View to a drill

Dual gradient drilling (DGD) has been discussed for some time as the future of deepwater operations. Touted as a game-changer, it is suitable for difficult or otherwise undrillable wells and could open up many new possibilities for the industry.

The concept itself is relatively straightforward. It is a form of managed pressure drilling, which, according to the IADC’s definition, involves creating “two or more pressure gradients within selected sections to manage the well pressure profile”.

In other words, the bottomhole pressure is the result of several columns of fluid, rather than the single column you would create using conventional drilling methods.

Although the idea goes back decades, it is only over the past few years that the technique has begun to take off. In 2014, delegates at the Offshore Technology Conference in Houston, debated whether DGD was ready for ‘prime time’. While conceding that widespread adoption would not come easily, they agreed it was becoming necessary.

“It’s changing the way wells are designed,” said Frederic Jacquemin of Pacific Drilling at the conference. “It’s not done for fun, it’s a question of survival, to ensure that the well will be there in ten to 15 years’ time.”

At the time of the conference, a few oil companies had begun to make strides in this area. Chevron and Statoil had tested the technology in the Gulf of Mexico, GE Oil & Gas was working on developing new techniques and Petronas and Petrobras were adopting managed pressure drilling in some offshore wells.

The industry, then, seemed on the brink of embracing DGD. As participants stressed, the industry was approaching the limits of what could be drilled using conventional methods.

“We’re much closer to the wall now, so for us, it’s time to change the game entirely,” said Chevron’s Ken Smith at the OTC panel discussion.

Slow but steady

Over the subsequent four years, adoption has continued at a slow, but deliberate, pace. On top of the various wells already drilled, there are new applications every year and numerous prospects on the horizon.

“The industry is gaining more experience and more success stories, and this will definitely help,” says Per Cato Berg, advisor managed pressure drilling at Statoil. “Interest seems to be increasing, although it’s still quite slow.”

In his role at Statoil, Berg has been working with managed pressure drilling related issues for the past 12 years. His job is to support the drilling operations that are using managed pressure and dual gradient technology.

As he explains, Statoil has implemented two kinds of dual gradient technology to date.

“The simplest and most common form of dual gradient drilling is used for topholes,” he says. “For that, Statoil installs a pump on the sea bed that is used to transport the returns from the seabed to the drilling rig through dedicated holes. This enables a weighted drilling fluid to be used and can be very beneficial for drilling unstable formations in the top.”

The other variant is called controlled mud level (CML) drilling and is used after the BOP and marine riser is installed. This is suitable for drilling reservoir sections, with subsea pump placement from 500 to 1,500ft below sea level.

“A pump is installed on the marine riser and it returns the drilling fluid to the rig through a return line that is integrated on the riser,” explains Berg. “The speed of the pump then manipulates the mud level in the riser, so the top of the riser is then filled with air while the rest is filled with weighted drilling fluids. This way, the pressure in the bottom of the well can be manipulated.”

There are various other forms of DGD, which can be modified according to the well in question. Some wells use a mud dilution method, for instance, while others inject an inert gas like nitrogen into the riser. According to the IADC Dual Gradient Drilling Subcommittee, dual gradient systems can be classified in two main categories – pre-BOP and post-BOP – with CML falling into the latter.

Keep gas at bay

The first DGD well came in 2001, when Chevron, Conoco, BP and GE Oil & Gas (then Hydril) completed a joint industry project in the Gulf of Mexico. The project in question – the Subsea MudLift JIP – had taken five years and nearly $50 million, making it one of the largest and most significant JIPs in history. It comprised a subsea mud lift pump situated on the seabed, along with a subsea rotating diverter that minimised the influx of gas into the riser.

This prototype was designed with a clear goal in mind – to provide a total solution for DGD in terms of hardware and methodology. Intended to manage the problems associated with ultra-deepwater drilling, the MudLift would enable drilling at water depths up to 10,000ft. This would mean tapping into previously inaccessible oil and gas reserves.

While the project was successful, the technology was set aside for a number of years, and it wasn’t until 2008 that the industry decided to revive them. That year, Chevron set to work on building a full-scale version of the prototype, which was loaded onto the Pacific Santa Ana in 2013. The core technology, now owned by GE and rechristened the MaxLift 1800 Pump, enabled the ship to operate in water depths of 12,000ft and drill 40,000ft into the earth.

Statoil, meanwhile, set to work using dual gradient technology in Norway and the Gulf of Mexico. Its Scandinavian operation, on the Troll field, came in response to challenges with mud losses.

“Statoil started using controlled mud level on the Troll Field in 2014,” says Berg. “The Troll reservoir was depleted, and losses were experienced even when during drilling with very low mud weight. The CML system was therefore used to enable drilling with even lower bottomhole pressure, reducing the mud losses significantly.”

The company used a technique called EC-Drill, billed as enabling operators to ‘drill the undrillable’. Statoil reduced its mud consumption by around 70%, compared with conventionally drilled wells.

Later that year, Statoil became the first operator to deploy dual gradient technology in the US part of the Gulf of Mexico. Its CML system is slightly different to Chevron’s: while Chevron’s system involves filling the wellbore with drilling mud up to the seafloor, Statoil’s involves attaching a pump to a riser 1,100ft below the surface.

Of the two approaches, Statoil’s is slightly simpler and involves less rig modification.

“Statoil used the controlled mud level system on the Maersk Developer rig to drill four deepwater wells in the Gulf of Mexico,” says Berg. “It used it to drill parts of the salt section, and most importantly, when it drilled to the base of the salt where the pore pressure uncertainty is largest.”

Berg says this type of dual gradient system was chosen for a simple reason: the risk reward picture was favourable to Statoil’s applications.

“It’s a fairly simple technology that brings several large benefits,” he says. “On the Troll Field, mud losses have been significantly reduced, and the four wells in the Gulf of Mexico were drilled with excellent efficiency.”

He adds that dual gradient technology has the potential to bring many broader benefits to the industry. In particular, it stands to improve well control and slash non-productive time.

Constant bottomhole pressure

“One of the main challenges with deepwater drilling is the narrow window between the pore and fracture pressure,” he says. “This small window often results in well control incidents, losses, and non-productive time. CML enables you to drill with a lower bottomhole pressure than you otherwise would be able to and keep that bottomhole pressure constant. This helps reduce all these risks and ensure the well’s integrity.”

On top of that, CML enables better responsiveness. Operators can quickly change the bottomhole pressure in reaction to changing conditions in the well, re-establishing the pressure balance even as drilling is going on.

With so many advantages, why has adoption remained so slow?

“Being a first mover is always challenging,” says Berg. “CML involves a quite large conceptual change to the drilling process, so it’s natural that there’s some scepticism.

“Implementing technology like this requires rig modifications, new equipment and changes to a lot of procedures, so there’s a lot of planning involved. There’s also of course a cost element that can’t be ignored.”

The actual savings may prove tricky to calculate. Although the price is undeniably high, there will always be a trade-off between the overheads and what it enables you to accomplish. In many cases, the reductions in nonproductive time will equate to savings overall.

“There is, of course, some extra cost involved in preparing the rig, and of course there’s some operational cost involved, so that limits the use of wells with extra challenging conditions,” explains Berg. “The savings will vary greatly with each application – on some wells the savings will be marginal, and on others the technology will make the well drillable.

“Dual gradient is something you implement where you believe you can solve a specific challenge on a challenging well.”

For these reasons, we probably can’t expect to see a rush of dual gradient wells cropping up over the next few years. According to most estimates, the industry could take up to 20 years to make full use of dual gradient.

It is nevertheless likely that a point will be reached where no other technique will suffice. With operators forced to tackle ever more challenging wells, conventional drilling methods may not seem up to scratch.

As one of the pioneers in the field, Statoil plans to keep building on its early experience.

“The technique is still quite new so we are first and foremost optimising the equipment and the procedures to operate as safely and efficiently as possible,” says Berg.

“Statoil is currently finishing the preparations for implementing CML on the two new semi subs it has drilling on the Troll Field, Songa Equinox and Songa Endurance.”

He believes that these types of systems are likely to be included in the rig package in future, so that when the rig is contracted it will come with the necessary equipment ready to use.

“The rig contractors have the expertise of operating similar equipment and are responsible for well control, so it will be beneficial if they take ownership of these types of system,” he says.

“As the industry gets more experience, the hurdles that must be crossed will get smaller, and we will see a more widespread adoption of dual gradient.”