Dolphin Drilling unveils new deepwater drillship

Posted on 19 June 2013

Dolphin Drilling recently unveiled its new deepwater drillship, the Bolette Dolphin. The rig is equipped to operate in 12,000 ft of water with a maximum drilling depth of 40,000 ft.

Aberdeen-based Dolphin Drilling, one of the oldest and largest independent drilling contracting companies in the North Sea, unveiled its new 751-ft ultra deepwater rig, Bolette Dolphin, at a naming ceremony at the Hyundai Heavy Industries Shipyard in Ulsan, South Korea, where it is currently being built.

The drillship, designed for efficient deepwater drilling and completion activity, will start work for Anadarko Petroleum Corporation later this year and has been contracted for a four-year international campaign.

“The naming ceremony of the Bolette Dolphin hails a key step in the company’s strategic development with a deepwater focus, directly in line with industry demands as exploration and production continues to push to ever deeper depths. The ship marks a significant investment for the group and will be one of the most advanced deepwater drillships in the market,” Graeme Murray, managing director at Dolphin Drilling, said.

“Equipped to operate within 12,000 ft of water, with a maximum drilling depth of 40,000 ft, we are confident it will deliver favorable results for Anadarko and its major exploration campaign.”

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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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Operational experience, contingency planning fill gaps in deepwater cementing

By Joanne Liou, editorial coordinator

Ragheb Dajani of Hess Corp provided an operational perspective on using cement as a primary barrier in deepwater wells at the 2012 OTC on 30 April in Houston.

Two questions need to be asked when considering cement as a primary barrier in a deepwater well: 1) Will the job be successful? 2) What if it isn’t? The two considerations beg to question and validate the prospect of a successful cementing operation. Ragheb Dajani of Hess Corp shared an operational perspective on cementing during a keynote speech at the 2012 OTC on 30 April in Houston. “There is a definite increase in recognition and scrutiny on the profound effects cementing can have on operations – on safety, environment and public opinion,” he said, “but the gap is in installing the cement as the barrier downhole.”

On paper, a lot has been done to support cement designs; however, there is uncertainty in effectively executing the operation.

It is important to understand the risks of a cementing operation and to approach it from a perspective that realizes the consequences of failure, Mr Dajani explained. A key challenge is in the cementing design, and the first step is to determine whether cement can realistically provide a barrier. “We can’t always rely on cementing unless we have a high degree of confidence to execute it and to provide a barrier downhole,” he said. “As we go deeper and deeper into the reservoirs, we’re asking for a small volume of cement to travel four or five miles. Yes, we can do that, but there is a lot of work that needs to be done ahead of time in order to protect that cement slurry to reach 20,000 ft.”

A strong understanding of the wellbore environment and the effects of contaminants on the cement slurry are among considerations that need to be addressed ahead of time. “Do we have adequate compressive strength development? Do we need to wait for the cement for a longer period of time until the contaminant actually sets to have an isolation barrier off the cement?”

As the cement is loaded offshore, it travels through a chain of custody that calls for quality control and brings Mr Dajani to pose more questions. “Are we using the right pressure on the lines? Is there too much moisture?” Quality control is necessary for the cement to maintain its chemical properties and a successful end result, he said.

On the training side, young engineers may have the knowledge but still lack field experience. An understanding of best practices cannot replace experience. “There’s a disconnect between designing on paper and having the experience level to have confidence in executing it in the field,” Mr Dajani stated. The challenge can be met by providing them with additional time and field training offshore.

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Deepwater demands require upgrade in surface, downhole technologies alongside industry collaboration

By Joanne Liou, editorial coordinator

Deepwater drilling in the US Gulf of Mexico (GOM) is pushing limits with depths around 34,000 ft, more than 25,000 psi bottomhole pressure (BHP) and 250°F bottomhole temperature (BHT), and the numbers will only get higher with the next generation of deepwater rigs and equipment. Tomorrow’s rig will boast the capacity to reach 35,000- to 40,000-ft measured depth with more than 30,000-psi BHP and greater than 300°F BHT, Rohit Mathur, account manager of Baker Hughes, explained at the IADC International Deepwater Drilling Conference and Exhibition in Rio de Janeiro, on 17 April.

The increasing demands of deepwater drilling require upgrades in not only the rigs and equipment but also in communication and collaboration, Baker Hughes’ Rohit Mathur said at the IADC International Deepwater Drilling Conference and Exhibition in Rio de Janeiro on 17 April.

Presenting a service company’s approach, Mr Mathur explained the current challenges in the GOM, from hurricanes to high pressures, that are shaping expectations of the type of rigs that will be necessary and the equipment specifications that will be needed in light of formation issues and the wellbore itself. “The next-generation (derrick) will need to be rated to 2.5 to 3 million lbs, 2 million-lb traveling capacity, 2 million-lb active heave compensation, 30,000 ft or more of tubing racked back on rig floor itself and have the capability to drill at least to 40,000 ft drilling capacity on depth,” he said.

In the next five years, Mr Mathur expects deepwater rigs to have 12,000-ft storage of riser onboard and in the next 10 years, 15,000 ft. Cementing units will need 3,000 hp or more and be capable of high-pressure fracturing operations.

He also believes that wired drill pipe will become more prevalent in deepwater operations despite the higher costs. “There is a demand for higher data density, more real-time data in productive zones,” he said, noting that the limits of mud-pulse telemetry may be exceeded as we push wells depths to the 30,000- to 35,000-ft mark.

The additional uncertainties associated with deeper, sub-salt formations also create a need for better integration of wellbore programs utilizing real-time LWD, real-time drilling dynamics, seismic modeling and a 3D well plan model. “One picture gives a better, clearer understanding of what zones we’re trying to hit, how we’re hitting them, how we can exit out of that and basically improve the whole field development provided the better understanding,” Mr Mathur said.

Upgraded technologies also implicate a need for better communication and collaboration. “The communications workflow needs to be smoothened out,” he continued. “Everyone needs to know who to call, which would basically mean people at the rig site, at the office, team leaders talking to each other and keeping in the loop. We talk about technology, but we also need the piece of communication to do the work.”

Given the vast task ahead in deepwater, Mr Mathur believes that the industry is lacking a coordinated effort but notes that “there is definitely growing awareness among the industry.” Where there is an awareness of what needs to be done, individual companies are honed into their own projects and programs. “Everybody’s doing their own training program, but there’s not coordinated effort,” he said. “That’s what I’m calling for. There is a need to bring this big picture where everybody can talk the same lingo, the same language on what process, policies need to happen at the rig site, to prevent a disastrous situation from occurring.”

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Baker Oil Tools Sets Deepwater Record for Horizontal Gravel Pack Completion

HOUSTON, TEXAS (June 3, 1999) - Baker Oil Tools set a new deepwater record off the coast of Brazil for the successful completion of a subsea horizontal gravel pack, at a water depth of 3,248 ft.

Using a semisubmersible floating rig, the well was completed with an 8 1/2-in. open-hole horizontal gravel pack having a lateral length of 1,673 ft.

The well was drilled to a total depth (TD) of 11,460 ft using Baker Hughes INTEQ's PERFFLOW™ drill-in fluid to prevent formation damage and provide formation stability for successful hole cleaning and gravel packing procedures.

Baker Oil Tools' EXCLUDER™ Extended Longevity Well Screen provided mechanical robustness and plugging resistance as over 37,400 lbs of sand was packed into the horizontal section. The sand was pumped at a rate of 9.1 bpm with sand concentration of 1.1 lb/gal, resulting in gravel placement of 133%. Using the PERFFLOW fluids system and hole cleaning procedures allowed successful well production with no post-job acid required.

Baker Oil Tools is a world leader in total completion, workover, and fishing solutions that help exploration and production companies optimize their hydrocarbon recovery investment.

Baker Oil Tools solutions are based on advanced downhole and surface technology, practically applied, to help operators produce at the highest levels and the lowest cost throughout the life of the reservoir.

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New HI-M-PACT&#8482 Low-Dosage Hydrate Inhibitor - Step Improvement in Deepwater Flow Assurance

SUGAR LAND, Texas (May 31, 2002) - Baker Petrolite introduces the HI-M-PACT™ low-dosage hydrate inhibitors (LDHI) to help deepwater oil and gas operators inhibit hydrate plugging, reduce costs and increase hydrocarbon recovery. In field applications, the low-dosage HI-M-PACT inhibitors have achieved significant total cost savings in production systems designed for conventional methanol treatment.

Hydrates are ice-like crystalline structures that form in deepwater systems through the combination of light hydrocarbons and water under low seabed temperatures and high reservoir pressures.

Hydrate plugs have formed as long as 2,000 ft (610 m) and have blocked pipelines as large as 40” (1 m) in diameter. The cost of remediating hydrate plugging can be extremely high in subsea lines that stretch as long as 60 miles (97 km).

Based on anti-agglomerant technology, these low-dosage HI-M-PACT inhibitors disperse hydrates into the liquid hydrocarbons. Dosage rates are typically 1/40th that of conventional inhibitors. With the HI-M-PACT anti-agglomerant inhibitor, total costs for existing production systems are expected to be cut by as much as 50%. The greatest savings are expected in the design of new production systems through the use of narrower treatment flow lines, reduction of premium deck space for treatment storage tanks and incremental hydrocarbon recovery.

In a deepwater Gulf of Mexico field, methanol injection at the maximum rate was insufficient to control hydrates in 24-mile gas condensate flow lines,” explained Hartley Downs, Director of Fluids Conditioning for Baker Petrolite. “The HI-M-PACT inhibitor at a low dosage of 0.35 gal/bbl of water increased production by 20 MMcfd. Increased capacity afforded by the HI-M-PACT treatment is expected to allow the recovery of additional 7.5 Bcf in hydrocarbon reserves.”

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Factors Key To Deepwater Cementing article

HOUSTON–As deepwater oil and gas exploration expands around the world, well cementing is a critical aspect of well construction with unique considerations because of the deepwater environment and downhole conditions. To minimize risks, well construction costs and nonproductive time, it is important to understand the constraints for deepwater cementing and essential good cementing practices, and to carefully plan for contingencies that may arise when working in locations where cement must be placed properly the first time, every time.

Two of the most frequently asked questions regarding offshore operations are what makes deepwater drilling so challenging, and what is the major difference from drilling on the Shelf? To answer this question, one must understand that deepwater drilling rigs float thousands of feet above the surface location. They are kept on station either by anchors attached by miles of gigantic cables or by an automated dynamic positioning system that operates the rig’s thrusters based on very precise data from global positioning satellites. Both of these systems have limits, but they have propelled oil and gas exploration into water depths greater than 10,000 feet.

Deepwater semisubmersibles deploy two-story-high stacks of blowout preventers that sit on the seafloor and are exposed to extreme cold and external pressure. The floating rigs also carry small unmanned, remotely operated vehicles that monitor operations at the seafloor and use robotic arms to assist when necessary. These technological wonders and dozens more, developed and built by the service industry especially for the challenges of deepwater drilling, add to a huge capital investment by oil and gas exploration and production companies. The cost of developing a deepwater field can exceed $1 billion, and increases with increasing water depth.

The mechanics of drilling a deepwater well are also much different from drilling on land or on the Shelf. In deep water, the first two to three strings of pipe are installed without a connection back to the rig. Riserless drilling essentially eliminates any means of placing pressure on the well, other than the pressure exerted by the well fluids and the natural column of sea water. This means that mud and cement companies must have very specialized systems and training in order to counteract and control the problems associated with riserless drilling.

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Special webcast: Defining challenges and potential solutions for MPD in deepwater drilling

Posted on 27 March 2012

http://www.drillingcontractor.org/wp-content/plugins/vipers-video-quicktags/resources/jw-flv-player/player.swf?file=http%3A%2F%2Fwww.drillingcontractor.org%2Fwp-content%2Fuploads%2F2012%2F03%2Fvideo-milan-03121.flv

IADC group VP/publisher Mike Killalea sat down with David Pavel, global director of business development for Weatherford International, and Gavin Humphreys, manager – technology and new business for Stena Drilling, at the 2012 SPE/IADC Managed Pressure and Underbalanced Operations Conference & Exhibition in Milan, Italy on 20 March to discuss the challenges and possible solutions to MPD applications in deepwater. Key barriers to implementation include issues related to planning, procurement and operations. “Right now the challenge for drilling deepwater MPD is getting the fleet that exist in the world today … to a point where we can deploy this type of equipment and procedure on these rigs,” Mr Pavel said.

Read more about MPD-ready rigs in here.

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New HI-M-PACT&#8482 Low-Dosage Hydrate Inhibitor - Step Improvement in Deepwater Flow Assurance

 

SUGAR LAND, Texas (May 31, 2002) - Baker Petrolite introduces the HI-M-PACT™ low-dosage hydrate inhibitors (LDHI) to help deepwater oil and gas operators inhibit hydrate plugging, reduce costs and increase hydrocarbon recovery. In field applications, the low-dosage HI-M-PACT inhibitors have achieved significant total cost savings in production systems designed for conventional methanol treatment.

Hydrates are ice-like crystalline structures that form in deepwater systems through the combination of light hydrocarbons and water under low seabed temperatures and high reservoir pressures.

Hydrate plugs have formed as long as 2,000 ft (610 m) and have blocked pipelines as large as 40” (1 m) in diameter. The cost of remediating hydrate plugging can be extremely high in subsea lines that stretch as long as 60 miles (97 km).

Based on anti-agglomerant technology, these low-dosage HI-M-PACT inhibitors disperse hydrates into the liquid hydrocarbons. Dosage rates are typically 1/40th that of conventional inhibitors. With the HI-M-PACT anti-agglomerant inhibitor, total costs for existing production systems are expected to be cut by as much as 50%. The greatest savings are expected in the design of new production systems through the use of narrower treatment flow lines, reduction of premium deck space for treatment storage tanks and incremental hydrocarbon recovery.

In a deepwater Gulf of Mexico field, methanol injection at the maximum rate was insufficient to control hydrates in 24-mile gas condensate flow lines,” explained Hartley Downs, Director of Fluids Conditioning for Baker Petrolite. “The HI-M-PACT inhibitor at a low dosage of 0.35 gal/bbl of water increased production by 20 MMcfd. Increased capacity afforded by the HI-M-PACT treatment is expected to allow the recovery of additional 7.5 Bcf in hydrocarbon reserves.”

View the original article here

Factors Key To Deepwater Cementing article

HOUSTON–As deepwater oil and gas exploration expands around the world, well cementing is a critical aspect of well construction with unique considerations because of the deepwater environment and downhole conditions. To minimize risks, well construction costs and nonproductive time, it is important to understand the constraints for deepwater cementing and essential good cementing practices, and to carefully plan for contingencies that may arise when working in locations where cement must be placed properly the first time, every time.

Two of the most frequently asked questions regarding offshore operations are what makes deepwater drilling so challenging, and what is the major difference from drilling on the Shelf? To answer this question, one must understand that deepwater drilling rigs float thousands of feet above the surface location. They are kept on station either by anchors attached by miles of gigantic cables or by an automated dynamic positioning system that operates the rig’s thrusters based on very precise data from global positioning satellites. Both of these systems have limits, but they have propelled oil and gas exploration into water depths greater than 10,000 feet.

Deepwater semisubmersibles deploy two-story-high stacks of blowout preventers that sit on the seafloor and are exposed to extreme cold and external pressure. The floating rigs also carry small unmanned, remotely operated vehicles that monitor operations at the seafloor and use robotic arms to assist when necessary. These technological wonders and dozens more, developed and built by the service industry especially for the challenges of deepwater drilling, add to a huge capital investment by oil and gas exploration and production companies. The cost of developing a deepwater field can exceed $1 billion, and increases with increasing water depth.

The mechanics of drilling a deepwater well are also much different from drilling on land or on the Shelf. In deep water, the first two to three strings of pipe are installed without a connection back to the rig. Riserless drilling essentially eliminates any means of placing pressure on the well, other than the pressure exerted by the well fluids and the natural column of sea water. This means that mud and cement companies must have very specialized systems and training in order to counteract and control the problems associated with riserless drilling.

Download the PDF to read more.

DOWNLOAD PDF (828.6 KB)

View the original article here