Serko Sarian, telemetry and conveyance portfolio manager for Schlumberger, talks with Drilling Contractor associate editor Katherine Scott about the company’s TuffLINE composite wireline cable on the exhibit floor at the 2013 OTC on 6 May in Houston. Developed over five years at the Schlumberger Houston Conveyance and Surface Equipment Center, the cable consists of a seven-conductor electrical core protected by two opposite wound steel armors and engineers out high-tension conveyance limitations.

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.

Noble Energy’s senior vice president of exploration and business innovation, Susan Cunningham, recognized how innovative ideas and people have led to her company’s successes in increasing production and discoveries.

As a company grows from a small organization to a relatively large one, it must contend with questions of how to keep its enterprising spirit alive. As Noble Energy transforms from its roots as a relatively small entrepreneurial company to a large independent, innovation is key to building and maintaining a competitive edge, Susan Cunningham, senior vice president of exploration and business innovation at Noble, explained at the 2013 OTC on 8 May. “The core of any sustainable and successful company and career trajectory is the ability to think different, to be able to see a different reality than what we see today,” she stated.

Over the past decade, Noble has increased its market capitalization to $20 billion, almost doubled its oil production to 240,000 bbls/day and increased its proved reserves to more than 1 billion bbls from less than 500 million bbls. “In the next five years, we expect to double our production, double our proved reserves,” Ms Cunningham said. “We operate in five core areas – two onshore in US unconventional plays, the other three offshore around the world, from deepwater Gulf of Mexico to West Africa and the Eastern Mediterranean. We expect to add at least two core areas through exploration.

Crediting the company’s success to innovation driven by creativity, Ms Cunningham explained innovation is not all about technology; it’s also about innovative thinking. Sharing concepts largely influenced by Imagine: How Creativity Works, a book by Jonah Lehrer, she explained how the confluence of different ideas can lead to breakthroughs. “Whenever people connect or come together, they become much more productive per capita,” she said. “It happens in every city, in every time (period). By measuring every socioeconomic data, from patents to per capita income, scientists have found creativity scales to an exponent of approximately 1.15, which means that a person living in a city of a million people will on average generate 50% more patents and make 15% more money than a person living in a city of 500.”

Businesses, however, exhibit the opposite relationship, an increase in the number of employees leads to a decrease in creativity. According to scientists, this is rooted in failure of innovation because large businesses tend to minimize the very interactions that lead to new ideas, she said.

Cities, however, provide a platform for masses of people to interact to create new ideas and new energy, leading to unpredictable encounters and spontaneous mixing, Ms Cunningham explained. Noble is transferring that concept to build a company around its entrepreneurial history, “where we never lose sight that business is all about people. The engagement of the human spirit is vital to a vibrant community, as well as a vibrant company.”

Three pillars support Noble’s innovation: leadership, alignment with the company’s vision and innovative thinking. “The first is focused on creating great leaders everywhere,” Ms Cunningham said, “where respect and care is at the core and taking outcomes that we don’t know how to achieve is what we do.”

A testament to Noble’s business innovation is the company’s exploration goal in 2006 to discover 1 billion bbls of oil equivalent of net resources in the next five years. “We didn’t end up discovering 1 billion bbls of oil equivalent in five years,” Ms Cunningham said. “We discovered 2.8 billion bbls of oil equivalent from 2007 through 2012, replacing about 30 times our current annual production and creating two new core operating areas.” In 2006, Noble averaged 35 million bbls of oil equivalent per year through exploration. The company set a goal that seemed impossibly high, but “to our astonishment, we exceeded it. We took it on to cause our organization to change, to grow, to be the best it could be,” she said. “To achieve all that, we had to be innovative to change the direction of our future.”

Paul Day, business development director for Weatherford, speaks with Drilling Contractor associate editor Katherine Scott about the company’s Keystone module on the exhibit floor of the 2013 OTC on 8 May in Houston. The Keystone module is an RFID-based, remotely operated electronic completion system to control downhole tools that can set packers or open packer setting ports, operate sliding sleeves to allow tubing to annulus circulation, close and open barrier valves, and operate fill subs. The system is made up of four elements— an RFID-hydraulic-power unit, a circulation valve, a production packer and a fall-through-flapper barrier valve.

Keystone is a trademark of Weatherford.

Qualification of DGD systems is dependent on the specific configuration of the DGD system, the drilling installation and the well conditions, DNV’s Francisco Chávez V. said at the IADC Dual Gradient Drilling Workshop on 9 May in Houston.

As industry gains experience in the deployment of dual-gradient drilling (DGD) systems on floating rigs, qualification of these systems will become necessary to provide documented evidence that the system will operate safely, Francisco Chávez V., principal project manager of the drilling & well section for Det Norske Veritas (DNV), said at the 2013 IADC DGD Workshop in Houston on 9 May. Such qualification would be dependent on three factors: the configuration of the DGD system, the drilling installation and well conditions, he said. “These three set the qualification boundaries, and changing any one of these will require a reassessment of qualification.”

Because new technologies begin with no defined standards that become developed as the technology is utilized, Mr Chávez said, a risk-based, systematic approach to system qualification would ensure that the technology functions reliably within specified limits. This approach should be applied to DGD technologies, he said, which remains new in terms of field deployment, particularly in deepwater environments. It’s also necessary to qualify DGD systems to extend the operational limits when existing DGD technology is used in more demanding operations, he said.

Mr Chávez cited the following as the current, relevant design standards for DGD on floating drilling rigs with DNV Class:

• DNV OS E 101 “Drilling Plant”
• DNV OS A 101 “Safety Principles and Arrangements”
• DNV OS D 202 “Automation, Safety, and Telecommunication Systems”

Efforts are also ongoing to produce more specific guidelines for designing DGD systems:

• The IADC Underbalanced Operations & Managed Pressure Drilling Committee has drafted an API Recommended Practice for managed pressure drilling, “Constant Bottom Hole Pressure using Applied Surface Back Pressure (Category 2 MPD) with Single Phase Fluid”
• Revised version of NORSOK D-010
• DNV revision of DNV-OS-E101

“The design of all equipment has to consider the regulations and the standards, which will eventually be used for qualifying such a system for the operation that is intended. Within that, it implies as well the need to assess the reliability of the different components within that part of the classification so the standards and the qualification methods contribute to building trust on the safe operations, the design and the performance, the reliability of a DGD system,” Mr Chávez said.

Paul Guirlet, Pacific Drilling, said at the workshop that the company had to make several modifications to integrate DGD on the Pacific Santa Ana but is incorporating lessons learned on the four rigs still under construction, which will be delivered “as DGD ready as we can.”

In another presentation at the workshop, Paul Guirlet, vice president of technical support for Pacific Drilling, highlighted the challenges and modifications associated with the integration of DGD on rigs, particuarly what the company has accomplished over the past three years working with Chevron on the Pacific Santa Ana.

He acknowledged that integrating DGD on that drillship has been a team-based effort among many companies, including Chevron, GE, AGR and National Oilwell Varco, adding that the biggest challenge from his perspective was finding space on the rig for the system. “Even if we have a very large vessel, the challenge is finding room.” Further, installation of DGD equipment required locations where it would be easy to access, easy to maintain and easy to use. “This is quite a big piece of equipment; consider it like a lower stack of a BOP that needs to be installed a part of the riser string… We’ve done a lot of work trying to optimize and make the best use of the space available on the vessel.” The DGD equipment includes a drilling riser cross-section, subsea rotating device, solids processing unit, MaxLift pump and drill string valve.

Other equipment on the rig, such as the piping system and the Christmas tree, also needed to be retrofitted due to the fluids used in DGD. “All of our vessel are coming with two storages for the BOP, but of course the MaxLift pump was not exactly similar to a BOP, so we needed to upgrade that. We needed to have a second guiding system to make sure the vessel motion would not create any problems.” Pacific Drilling also had to add two Mux reels, he said.

Mr Guirlet noted that Pacific Drilling is taking all the lessons learned from the Pacific Santa Ana, which was delivered in late 2011, to its new ultra-deepwater drillship, the Pacific Sharav. “We really believe in the DGD plan, so all of the four rigs that we’ve got currently under construction at Samsung will be as DGD ready as we can, because there is a lot of development still ongoing at this stage. And we will know more certainly after we drill the first well in not too long.” Samsung is expected to deliver the Pacific Sharav at the end of 2013.

Group discussions at the 2013 IADC Dual Gradient Drilling (DGD) Workshop on 9 May in Houston focused on DGD implementation drivers and operational challenges. The event, hosted by the IADC DGD Subcommittee, cultivated open discussion by dividing the audience into groups and allowing them to talk with speakers in a smaller group setting. In this exclusive video, Kristin Falk, chairwoman of the subcommittee and vice president engineering, product development & training for AGR Enhanced Drilling; and Frederic Jacquemin, chairman of the subcommittee and DGD program director at Pacific Drilling, speak with Drilling Contractor associate editor Joanne Liou about the key takeaways from the workshop and some of the subcommittee’s current projects.

Managed pressure drilling (MPD) systems are increasingly being used in formations with restricted operational pressure windows, but a lack of understanding of the interaction between MPD well control equipment and the primary well safety barrier presents an increased risk of incidents, an engineering expert contends. “Our experience is that the drilling industry is struggling when it comes to understanding the primary well control envelope for MPD in general,” Arne Handal, senior engineer and product manager for Det Norske Veritas (DNV), said at the 2013 IADC/SPE Managed Pressure Drilling & Underbalanced Operations Conference & Exhibition, 17-18 April in San Antonio.

“For MPD operations, we have poor standards, and the definitions often vary or are inconsistent, meaning people think differently about these systems,” Mr Handal said. He clarified those definitions by comparing conventional drilling practices with MPD and introducing a simplified, closed-loop MPD control system model.

“To understand MPD, we need to start with a basic explanation of the conventional drilling pressure control system, where primary well control during normal drilling operations is achieved by maintaining sufficient mud weight to keep the hydrostatic pressure in the well in overbalance,” Mr Handal said. The primary well barrier, in this case, is provided by the mud column in the well. “To avoid degradation of the primary well barrier, the equivalent circulating density (ECD) should not unintentionally exceed the exposed formation fracture gradient.”

Impact on primary barrier

“When it comes to well control in MPD, the principle is the same: We need to keep the well in overbalance,” he continued. “But when we use MPD, we can actually change the pressure in the well during the operation.” In a typical MPD operation, primary well control uses active bottomhole pressures to keep the hydraulic well pressure in overbalance. The primary well barrier is the same as for conventional drilling only if the mud is designed solely to prevent a well incident within both expected and verified formation pressure limits. “Otherwise, the primary well barrier is ensured by the mud in the well, in addition to a system of typically nonconventional equipment, such as an MPD pressure control system, which consists of three components,” he explained:

• A control system, including a logic unit and well monitoring system to maintain bottomhole pressure within the operational pressure window;
• Dynamic MPD pressure control equipment, including an automated choke manifold, additional circulating systems, conventional pumps and tools that restrict flow, to dynamically adapt the annular hydraulic pressure profile of the well;
• Static MPD pressure control equipment, rotating or non-rotating control devices (RCD), to isolate backpressure and close the well if necessary.

“It is important to understand that the unconventional equipment used in MPD operations can impact the primary well barrier, posing a risk if the RCD, or secondary barrier, should fail,” Mr Handal said. “No well barrier is perfect; each barrier will have holes or degradations. If the holes in the barriers become aligned, and the well becomes underbalanced after drilling into the reservoir, a blowout could occur.”

To overcome this gap in understanding, Mr Handal presented a simplified, closed-loop MPD pressure control system that addresses well safety barrier management by redefining the primary well barrier to encompass several elements, including the drill string non-return valve, the RCD and an adjustable choke. Using dedicated risk analysis, the model for a typical MPD well would include the RCD on the top, a pressure transmitter and a pressure-while-drilling tube. The MPD pressure control system is connected to the adjustable choke and the well monitoring system.

Dedicated risk assessments should be conducted before defining well barriers, Mr Handal said. “Each MPD system is unique, and the configuration of the MPD pressure control equipment may vary for the same MPD system.”

M-I SWACO presented various solids and pressure control technologies at the recent 6^th annual M-I SWACO Tech Expo to meet the demands of onshore and deepwater operations.

The MD-2 Shale Shaker is a dual-deck, flatbed shaker with full-contact composite screen technology.

1. Product: MD-2 Shale Shaker

Launch: 2013 OTC

Based on the MD-3 Shale Shaker, the MD-2 Shale Shaker is a dual-deck shaker that features similarities to the MD-3 platform – the same screen, clamping system and motors. However, while MD-3 targets primarily high-end offshore operations, the MD-2 targets both high-end land operations and offshore projects, such as refurbishment jobs. “The advantage of (MD-2) is that we’re giving customers the ability to utilize the scalping deck throughout the whole well,” Marc Kirschenbaum, business development manager for shakers, screens & mixing technologies, said.

The MD-2 also combined the best practices and lessons learned from the MD-3 and the Mongoose Pro Shale Shaker, Bob Barrett, project manager, said. One advantage of the shaker is its ease of use. “All the controls are front-mounted, so you don’t have to get to the side of the shaker if there’s a space restriction” Mr Barrett stated. “For HSE concerns, all the screens are front loaded, easy to install and remove,” allowing screens to be inspected easily and quickly. The pneumatic screen clamping system does not require any tools.

M-I SWACO has three MD-2 units in the field in Wyoming and South Texas and has run design validation and performance evaluation tests. The company expects the product to enter the global market, particularly in Western Canada, Asia, the Middle East and South America.

The VERSA-CHOKE is a modular, versatile choke for advanced well control applications.

2. VERSA-CHOKE

Launch: August 2013

The modular VERSA-CHOKE can be customized for a variety of applications – high-end pressure control, MPD, UBD, frac flowback and frac plug drill-outs. “It can be applied onshore, offshore – anywhere there is a demanding environment for a pressure control system,” Mike Offner, business line manager for pressure control, said. The highly flexible choke features internal trim sizes that can be changed based on the flow application, allowing the same choke to be used in different applications. The ability to reverse trim improves choke operation life and reduces maintenance costs.

The choke’s hydraulically driven actuator can withstand full backpressure and can be swapped without having to disassemble internal components. “The actuators can be removed and worked on without disturbing the choke from the manifold,” Mr Offner said.

The VERSA-CHOKE is being tested in an MPD application in South Texas. Mr Offner added that a new MPD control system is also being developed that will provide precise control over bottomhole pressure and a reduced footprint.

SMART 3D provides a solution for effective displacement by integrating hydraulics, chemistry and mechanics.

3. SMART 3D

Launch: February 2013

Integrating hydraulics, chemistry and mechanics, the SMART 3D displacement brings together field-proven technologies to form a single wellbore displacement approach. “Those three components together give you effective displacement when you are transitioning,” Charles Svoboda, director of wellbore productivity, business development, said. “These three components are what it takes to get that efficient, effective displacement the first time.”

SMART 3D includes tools, such as WELL PATROLLER, to remove any residual debris and WELL SCAVENGER to provide reverse circulation at the end of the workstring to enhance debris removal. “We put the tools together in an assembly to meet the needs of the well,” Gabe Little, displacement product champion, said. “If we think we have a lot of ferrous debris because we’ve been milling, rotating for a long time, we’ll go to higher capacity.”

The SMART 3D displacement strategy is primarily geared toward offshore well cleaning. “We have to get a clean wellbore so that we minimize the amount of rig time,” Mr Svoboda said. “We want to do as many operations as possible on a single trip. We get the well displaced back to a water-based, water-wet environment, and we remove the debris so that when they go into the completion phase, they’re not running into debris that has been left from the drilling.”

The SeaONYX BOP surface control system utilizes a control platform that the company says has been designed for obsolescence management. The system addresses the challenge of ensuring availability, especially for electronic components, for a product expected to operate for 20 years or longer.

A BOP surface control system and operator interface designed for deepwater drilling was among several technologies GE launched this week at the 2013 OTC. The Acoustic Leak Detection System and the Subsea Multi-domain Condition Monitoring System were two other technologies introduced at the Houston event.

The SeaONYX BOP surface control system from GE Oil & Gas incorporates the company’s Mark Vle hardware and Proficy software tools. It uses dual redundant electronic control systems to control the subsea equipment. The Mark VIe control components allows the SeaONYX to use a configuration that has been installed in more than 2,000 thermal, wind, hydro and nuclear facilities, according to GE.

“SeaONYX is a control system that helps to manage our BOPs in deepwater drilling operations. The development of the new system is an outstanding example of importing industry-leading technologies from other GE businesses into the oil and gass space,” said Chuck Chauviere, president of drilling for GE Oil & Gas. “In this case, our customers will be benefitting from a control system solution that has a strong track record of success and high-level performance in the global power generation industry.

A critical advance with the new control system’s Mark Vle control platform is its inherent design for obsolescence management. The system addresses the industrywide challenge of ensuring availability, especially for electronic components, for a product expected to operate for 20 years or longer. The SeaONYX system does this by using a standard footprint for the major components that will be used in future releases of Mark VIe hardware.

Another feature of the Mark Vle architecture is the ability to “hot swap” certain components while the system is running. When an individual component requires replacement, the rest of the system remains active while it is replaced. The new component will boot up, configure itself and typically come back online in a matter of minutes, increasing system availability.

The two condition monitoring and sensing solutions for the subsea sector, launched by GE’s Measurement and Control business, will allow operators to monitor the integrity of their subsea installation. The Acoustic Leak Detection System (ALD) uses passive, acoustic hydrophone technology to detect and locate subsea oil and gas leaks by discriminating the noise of a leak from other sources of sound. Developed from naval military technology, the system detects “silent” leaks that occur when there is low flow rate or low differential pressure.

The ALD can detect both crude oil and gas with a coverage up to 500 meters.

The Subsea Multi-Domain Condition Monitoring System combines electric emission monitoring and acoustic hydrophones designed for monitoring the operating condition of subsea machinery and processes — from pumps and valves to supporting infrastructure. Typically combined with ALD to detect subsea leakage, the system performs multi-domain analysis supported by proven pattern recognition and machine learning algorithms to identify and display subsea structure, machine and pipeline activities and anomalies.

“As subsea exploration and production becomes increasingly important globally, many customers are looking to expand these topside capabilities to the seabed,” said Jens Abrahamsen, Naxys business leader for GE Measurement & Control, a GE Oil & Gas division. GE acquired Naxys in 2012. “By combining subsea sensors and acoustic condition monitoring with existing GE technology, GE customers can expand their view into operations and make intelligent, critical decisions about their operations.”

Julio Quintana, president and CEO of Tesco

Tesco Corp has completed tests for two products – the HXI 150-ton top drive and Hydraulic Compact CASING DRIVE SYSTEM (HCCDS) – for extended reach.

The HXI 150t, the 12^th of TESCO’s top drive line, features the same benefits as the HXI 250t but is lighter and smaller and allows operators to move the top drive between mobile rigs. “The R&D groups did a great job of looking at this unit and shrinking it down substantially,” Julio Quintana, president and CEO of Tesco, said at a press conference at the 2013 OTC on 7 May. “You’re able to put it on essentially any rig in the world.”

Generating 24,000 ft/lbs of drilling torque, the HXI 150t is designed for the horizontal value stream, as well as the vertical stages of the well, including drilling sections, rotating casing to TD and cementing the casing. Its integrated safety interlock of the process logic controller system and driller’s control panel maximizes operating efficiency while minimizing risks.

“Consistent with our customer intimacy culture, we asked our customers what attributes of the top drive were critical to their operations and they told us: rig integration, smaller footprint and mobility,” Jeff Foster, vice president of top drives, said. “We designed the HXI 150t to meet all of those demands, and after a year of field testing, we are confident that it is the most versatile and dynamic top drive to meet those challenges.”

Complementing the HXI 150t is TESCO’s HCCDS, a compact, lightweight version of the company’s 500-ton CASING DRIVE SYSTEM.  Replacing conventional power tongs, traveling elevators and removing the need for a stabbing board, the HCCDS allows circulation, rotation and reciprocation of the casing to ensure it reaches casing point and in conjunction with TESCO’s Dynamic Cementation System improves the cement bond and wellbore integrity.

“By eliminating traditional equipment, the HCCDS is cost-efficient and maximizes safety by eliminating risks associated with conventional casing running equipment,” Nick Mawford, vice president of tubular services, said. “The HXI 150t top drive, coupled with TESCO’s HCCDS provides operators and end-users a compact rig solution for any drilling environment.”

Hydraulic Compact CASING DRIVE SYSTEM and CASING DRIVE SYSTEM are trademarks of Tesco Corp.