise of dual gradient. He offered a check list of issues that need to be addressed to ensure the system can safely drill in the difficult conditions of the Gulf of Mexico.

“The top concerns are effective training and well control,” he said. “In the environment we are operating in, it will only take one mistake using this equipment and it will affect everyone in deep water, and prevent dual gradient from being the game changer it can be.”