Ensco orders sixth ultra-deepwater drillship to meet customer demands

Responding to the high level of customer demand driven by a trend of successful offshore discoveries, Ensco has ordered an advanced-capability, ultra-deepwater drillship to be built by Samsung Heavy Industries in Geoje, South Korea.

The vessel, ENSCO DS-8, will be the sixth Samsung DP3 drillship in the Ensco fleet.  It is scheduled for delivery in the Q3 2014. The contract also includes options for two additional drillships of the same design.

Consistent with the previous five Samsung ultra-deepwater drillships ordered since 2007, the new unit will have advanced capabilities to meet the demands of ultra-deepwater drilling in water depths up to 12,000 ft and a total vertical drilling depth of 40,000 ft. New features on ENSCO DS-8 include retractable thrusters, enhanced safety and environmental features, improved dynamic positioning capabilities and advanced drilling and completion functionality including below-main-deck riser storage, triple fluid systems, offline conditioning capability and enhanced client and third-party facilities.

“An ongoing trend of new deepwater oil and gas discoveries around the globe is creating a high demand for equipment capable of tapping those resources,” Ensco Chairman, President and CEO Dan Rabun, said.

The new drillship is based on the proprietary Samsung GF12000 hull design measuring 755 ft in length and 125 ft in width. It will offer a payload in excess of 22,000 tons and a 1,250-ton hoisting system. The rig’s design and capabilities include features that increase operating efficiency, such as enhanced and redundant offline tubular stand building features and a 165-ton active heave compensating construction crane, allowing for the deployment of subsea production equipment without interference with ongoing drilling operations.

The rig will be equipped with dynamic positioning in compliance with DPS-3 certification; six-5.5 megawatt thrusters for enhanced station-keeping; expanded drilling fluids capacity; a 15,000-psi subsea well control system with six rams, upgradable to seven rams and/or a second BOP stack; burner boom for well testing; and living quarters for up to 200 personnel.

“This addition to our fleet is in keeping with our strategy of standardization, which streamlines construction, operations, inventory management, training, regulatory compliance, repairs and maintenance,” Mr Rabun said.

Ensco’s three active DP3 drillships are currently contracted into 2016 in the Gulf of Mexico, Brazil and West Africa. A fourth, ENSCO DS-6, is undergoing pre-commissioning modifications in preparation for its first well assignment under a five-year contract with BP. ENSCO DS-7 is scheduled for delivery in the second half of 2013.

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Keppel AmFELS to deliver new jackup to Perforadora Central in 2014

Posted on 02 April 2012
Mexico’s Perforadora Central has awarded a contract to Keppel AmFELS to build a repeat jackup worth $205 million. Slated for delivery in Q1 2014, the rig will have leg lengths of 511 ft and the capability to drill wells up to 30,000 ft at a water depth of up to 375 ft.
Keppel AmFELS completed Tonala, an ultra-premium KFELS B Class jackup for Perforadora Central in 2004, followed by Tuxpan, a LeTourneau S116E rig in 2010. The Papaloapan jackup, which was ordered by Perforadora Central in March 2011, is under construction and on track for delivery Q1 2013.
According to Perforadora Central,  ”Our Tonala and Tuxpan jackups are turning in excellent performances for PEMEX in Mexico while construction of Papaloapan is ahead of schedule. We are just as confident that our latest newbuild by Keppel AmFELS will be another exceptional product to boost our track record and establish us as the foremost provider of drilling solutions in Mexico.”
Keppel AmFELS noted that it is pursuing other projects with PEMEX. “We have endured the post-Macondo challenges well. Having recently secured the Ocean Onyx semisubmersible major upgrade and a series of repairs, this newbuild jackup adds to a healthy workload through Q1 2014,” said Tan Geok Seng, president of Keppel AmFELS.
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MPD makes the difference in offshore Indonesia offshore gas development program

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

An offshore well in Indonesia’s Ujung Pangkah field went from a potential failure to an invaluable success once managed

Clifford Lang (right), Hess, was among a panel session looking that examinedat the state of play of MPD and UBO technologies from the operator’s perspective at the 2012 MPD and UBO Conference and Exhibition on 21 March in Milan, Italy. The session was moderated by Dag Ove Molde (from left), Statoil, and included Claudio Molaschi, Eni, and Dave Elliott, Shell.

pressure drilling (MPD) was deployed, said Clifford Lang, drilling and completions manager of Europe, Eurasia and North Africa for Hess. “We surveyed the rig for MPD prior to getting on location … as a precaution,” he said during a presentation at the 2012 IADC/SPE MPD and UBO Conference and Exhibition on 21 March in Milan, Italy.

The first well in the gas-drilling program was completed without losses. However, on the second well, during the drilling of a sidetrack through carbonates in the reservoir section, “we hit the cave,” Mr Lang said. Losses totaling 96,000 bbl were experienced before the company began bullheading seawater with high-viscosity pills to push the gas back into place. The goal was to pull the pipe at least partly out of the hole. “We had to get out of the hole to get MPD in place,” he said.

A second gunk pill that was pumped down at 4,652-ft MD gave the team a chance to get out of the hole. Reduced hydrostatic pressure on top of the gunk pill allowed it to support the fluid above and allowed surface pressure to be bled off to zero.  A 9 5/8-in. drillable subsurface plug was set at 4,325-ft MD, and a cement plug was set on top to secure the well. “That took us 10 days of pain and losses,” Mr Lang said.

Once the team rigged up the MPD equipment and went back in with the drill string, the well reached TD and became Hess’ most productive on the field at 55 million standard cu ft/day. Mr Lang believes that surveying the rig for MPD in advance and having a contract in place with a service company was key to turning the well around when “we were staring at failure in the face.”

MPD has reduced the operational NPT associated with losses in the reservoir section to virtually zero, he added. Hess now makes sure that it has MPD equipment hooked up prior to seeing potential issues drilling through carbonates. Specifically on the Ujung Pangkah field, the company ended up deploying MPD twice out of the first six wells. “(MPD) enables us to do things we wouldn’t have been able to do. It will be used on all future wells and exploration wells in that area. Wherever we have carbonates we will be using this,” Mr Lang said.

Instead of fighting Mother Nature with LCM during loss situations, working with her natural pressure profile through the use of MPD techniques could save significant costs and time. “It will save you a fortune,” Mr Lang stated. “It’s safe, practical and it allows us to do so much more than we expected to do with these wells.”

Platinum sponsors for the 2012 SPE/IADC MPD & UBO Conference & Exhibition were Eni and Schlumberger; gold sponsor was Halliburton.

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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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Candidate selection could be key to successful underbalanced drilling project

AppId is over the quota
AppId is over the quota
A successful UBD operation begins with the right candidate selection and good communication among the stakeholders.

By Katie Mazerov, contributing editor

Upfront planning and appropriate candidate selection are critical to achieving success in underbalanced drilling operations, especially as the industry begins to look to deepwater as the next frontier for the application, Patrick Brand, executive VP for Blade Energy Partners, said in a presentation at the 2012 SPE/IADC Managed Pressure Drilling & Underbalanced Operations Conference & Exhibition, 20-21 March in Milan, Italy. “Underbalanced drilling (UBD) has been around for more than 100 years in one form or another, but there are still issues that we as an industry see every time we get into underbalanced projects,” Mr Brand said.

The key for success in UBD lies in the preliminary work, starting with candidate selection, or the process of choosing the right reservoir for the application of underbalanced drilling, he said. “UBD cannot create value where it does not exist. … If you don’t get the candidate right, you are bound to have a failed project. Companies that try and short-cut this phase of the work ultimately run into accidents, nonproductive time (NPT) and failures.

“Doing the work up front and getting it right leads to proper equipment, procedures and training, which is what makes the project successful,” he continued. At the center of that process is good communication among all stakeholders involved in the project.

Mr Brand maintains there are still several concepts about UBD that the industry has not fully grasped. For one, UBD is a reservoir exploitation tool first and foremost, not a drilling technique, he said. “We’re trying to enhance the reservoir by increasing productivity and ultimate recovery or determine the reservoir’s characteristics.” He identified reservoir characterization as a process where many companies are missing out on an opportunity to use clean data to determine the true permeability of the reservoir, which can aid in the final completion design. “For example, knowing where the fractures are can really help us get the most out of the reservoir.”

Do your homework

Another issue concerns the over-estimation of equipment required for multi-phase hole cleaning. “We all work under the same general rules, but we’re learning that often these rules are very conservative and that we can easily drill wells at lower parameters,” Mr Brand said. “We have actually killed projects for problems that don’t exist.”

There is also confusion in the industry as to when to use UBD versus managed pressure drilling (MPD). “MPD has really taken over in a lot of areas, but knowing when to use the right technique is very important,” he said. It’s also critical to understand the chemical interaction between produced and pumped fluids and equipment. “In cases where oxygen or produced fluids are pumped with gas, if you don’t do your homework correctly, you can have problems with elastomers or chemical reactions.”

In deepwater, Mr Brand believes the biggest challenge for deployment of UBD involves the loads on the riser. “If we’re looking at taking the returns of multi-phase fluid up in that riser, we need to make sure we can control the well safely, especially when we encounter the possibility of leaks or anything else in the rotating control device, and the unloading of that riser,” he said.

In addition to deepwater applications, challenges for UBD include tripping and running completions efficiently, wellbore stability, barrier policies, equipment certification and specifications, and low-rate metering/multi-phase metering. “It’s easy to drill underbalanced,” Mr Brand said. “The challenges come in getting out of the hole and getting the completion in the hole. We need to do a lot of work in that area and get better tools for doing it effectively.”

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Hot spot for geothermal research - Connexus

 

The Christensen Diamond Products manufacturing plant opened in Celle, Germany, in 1957. The facility built diamond core heads and drill bits and later expanded to make downhole tools. In 1977, the Celle engineering and manufacturing team introduced the Navi-Drill™ line of downhole drilling motors.

After a series of mergers and acquisitions that began in the late 1970s, the facility became part of Baker Hughes in 1990 with the acquisition of Eastman Christensen. Other innovations developed in Celle include the industry’s first steerable motor system and the AutoTrak™ rotary steerable closed-loop system.

The Celle Technology Center (CTC), as it’s called today, was expanded in 2009 to support joint technology developments, including geothermal, with operators and local universities. Since its grand reopening, the CTC is also home to the Baker Hughes Center of Excellence for geothermal and high-temperature research and development.

In 2009, Baker Hughes and the Niedersachsen (Lower Saxony) state government jointly launched a multimillion euro, five-year cooperative university research project aimed at improving the technology for generating geothermal energy from very deep (4000 m to 6000 m) [13,123 ft to 19,685 ft] geological formations. With guidance from Baker Hughes scientists in Celle, Lower Saxony’s technical universities will combine their acknowledged strengths in geosciences, material sciences, drilling technology and technical systems in order to generate leading-edge research results for Baker Hughes to integrate into the development of sustainable and marketable products and services.

The Lower Saxony state government is also providing financial support for Baker Hughes’ research and development of high-temperature electronics for use in drilling and evaluation, as well as completion and production applications. In addition, Germany’s federal government has awarded Baker Hughes a cofunded project to develop cost-efficient drilling technologies for geothermal wells.

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