Chevron and Statoil are launching new solutions to a growing challenge in the Gulf. Bruce Nichols reports.
The GE (Hydril) MaxLift pump aboard the Pacific Santa Ana drillship. Photos: Pacific Drilling.
After decades of theorizing and experimenting, the Gulf of Mexico is about to see the commercial application of two proposed solutions to a problem that is worsening as waters and wells get deeper: narrowed or non-existent “drilling windows” between pore pressure and formation strength.
Chevron’s solution is dual-gradient drilling (DGD) using the purpose-built Pacific Santa Ana drillship and the GE (Hydril) MaxLift pump placed on the seabed. The system will undergo testing in an upcoming exploration well.
Statoil’s solution is different, but relies on the same principle. Dubbed ECD-M, for equivalent circulation density management, it is controlled-mud-level drilling with the mud return pump built by Enhanced Drilling (AGR) placed part way down the riser rather than on the seabed. The system is slated for its first Gulf run at Statoil’s Perseus prospect in De Soto Canyon Block 231. Statoil expected to spud Perseus by the end of 3Q 2014.
There have been variations on the dual-gradient, managed-pressure-drilling theme since the 1960s, including joint industry projects, several tests and a number of partial applications on the Norwegian Continental Shelf, the Gulf of Mexico, offshore Asia, and Cuba. But the commercial imperative wasn’t there to force widespread adoption.
“Dual-gradient has always been the dream of any educated deepwater drilling engineer,” said Robert Ziegler, general manager of engineering services drilling at Cairn India, and a pioneer who has run his own tests of an AGR system offshore Cuba. “When you design your wells, you realize that the biggest problem you have is the water column and the need (in conventional drilling) to have a single fluid from the surface to the zone you want to control,” Ziegler said.
The mud between the seabed and the surface, necessary in single-gradient drilling, shrinks the drilling window – the margin between pore pressure and formation strength – and drilling starts “with one hand tied behind its back,” as Ziegler puts it.
The Pacific Santa Ana drillship at Chevron’s Anchor prospect in Gulf of Mexico.
Now, with wells getting ever deeper and more difficult to drill, there may be a stronger business case for change. Chevron’s project manager for dual-gradient drilling implementation, Ken Smith, outlined the challenge at the 2014 Offshore Technology Conference (OTC). Starting 15 years ago, narrowing windows began creating problems for drilling conventionally, most notably by requiring many more casing strings, each one narrower than the previous one, resulting in cementing troubles, tight down-hole tool tolerances and narrower-than-desired completions.
“Today, it’s only gotten more challenging. We routinely drill nearly ‘un-drillable’ wells,” he said, citing wells more than 30,000ft in total depth drilled in waters more than 6000ft deep with mechanical risk indexes above an astronomical 9000. The newest rigs are now capable of drilling to 40,000ft, capability that will be needed to reach the industry’s growing portfolio of ultra-deepwater projects. But the technological advances that have enabled drilling beyond 30,000ft are less effective deeper down, he said. “We are nearing their limits to deliver today’s oil targets in deepwater,” Smith said. “It’s time to change the game.”
Mud weight versus pore pressure, fracture gradient
The basic problem is that the weight of the drilling fluid in the wellbore must stay within limits as the drill bit passes through varying geologic strata on its way to target depth. If the mud weight is too heavy, it can fracture a formation and cause collapse of the wellbore as mud flows out into the neighboring strata, a phenomenon called “losses.” If the mud is too light, it can’t prevent uncontrolled intrusion of water, oil or gas into the wellbore, a phenomenon called “kicks.”
If mud weight becomes too heavy or too light, as the well deepens from one strata to another, drilling has to stop and casing has to be cemented in to stabilize the hole, taking up drilling time and money.
Generally, in conventional single-gradient drilling, the deeper the well, the more casing strings have to be set. And because each string has to pass through the previous one, the casing – each string of which extends all the way to the surface – shrinks in diameter as the well deepens. This could mean the well can’t reach the target zone at the desired diameter, making the production string too small to produce economically, and the well, in effect, un-drillable.
Dual-gradient or managed-pressure drilling offers a way forward. If the mud level in the marine riser can be dropped, the pressure gradients in the wellbore start at a lower level, in effect widening the drilling window.
In the Chevron-Pacific DGD case, the relevant gradients start at the seafloor. In Statoil’s ECD-M, gradients while drilling can start as deep as 1100ft below the surface, the depth at which Statoil has chosen to place its pump in coming tests. In both cases, the mud load is lighter.
The Chevron system fills the wellbore with drilling mud up to the seafloor. There, the MaxLift pump circulates the mud back to the surface via a separate mud return line. The riser from the seafloor to the rig is filled with seawater equivalent weight fluid – eliminating the additional mud weight.
Statoil also uses a pump and mud return line, but the pump is attached to the riser 1100ft below the surface. Mud fills the riser up to a level set by the pump and then circulates up a mud return line to the surface. The rest of the riser is filled with air, which does not require a handling system.
“We don’t call it dual gradient. It’s zero gradient because there aren’t two fluids,” said Uno Holm Rognli, Statoil’s vice president of drilling and wells for the US offshore.
The Enhanced Drilling (AGR) pump on the COSL Innovator semisubmersible at Statoil’s Troll Field off Norway. Image: Enhanced Drilling.
Different goals lead to different systems
The difference in systems is because Statoil and Chevron are coming at the problem from different starting points. Chevron wants to maximize the window and reduce the number of casings or intermediate liners required.
Statoil’s goal is more modest: to stay within the narrow window that is available by eliminating fluctuations between static and dynamic circulating pressure, an issue in conventional drilling. If it saves having to install extra casings or liners, that’s an added benefit. “We want to simplify it,” Rognli said.
Statoil engineers chose 1100ft for the pump depth because they consider that adequate for now. “We could put it deeper, but it would mean a longer umbilical, a longer mud return line. So everything gets more expensive,” Rognli said. Deeper placement of the pump is under study, but “we are starting carefully,” said Roger Stave, senior technology advisor to Enhanced Drilling.
In both the Chevron and Statoil systems, the drilling window, in effect, starts closer to the seabed rather than at the surface, reducing the impact of water depth. It’s almost as if the rig were on land.
Statoil employs centrifugal pumps in a series of three, attached to the riser. “We’re using the same pump as those used for riserless mud return (RMR), and they have been around several years, on a lot of wells,” said John-Morten Godhavn, a Statoil researcher and managed pressure drilling specialist.
Riserless tophole drilling, Ziegler says, is – in essence – the oldest dual-gradient approach because there is no marine riser. But it is unusable for taking a well to total depth. Chevron’s seafloor-based MaxLift pump is quite different. It is an innovative positive-displacement powered by seawater.
GE MaxLift pump key to Chevron DGD
|Source: Chevron, Design by Bruce Nichols|
The GE MaxLift pump has six, 80gal chambers, each divided by a diaphragm. Seawater pumped from the surface provides hydraulic force to move the diaphragm back and forth, alternately pulling mud from the well and pushing it to the surface. The system can achieve 1800gal/min. Powering it with seawater minimizes electrical equipment sitting several thousand feet underwater. There are still electronics involved, as the valves that open and close, directing flows of mud and seawater, are electronically controlled.
Both systems are more than just pumps and return lines. In the Chevron-Pacific system, the pump is placed atop the lower marine riser package. A solids processing unit (SPU) sits atop the pump to ensure that solids are small enough to pump without plugging the mud return line. A subsea rotating control device sits above the SPU, providing a mechanical barrier between the wellbore and the riser. It allows temporary over-balancing during system operations, while protecting the wellbore from pulses that could “break the window” downhole.
The Pacific Santa Ana – purpose-built for DGD – has three separate fluid systems, one for handling drilling mud, another for the seawater-like fluid in the marine riser, and another for the seawater powering the pump. The moon pool was redesigned for handling the 450,000lb MaxLift pump in addition to the usual subsea equipment.
The Statoil system – designed for retrofitting on existing rigs – uses Enhanced Drilling’s 29,000lb EC-Drill controlled-mud-level system, modified riser joints, MPO’s Delta Seal Riser Module with quick closing annular, a riser gas handler system, and Coriolis sensors for early kick detection.
Whereas Chevron’s business case revolved around drilling in ultra-deepwater, Statoil had two goals – to drill more efficiently in ultra-deepwater and to extend the life of fields in shallower Norwegian waters. Both Statoil goals require overcoming bottomhole pressure issues, but in the case of mature fields offshore of Norway, the problem is that years of production have sharply cut formation pressures and increased mud-loss incidents.
Statoil’s Enhanced Drilling system meets two needs
At the Troll field last March, Statoil used an ECD-M retrofitted semisubmersible, the COSL Innovator, to drill a depleted formation, punching a horizontal well 12,500ft and reducing mud losses 75%. “Troll came up as a kind of first use because they had a special need,” Rognli said. “What they are using is this system to take down the mud level in the riser, to drill with lower pressure, still using water-based muds.”
Maersk Developer at Statoil’s Martin prospect with Mars and Olympus on the horizon behind. Image: Bruce Nichols.
Troll is in relatively shallow water, at just over 1000ft deep, so the pump in the ECD-M system could be placed close to the seafloor, filling most of the riser with air. “We pulled the fluid two-thirds of the way down the riser, and we got an effect greater than if you’d filled the riser with seawater to the seafloor,” Stave said.
An advantage of the Chevron system is that, should the marine riser part for some reason and mud circulation be lost, the mud in the well is sufficient to maintain control, acting as a fail-safe.
Statoil considers its system fail-safe as well, but for different reasons. Its risers are equipped with dual annular sealing devices, which can be activated quickly to trap pressure should a sudden loss of circulation arise.
“But the annulars are not part of well control. We add the annulars to avoid getting into well-control situations. If a well-control situation arises, then we will isolate the riser and our controlled mud level system by closing the BOP and handle conventionally,” Godhavn said.
Both Chevron and Statoil say they are proceeding step-by-step and that full implementation of their systems will unfold gradually. “We are going slow to go fast,” Jacquemin said.
The Chevron-Pacific and Statoil systems were a hot topic at OTC. The title of one panel session was, “Is Dual Gradient Drilling Ready for Prime Time?” The answer appears to be “yes,” assuming regulatory approvals and successful demonstrations in the Gulf of Mexico.
“Oil has never been easy, but it’s certainly getting more and more difficult to find and access, and the technology that makes it easier is usually welcome, especially now that you have different techniques, different price ranges, different people helping the technology develop,” Jacquemin said.
He mentioned Weatherford, which has the back-pressured managed pressure drilling system that Statoil has used off Norway. Weatherford also contributed the subsea RCD to the Chevron-Pacific DGD system. Jacquemin also mentioned Transocean, which offers a system called Controlled Annular Pressure Management (CAPM). That system was ready for a test in the Gulf, until the Macondo disaster forced a delay, Jacquemin said.
“It’s no longer about theory. It’s really happening,” Jacquemin said. “Now we’ve drilled. We can show pictures. We go to conferences and talk about case studies. It’s exciting.”