Dual-gradient drilling (DGD) is gradually making the ‘undrillable’ drillable by taking away the impact of water depth on offshore operations. But it remains a very young technology and the challenges ahead before it becomes the norm – if indeed it ever does – are many and include costs, changes in operators’ procedures, personnel training and regulators’ attitudes.

"It is always difficult to introduce a new technology to the industry," says research and development technology manager at AGR Enhanced Drilling, John Cohen, who has delivered seminars and workshops on DGD for the Society of Petroleum Engineers (SPE) and International Association of Drilling Contractors (IADC).

"This is compounded for the offshore industry, due to the high costs. In addition, regulatory agencies hold back development when there is any question of safety, founded or not."

Cohen illustrates his point by referring to a presentation on the process of taking technology from development to commercialisation that was given by Charlie Weinstock, (ex-Chevron) in May 2011 at an IADC DGD workshop.

"Weinstock talks about gaps or chasms that must be crossed," Cohen says. "To cross these chasms, companies need a champion company to fund and provide a proving ground for the technology. This requires a commitment that is very hard to achieve, especially in a large company. Combine this with the risk of failure and you have a job getting new technology adopted."

Nonetheless, 2012 saw Chevron start operations on the Pacific Santa Ana, the first drillship able to perform DGD, in deepwater Gulf of Mexico and more DGD-capable drillships are set to follow.

"The technology is now commercial or being developed to drill in currently undrillable areas," Cohen remarks. "So I think DGD is on its way."

The pressure at the seabed, created by the denser mud in the riser, is higher than the pressure created by the seawater surrounding the riser, and this difference in pressure creates drilling problems.

The basics: what is DGD and how can it enhance offshore drilling operations?
DGD is a fast-evolving branch of managed-pressure drilling (MPD), which removes the impact of water depth on offshore drilling, thereby making reservoirs as deep as 40,000ft below the sea floor, which were previously thought to be undrillable.

"DGD is often explained as putting the rig on the sea floor and in a very real sense this is true," Cohen summarises.

In land drilling, the density of the drilling fluid is selected to achieve the desired bottomhole pressure (BHP) to drill the well, with many factors going into determining the needed BHP and the correct mud density. "The pressure gradient starts at the top of the well where the pressure is equal to one atmosphere (the weight of the air above us) and rises with increasing depth until the bottom of the well, resulting in the required BHP," Cohen explains.

When it comes to offshore drilling, the gradient starts at the top of the riser and increases to the well bottom, again resulting in the required BHP.

"However, the pressure at the seabed, created by the denser mud in the riser, is higher than the pressure created by the seawater surrounding the riser, and this difference in pressure creates drilling problems," Cohen explains.

DGD solves this by filling the riser with seawater (or a fluid of the same density as seawater) and then fills the well with the density of mud to give the proper BHP – just like in land drilling.

"To do this, the heavy mud in the well must be pumped from the sea floor back to the drilling vessel, so the weight of this heavy mud is not placed on the well," Cohen notes.
So why is DGD a particularly useful drilling method for reaching reservoirs previously thought unreachable? It really depends on the form of DGD you’re talking about says Cohen.

"The sea-floor-based pumping system is one way to do DGD," he explains. "Another way is to pump fluid from the riser three quarters of the way to the surface back to the vessel and drop the fluid column in the riser near this point; this DGD method is named ‘controlled annular mud level’.

"The riser will now be filled with air or gas from this point up. The air or gas is much lighter than seawater and the resulting pressure gradient can now be the same with the pumping system shallower than ‘mid-water’. In many cases, particularly in shallow to medium water depth, one can even create a pressure gradient beyond what is possible with a seawater-filled riser."

Either way, there is one key benefit to DGD: "By better matching the pressure gradients in the wellbore to the natural pressure gradients, the well sections can be drilled deeper before a casing string must be set to close off and protect the wellbore from the pressures in the well," says Cohen. "This can result in significant savings by eliminating casing strings and saving time on the rig to run and cement the casing."

Some dual-gradient methods can also compensate for equivalent circulating density (ECD), which is the added pressure on the bottom of the well due to friction between the flowing drilling fluid and the well bore.

"In deep wells drilled in deepwater, the drilling window between the pore and fracture pressure gradients can be very small. The ECD can cause the BHP to go outside the window making the well undrillable," Cohen explains.
DGD also allows drillers to detect downhole pressure changes more quickly, enhancing safety and efficiency.

Strategic decision-making
Despite the obvious advantages of DGD, implementing such a disruptive technology, which requires operators to invest in new infrastructure, equipment, procedures and training on a large scale, is no easy task. Yet, by following the example already set by Chevron, Cohen certainly believes it is possible.

"Where the industry is now, the primary challenge is the decision-making process within the operator’s organisation," he says. "And Chevron’s strategic decision to implement dual gradient is a perfect example of how it can be made; one has to look at the impact the technology will have on the business from a risk and safety standpoint as well as drilling efficiency."

Other challenges that will be faced, he believes, include the cost of installing the infrastructure to support the equipment necessary to conduct DGD operations; the need to develop new procedures and train personnel to handle the changes in well control and operations; and showing regulators that DGD is as safe if not safer than conventional drilling.

"All these things cost money to implement, and operators that believe in the technology and are willing to pay for it are needed to move forward with DGD," Cohen stresses.

"Operators must evaluate the technology and then develop the business case to implement DGD on their wells. Then a strategic decision has to be made to implement this on a broader front – not on a single-well basis."

One has to look at the impact the technology will have on the business from a risk and safety standpoint as well as drilling efficiency.

Chevron: leading the way
In 2012, Chevron announced that the Pacific Santa Ana, a deepwater drillship built to the company’s specifications and the first ever designed with the capacity to perform DGD, had arrived in the Gulf of Mexico to work for Chevron under a five-year contract with a subsidiary of Pacific Drilling. It can drill in 12,000ft water depth, 40,000ft into the earth.

The ship is equipped with a DGD riser, a mud-lift pump-handling system, six mud pumps – three for drilling fluid and three for seawater – extensive fluid-management system enhancements and more than 72,000ft of DGD-related cables, with GE Oil & Gas’s MaxLift 1800 Pump at the heart of the system.

GE’s system works as follows. To achieve a dual gradient, flow from a well being drilled is diverted to the MaxLift 1800 pump, which is located above the blow-out preventer and pumps the cuttings-laden mud back to the drilling vessel using an auxiliary line.

The riser is then filled with seawater-density fluid, so the reservoir ‘feels’ as if the rig is located on the seabed since the MaxLift pumps prevent the hydrostatic pressure of the mud from being transmitted back to the wellbore.

Clearly, the equipment on board the Pacific Santa Ana involved no small investment, but for George Kirkland, vice-chairman of Chevron Corporation, it was necessary to move the industry forward.

"Pacific Santa Ana will enable us to demonstrate dual-gradient drilling, which has the potential to change the way deepwater wells are drilled," he said. "This new process builds on our record of technology leadership in deep water."

The Pacific Sharav, which was delivered in May 2014 from Samsung Heavy Industries and is currently mobilising to the Gulf of Mexico where the rig will work again for Chevron under a five-year contract, is also DGD-capable, and has incorporated learnings and improvements from the Pacific Santa Ana.

DGD: the future of offshore drilling
Looking to the future, Cohen still believes there will be bumps along the way as the industry moves towards a point where DGD could become commonplace.

"A severe mistake could set the technology back years," he warns. "And this means that those involved must be extra vigilant and take the time necessary to develop the technology without mistakes."

Yet, there’s no doubt that DGD can make the previously undrillable, drillable, Cohen concludes. "As we push deeper into water and well depths, the number of undrillable wells will increase, so DGD represents the future for offshore drilling.

"I also believe that DGD improves safety; so as it becomes more accepted and we learn to use it, I think we will have a safer industry."