Different dual-gradient methods enable drilling in deepwater, depleted reservoirs

Increasing pore pressures and fracture gradients in target reservoirs in the Gulf of Mexico have motivated Chevron to use a seabed pumping dual-gradient drilling method, Ken Smith, Chevron, said at the 2013 IADC DGD Workshop on 9 May in Houston.

By Joanne Liou, associated editor

Dual-gradient technology continues to gain attention as an important solution to deepwater drilling and extraction of resources from depleted reservoirs. Chevron is months away from deploying its dual-gradient system in the deepwater Gulf of Mexico, where the environment is largely characterized by increasing pore pressures and increasing fracture gradients, Ken Smith, manager of the dual gradient drilling (DGD) project implementation at Chevron, explained. “We’re really driven by the environment we’re drilling, the rocks that we have to drill. We’re motivated to change the physics behind our drilling,” he said at the 2013 IADC DGD Workshop on 9 May in Houston.

Nonproductive time is a major challenge, averaging up to 30% in the deepwater GOM, Mr Smith noted, adding that one-third of Chevron’s well costs go toward fighting NPT. “It’s getting worse as we routinely drill 30,000-ft wells, and we have leases in up to 20,000 ft of water.” This type of drilling environment is changing the playing field, and DGD will help overcome the challenges, he said. From a well design standpoint, DGD takes water depth out of the equation.

Chevron’s DGD system uses seabed pumping with positive displacement to open up tight pressure margins. “It improves the detection and reaction of the downhole challenges,” Mr Smith explained. “It restores the riser margin and remains overbalanced at all times.” With a restored riser margin, fewer casing strings are needed to reach TD.

In DGD, the fluid in the riser is replaced with seawater-dense fluid, setting up a pressure profile that is aligned with nature’s pressures. “We’re not fighting (natural pressures) as much as we do in conventional drilling,” Mr Smith said. “We enhance operational performance with the MPD capabilities of our system being closed and pressurizeable, which leads to improved well integrity and ultimately well productivity.”

Dag Ove Molde, Statoil, discussed the different types of dual-gradient systems that have been classified under the categories of pre-BOP and post-BOP.

While Chevron’s DGD is an example of seabed pumping, other methods of DGD also were discussed at the workshop, including Dag Ove Molde, specialist drilling technology for Statoil. The IADC DGD Subcommittee recently classified dual gradient systems into two main categories, pre-BOP and post-BOP. Mud-line pumping is one method under pre-BOP, while seabed pumping, dilution and controlled mud level fall under post-BOP.

Mud-line pumping is a riserless concept that has been deployed in the Gulf of Mexico and in the Norwegian sector, Mr Molde said. The system may consist of an interface on the seafloor, a subsea pump, a control system and a return conduit. Subsea pumps return the drilling fluid to the rig through a small-bore riser, which allows the mud to be used in the top sections of the well.

When mud inside the riser is diluted, injecting a lower-density fluid into the drilling annulus reduces the hydrostatic head of the circulating fluid. The mixing process results in the required density to achieve a constant bottomhole pressure, Mr Molde explained. Dilution is applicable from intermediate to deepwater operations.

Controlled mud level systems also use two fluids to control the wellbore pressure gradient. “The main usage is to control equivalent circulation density limitations,” Mr Molde said. The system can be placed at different levels in the riser to achieve variable control over the wellbore pressure based on fluid density and placement. Controlled mud level systems are applicable to intermediate water depth.

Dag Ove Molde, Statoil, discussed the different types of dual-gradient systems that have been classified under the categories of pre-BOP and post-BOP.

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Successful dual-gradient system follows nature’s pressure profiles

By Katie Mazerov, contributing editor

A dilution-based dual-gradient system dilutes the riser and creates a different pressure profile at the seabed.

A dilution-based dual-gradient system has been shown to deliver significant cost reductions and enhanced well control in deepwater wells. “This is an alternative way of creating a dual-gradient profile in the wellbore, not by means of pumping heavy mud from the seafloor up to the surface but by diluting the riser and creating a different pressure profile at the seabed,” said Luc de Boer, president of Dual Gradient Systems, which collaborated with Transocean in the development of the system. Mr de Boer discussed the testing process in a presentation at the IADC Dual Gradient Drilling Seminar on 19 March in Milan, Italy.

The premise of Transocean’s continuous annular pressure management (CAPM) system is based on using two stable mud densities in the wellbore, a specially designed centrifuge and a rotating control device (RCD) near the top of the riser below the slip joint rated to 1,500 psi.

The $5 million research and development project was conducted over a five-year period. The system is designed to follow the earth’s profiles – the ocean being low pressure and the earth being high pressure – rather than fight them, Mr de Boer noted.

“Initially, the system was designed conventionally, where heavy mud was pumped down the drill string through the bit and up the annulus,” he explained. When Transocean joined the project, the company suggested the use of an RCD to pump the mud. “At the bottom of the riser, the same mud without barite is injected into the return mud stream, creating a lower-density mud in the riser,” he said. An RCD at the top of the riser holds back pressure and directs flow to a choke manifold. Flow meters accurately track barrels in and out of the well. “The control device is at the surface, which also services as a very good safety feature,” he added.

Continuous separation

Testing began in 2002 with the concept to separate the oil-based mud into a high-density mud and a nearly un-weighted mud on a continuous basis. A second phase was launched in 2004 testing an oil-based mud and a water-based mud. In a third test in 2006, a special centrifuge unit with better capacity than a single centrifuge unit was deployed. The final test in 2007 achieved the desired separation process with a specially designed centrifuge that increased the flow from the normal pump rate of 50 gal/min to 600 gal/min, Mr de Boer explained.

In a comparative test in a deepwater Gulf of Mexico well, the conventional single-gradient well design included nine casing and liner seats to total depth (TD). The dilution-based, dual-gradient well design had six casing and liner seats, with a high-density mud weight of 12.8 lb/gal to 16.3 lb/gal, a riser mud weight of 9.9 lb/gal to 11.3 lb/gal and a dilution ratio of 2.4 to 3.1. “The reduction in casing strings, at $10 million per string, is significant,” Mr de Boer pointed out.

A third scenario featured a dual-gradient drilling (DGD) design with dilution below the mud line. The system resulted in four casing and liner seats, with a high-density mud weight of 17.3 lb/gal, riser mud weight of 10.9 lb/gal and a dilution ratio of 2.9. “We call this the prize,” Mr de Boer said. “This design takes more work to get the dilution below the seabed, but it gives us extended reach.” The dilution-below-mudline system also can be used for low-cost open-hole sidetracks and for low-cost exploration drilling.

With the DGD dilution system, all equipment is on the surface and can be repaired with little downtime; the CAPM riser system and flow controls enhance well control. The system also can be switched from dual-gradient to single gradient in an hour if necessary, Mr de Boer said.

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The essentials of dual-gradient drilling: Several variations under development

By Linda Hsieh, managing editor, and Katherine Scott, editorial coordinator

Although dual-gradient drilling has been around for years, many in the industry appear to remain unclear as to how the technology works or what it does. In a presentation at the 2012 IADC Dual Gradient Drilling Seminar on 19 March in Milan, Italy, AGR Subsea senior technology advisor Roger Sverre Stave reiterated IADC’s definition of dual-gradient drilling as a variation of managed pressure drilling that uses “two or more pressure gradients within selected sections to manage the well pressure profile.”

Roger Sverre Stave, AGR Subsea, noted that a significant industry focus on dual-gradient technologies has led the IADC Dual Gradient Subcommittee to take on many new initiatives, including organizing the 2012 IADC Dual Gradient Drilling Seminar on 19 March in Milan, Italy.

Whereas in conventional drilling, bottomhole pressure (BHP) is a function of single-gradient mud, dual-gradient methods make up BHP “based on multiple columns of fluid such that bottomhole pressure is a sum of two or more columns of fluid,” Mr Stave said.

“As long as the pore and frac pressures are increasing with depth, you will create a pressure gradient this is more compatible than pore pressure and frac pressure by introducing dual-gradient technologies,” he said. Effectively, dual-gradient drilling opens the “drilling window” by increasing margins. The technology also provides opportunities for faster recognition of instability, including loss and influx, as well as faster response to reestablish pressure balance.

Several variations of dual-gradient technology are under development within the industry, such as controlled annular mud level technologies and mudline pumping riserless technologies. Dual-gradient mudlift is another example, which is expected to be deployed by Chevron later this year in the deepwater Gulf of Mexico (GOM). Statoil too plans to deploy “light” versions of two variations of dual-gradient drilling in a pilot project in 2013, according to a separate presentation at the same seminar by John-Morten Godhavn, principal researcher for Statoil.

“And we have other technologies that create the dual-gradient effect by diluting and lightening the gradient in annulars of the drilling riser either by gas or fluid,” Mr Stave added.

Dual gradient goes back to as early as 1975 with the Howell patent and has been studied under various joint industry projects through the years, such as the MudLift JIP with ChevronTexaco, Conoco, BP and Hydril, and DeepVision with BP, ChevronTexaco, Transocean and Baker Hughes. “Shell SubSea Pumping system was also one major effort at the time with a seawater-filled riser but also having a separator system on the seafloor to pump out the solids and leave the cuttings behind on the seafloor,” Mr Stave said.

While only the MudLift JIP made it through to a successful field trial in 2001, Mr Stave notes that the need for dual gradient technologies has certainly not disappeared, particularly with the growing importance of the ultra-deepwater market in the GOM. “What I have seen is more industry focus along with various initiatives post-Macondo, but more related to safety now than previously when it was more focused on drilling efficiency,” he said.

Further, Mr Stave believes that ultra-deepwater leases and advanced drilling rigs may require dual-gradient drilling as an enabling technology going forward, meaning that it is impossible or very hard to drill those prospects without the dual-gradient drilling technique to manage the equivalent circulating density or dynamic friction loses. The technology allows the pressure gradient to fall more naturally within the pore and frac pressures of the well, he said.

Mr Stave acknowledged that dual-gradient technologies have been difficult to commercialize due to the investments required, as well as equipment integration issues. However, the concept remains on the agenda for many companies who are seeking to develop ultra-deepwater resources. “We are moving forward and we are making progress, but it takes a long time to implement these kinds of technologies.”

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