Dual-gradient drilling (DGD) systems being considered today encompass three fundamentally different approaches — seabed pumping, dilution methods and mid-riser pumping. “Every one of these approaches has different applications and pros and cons,” Ken Smith, manager of dual gradient drilling project implementation for Chevron, said.
Defining elements of DGD, an overarching definition of DGD and a discussion of projects under development were presented at the IADC Dual Gradient Drilling Workshop on 5 May in Houston. Mr Smith set the stage for representatives from Statoil, Chevron, Petronas Carigali and Transocean to offer perspectives on the benefits of DGD and barriers to implementation.
For purposes of the workshop, the IADC Dual Gradient Drilling Subcommittee’s definition of DGD was used as a basis for discussion; DGD is a subset of managed pressure drilling and is not underbalanced drilling. Specifically targeting subsea applications, DGD is the creation of multiple pressure gradients within select areas of the annulus to manage the annular pressure profile. Methods include use of pumps, fluids of varying densities or a combination of these.
Within the seabed pumping category of DGD there exists subsea mud lift drilling, an active project within Chevron, and controlled mud pressure, an active project within AGR. Historically, subsea mudlift drilling projects had been attempted about 10 years ago with the Deep Vision project, a JIP between Transocean, Baker Hughes, Chevron and BP; there was also a Shell Subsea Processing System that originated about 10 years ago.
Within the dilution category, Transocean is working on a system called continuous annular pressure management. Another effort involves a liquid that’s heavily loaded with hollow glass spheres and one that involves diluting the riser with nitrogen.
Within the mid-riser pumping category, Ocean Riser Systems is working on a low riser return system. A past effort in this category was Delta Vision, a mid-riser version of the Deep Vision project.
Mr Smith noted that Chevron is focused on a seabed pumping type system because the company is drilling deep and challenging wells in the Gulf of Mexico. “I’ve had a lot of mechanical problems. We’re chasing dual gradient to eliminate casings. Now that we’ve discovered subsalt, our motivations today are greater than ever before. The trend is getting more challenging,” he said.
The panel, comprised of Mr Smith; Dag Molde, principal engineer for Statoil; Robert Ziegler, head of deepwater drilling technology for Petronas Carigali; and John Kozicz, technology manager for Transocean, agreed upon the benefits of DGD regardless of the type of DGD selected.
Benefits include a much better detection of kicks; inherently safer wells because the riser margin can be restored; a better footprint from fewer strings of casing needed; reduced cost and risk from eliminating ECD ballooning; better cement jobs and completion integrity from the ability to open clearances; opportunity for improved well productivity as a result of potential designer completions; and tighter control of the well.
Presenters agreed that barriers to DGD implementation are the same as that for any energy industry technology and include resistance to change, perception of an increased risk profile, perception of limited scope for implementation, perception of a weak business case and competition for required resources such as time, money or personnel. On the route to commercialization, there are chasms into which technologies can fall and from which they may or may not recover momentum.