A long and winding road
Broad-scope advances in RSS, mud motors, bits, LWD/MWD push limits of directional drilling as automation vision takes shape
By Katie Mazerov, contributing editor
It’s no secret that drilling has taken a whole new direction in the past decade. In reality, it has taken multiple new directions as the industry navigates through increasingly complex formations and unconventional basins that require innovative solutions. As deeper, longer and more deviated wells have become the norm in many regions of the world, operators face a conundrum: how to balance ever more difficult and expensive directional drilling campaigns while maximizing wellbore economics.
The directional drilling revolution has spawned a continuous technological evolution with rotary steerable systems (RSS), downhole mud motors, directional bits and pad and factory drilling approaches designed to intensify and optimize the drilling process. The ability to enhance reservoir understanding and capture more data more quickly through measurement while drilling (MWD) and logging while drilling (LWD) also has
opened a wealth of opportunities.
As technologies have grown, so has the need for greater efficiency and service reliability. Remote monitoring of directional drilling operations via real-time facilities are enabling broader, expert oversight of operations. It’s also reducing the number of employees needed on the rig and the associated HSE exposure. Looking ahead, the development of automated directional drilling, enabled by high-speed wired drill pipe, could be a step-change that will lead to even greater innovations, perhaps even allowing wells to be steered remotely.
Many of the directional drilling accomplishments that the industry considers routine today were unfathomable back in 2002 when Devon Energy drilled its first unconventional wells in the Barnett Shale that combined horizontal drilling with slickwater hydraulic fracturing. At the time, only approximately 100 horizontal drilling rigs were operating in the US.
“The biggest driver in this shift is the nature of unconventional reservoirs and the need to exploit resources that are not viable vertically,” David Fortenberry, VP, Drilling North America for Devon, explained. “To capitalize on this opportunity has required industry to get better at drilling farther and faster with smoother curves and laterals, using robust tools that can stay in the hole and minimize tripping frequency because of tool failures. The difficulty of wells today, along with the push to improve performance, is taking technology to the limit, and those limits are being extended through the natural process of design, modification and improvement in tools, as well as practices and procedures.”
Mr Fortenberry cited improvements as including rotary steerable systems that are increasingly being used for curve-building and the drilling of laterals, mud motors that offer higher torque capabilities to allow for increased weight-on-bit and ROP, enhanced PDC bits that facilitate drilling curves and laterals through difficult geologies, and the ability to collect real-time data faster. Parallel to these advances, tool reliability has become critical, he added. “The service sector is under pressure to keep up with high demand for equipment manufacturing and servicing, which is impacted by personnel shortages.”
Adding to the complexity of today’s wells are multi-well pads that are facilitating what Mr Fortenberry calls “turnazontals,” where multiple horizontal wells are being drilled away from the pad.
In late 2010, Devon drilled 36 wells from one pad and 21 wells off another in an area southwest of Fort Worth, Texas. Today, pads with six to eight wells drilling laterals with lengths exceeding the true vertical depth of the formation are common. So are “factory drilling” operations spanning more than a mile where drilling and fracturing are taking place simultaneously.
“Our first wells in the Barnett took 28 to 30 days to drill, with 3,000-ft laterals and measured depths (MD) of a little over 10,000 ft,” Mr Fortenberry recalled. “Today, we’re drilling more complex wells with MDs of 12,000-13,000 ft and 10,000-ft laterals in as few as eight days using walking rigs that can finish a well and, within a few hours, spud the next one.”
Faster, real-time data
In the offshore sector, the trend is for more sophisticated LWD tools to collect real-time geological information to enable optimum placing of the casing, minimize drilling hazards (especially wellbore breakouts), understand pore pressure and look ahead with seismic-while-drilling technology, said Gokhan Yarim, VP, Marketing and Technique, Drilling & Measurements for Schlumberger.
“Service reliability, technologies for wellbore integrity, performance to achieve shoe-to-target depth, well placement and surveying have all been major drivers for improving directional drilling performance, both onshore and offshore.”
In response to the need for increased data rates, in-depth formation knowledge and accuracy, Schlumberger has worked to enhance its LWD and MWD technologies. These include the MicroScope HD high-definition, imaging-while-drilling service that provides real-time, high-resolution images of the formation, including fracture networks, connectivity and porosity, for evaluating the reservoir and optimizing completion design.
The company’s Periscope HD multilayer bed boundary detection service provides formation evaluation, including seismic and petrophysical properties, for up to 20 ft from the wellbore. “This helps operators understand what kind of layering is above and below the trajectory so they can keep the well in the sweet spot,” Mr Yarim said.
RSS that can drill better-quality wellbores with less tortuosity also are changing directional drilling, he continued. The Power Drive Archer, for example, is a high-build rate RSS, and the Power Drive Orbit RSS tool features a new pad actuation system, automatic hold inclination and azimuth and enhanced trajectory control at higher RPMs. Such technologies can help operators reach targets more quickly, reduce costs and retain better control of the well trajectory,” according to Mr Yarim.
Last year the RSS service drilled a record 12,690 ft in a single run for a Middle East operator that needed an RSS to maintain directional control while drilling deep laterals in a challenging onshore oil well.
Despite severe shock levels and high stick and slip values reaching 350 RPM, the system overcame severe torque to extend the lateral length by 33% and complete the operation 21 days ahead of schedule.
From art to automation
Directional drilling was as much an art form as it was an engineering practice in the 1980s and ’90s, but the industry’s development of skilled directional drillers has not kept pace with the growth of directional drilling activities, said Tony Pink, VP, Automated Drilling Applications for National Oilwell Varco (NOV). “This means that, for the next decade, we are going to have to deliver wells, especially those with mud motors, in an automated fashion because the skill set to drill these wells efficiently is not there.”
Integrated BHAs, drilling with casing/liner push directional drilling capabilities
Advances in rotary steerable systems (RSS) and logging-while-drilling/measurement-while-drilling (MWD/LWD) technologies have been game-changers in drilling complex, highly deviated and horizontal wells, but the industry continues to innovate. The increasing integration of bottomhole assembly (BHA) tools, for example, is widening adoption of advanced technologies and measurement capabilities and pushing the emergence of casing and liner drilling techniques.
“Over the last 15 years, BHAs have become fully integrated with steering tools, MWD/LWD telemetry, and sensors, all designed to improve efficiency when it comes to directional drilling,” said Alfred Knipper, Product Line Director, Directional Drilling Services, Baker Hughes. “Now we are seeing further integration and optimization of the multiple components in the BHA, which is allowing us to do a much better job of combining data and drilling solutions.”
High-tech drilling optimization sensors that were auxiliary or optional features when technology uptake was in the early stages are now standard components in BHAs because well complexity, both offshore and on land, is increasing with extended-reach drilling and developments that are much more crowded, he said. “From a well placement perspective, data is more critical than ever in ensuring the proper distance between wells and that wells are drilled in the right zone. With the multi-well pads being developed in the US market, we are placing hundreds of wells in the ground that must be navigated and precisely placed. Offshore rigs today are almost like pads, with companies drilling farther out from the templates.”
Drilling with liner and casing techniques also are being optimized to mitigate risk. Baker Hughes last year introduced the SureTrak steerable drilling liner service that uses one BHA to drill through trouble zones, evaluating the formation and placing the liner to total depth in a single run. The system is a fully functional directional drilling assembly used with the company’s AutoTrak RSS and modular LWD/MWD telemetry. The system has been deployed in Alaska, Norway and Saudi Arabia.
“The SureTrak service is being targeted for wells with borehole stability problems, where operators are encountering depleted zones, sloughing shales or similar problems that are making wells undrillable,” said Ahmed Al-Essa, Global Marketing Manager, Directional Drilling Services for Baker Hughes. “The service also saves time because typically we drill wells with a drilling BHA, trip the BHA out of the hole and run the liner, a process that can take up to two extra days in extended-reach wells. In the future, we will be able to drill with the liner, enlarge the hole as necessary and cement and set the packer, all in one trip.”
Looking ahead, Mr Knipper sees RSS tools being enhanced with greater dynamic steering capability to provide more precise well placement. Baker Hughes is developing the next generation of the AutoTrak RSS, bringing high build-rate drilling capability to offshore markets. The AutoTrak Curve system, which can drill high-angle trajectories up to 15°, has drilled more than 10 million ft since it was commercially introduced to the unconventional US land market two years ago.
The system saved 5.2 days of rig time and an estimated $352,000 drilling a horizontal well with a planned 10°/100 ft-dogleg severity curve section in the Utica formation of the Appalachian Basin in 2012. It delivered a 17.56°/100-ft build-up rate for a target change at 70° of inclination in the curve section and achieved an average ROP of 95.4 ft/hr for the 6,485-ft curve/lateral interval.
The practice of monitoring drilling from remote operating centers will pave the way for automated drilling and reservoir navigation, along with further development of high-speed telemetry and wired drill pipe, enabling two-way communication with the BHA, he said. “A challenge our customers have posed to us is to create added value from the downhole data we get today. A lot of our customers feel that there’s more value to be delivered through the tools we typically deploy. We believe advances in visualization, predictive services and understanding big data in the oilfield will define the future of directional drilling.”
SureTrak and AutoTrak are trademarked terms of Baker Hughes.
One solution is wired drill pipe, which provides rig controls and high-speed data to enable automated drilling, he continued. “With the speed of data coming from wired drill pipe, we are confident this system can provide the data to automatically control the trajectory of a wellbore much better and faster than even the best directional driller,” Mr Pink said.
Wired drill pipe, which provides a high-speed link with MWD/LWD tools, has been commercially available for several years. It has been used to increase efficiency offshore, but adoption into land drilling markets has been more limited, Mr Pink said. “For the offshore market, wired drill pipe is a no-brainer because of the cost spreads, but we believe it can be an affordable option for drilling challenging land trajectories. In the Eagle Ford play, for example, Precision Drilling Rig 591 used wired drill pipe to transmit MWD data at high speed to the surface.”
There are four stages to the industry’s transition to automated drilling, Mr Pink said, starting with the current ability of the directional driller to react to data coming from motors and mud pulse telemetry that may be delayed. The second stage would be moving to high-speed MWD/LWD data through wired drill pipe, at up to 54,000 bits/sec, allowing the directional driller to make decisions more quickly. The third stage is where automated steering capability, built into the rig’s control system, will eventually enable the rig to steer faster and more accurately than even the best directional driller.
“In five years’ time, we will reach stage four, where we can move the directional driller away from the rig site so he can steer and manage five rigs at a time from a remote operating center,” Mr Pink said.
He added that wired pipe will be the key enabler of multi-rig remote capability.
“Today, we can geosteer remotely and supervise pad operations, but we can’t directly control what is going on with the tools downhole. We still need humans on the rigs to control where the trajectory goes. The end game is to load a well plan into the rig, like a navigation plan is loaded into the autopilot of a plane, put the tools in the hole and let the rig just drill.”
Until that futuristic scenario with remote directional drilling becomes mainstream reality, operators and drilling contractors continue to rely on hardware improvements for efficiency and ROP gains, notably through RSS and mud motors. Oftentimes, the decision to use an RSS or a motor comes down to a cost-benefit analysis.
“Mud motors are an oilfield workhorse that has been around for decades,” said Neil Bird, Global RSS Manager for Weatherford. “The number of wells drilled with RSS is minimal compared to those drilled with mud motors. RSS technology was first deployed offshore, where high dayrates make it more cost-effective, or for complex land wells with extreme profiles. Today, RSS costs have come down substantially while reliability and availability have increased.”
A significant growth area in recent years has been motorized rotary steerables versus the conventional non-motorized designs that drill more slowly but can do directional work without sliding. “The only way to put more power to the bit is to place a motor in the string in order to transfer hydraulic power down the drillstring into the lower bottomhole assembly (BHA),” Mr Bird said. “This extra energy at the bit offers the same hole-cleaning quality of RSS but with improved ROP.”
Weatherford recently optimized its Revolution RSS point-the-bit motorized platform with the Mark 4, an upgrade of the 6.75 tool for 6 ¾-in. collar size and a 9.50 tool for 9 ½-in. collar size. The 9.50 tool targets offshore applications in the Gulf of Mexico, North Sea and offshore Mexico that demand bigger collar sizes and stiffer BHAs to withstand more vibration. The company is also introducing high-frequency vibration measuring boards into the tools.
The Mark 4 is designed for harsh formations in difficult drilling environments, such as the Bakken. It offers 12° dogleg capability with the option to go to 16°. “With some basic changes to BHA geometry and some simple engineering changes to the internal articulation of the bias unit components, we can increase to 16°,” Mr Bird said. “The theoretical modeling has already been performed, and the project to prove the Mark 4 to 16° dogleg severity is under way.”
Eventually the tool will provide the ability to put sensors right behind the bit. “Customers want to maximize how much horizontal section they can drill by building a tighter curve to maximize exposure to the reservoir,” he explained. “The higher the dogleg, the tighter the curve.”
Weatherford also is developing the second generation of its MotarySteerable directional control system, which uses a conventional bent mud motor while rotating to achieve directional control over the BHA without having to stop the drill pipe. It’s designed for low-cost, low-dogleg severity land wells. “In the US market, there are still a lot of land wells being drilled where it is not cost-effective to use an RSS,” he said.
Nomac Services, which is the directional drilling division of Chesapeake Energy affiliate Nomac Drilling, continues to use mud motors, which have been improved with shorter bit-to-bend models that can achieve higher build rates to drill 10° to 12° curves. “In the Utica play; we’re drilling as fast with conventional mud motors as we could with an RSS,” said Keith Edwards, Operations Manager, Nomac Services.
“Motors are being designed with new elastomer products, such as hard rubber power sections that allow us to run high differentials with greater reliability and increased ROP. In addition, there have been a lot of inroads in material strength on the metals we’re using to build motors, such as forged metal and titanium materials that last longer and allow us to rotate with higher RPM and fewer failures downhole.”
Over the past couple of years, the improvement of steerable PDC bits, which can drill the curve and lateral sections of shale wells in one run, also has brought a significant step-change to the US land market, Mr Edwards said. “With these bits, we can increase ROP without sacrificing steerability. Results vary by play, but we’ve seen ROP double in some areas.”
Agitators, which are downhole tools that assist with sliding, are being combined with top drives’ rotational control systems that provide the ability to slide and control the wellbore. “This is smart technology that allows us to establish parameters that can assist the directional drilling process with automated drilling systems,” he added.
Mr Edwards also has seen significant improvements in MWD/LWD capabilities over the past 10-15 years, specifically in circuit boards that expand the temperature threshold to 350°F and provide greater energy efficiency and improved power consumption of batteries. “With these advances in the components, we can now get more than 400 hours of battery pack, compared to 120 hours with older systems,” he said. “In the next five to 10 years, we will likely see MWD/LWD equipment reach 400°F capacity, which would be applicable in plays such as the Haynesville, where we have seen wells exceed 370°F.”
Nomac is also logging well operations in various plays across the US from the company’s Drilling Operations Center in Oklahoma City. “We program the MWD/LWD tools on location and put them downhole, but all the logging is done remotely,” Mr Edwards said.
Service quality, reliability
Hardware improvements have advanced RSS and mud motors. However, equally important are the gains made in service quality and reliability, said Jon Hill, VP, Marketing and Technique for PathFinder, a Schlumberger company. It provides directional drilling services for the unconventional land market.
“Enhancing the robustness of the entire directional drilling process, not just the downhole technology, has been a significant development. By embracing a culture of continuous improvement, we have made a substantial impact on reducing nonproductive time over the last decade. Today, for many land operators, the focus has shifted toward drilling efficiency, which requires the same holistic continuous improvement culture, in addition to technology introduction that yields operational and commercial benefits.
“In the unconventional market, the goals of our customers are often challenged by field economics with tighter and lower production rate reservoirs,” Mr Hill said. “Mitigating commercial risks as well trajectories become more challenging with deeper payzones, longer laterals, higher build rates and wellbore stability issues drives the need for higher performing BHAs.”
To that end, industry has seen the emergence of the manufacturing drilling approach to field development, which includes pad drilling and high-intensity drilling campaigns designed to achieve repeatable performance and reduce performance variability.
“From a risk-mitigation point of view, if it takes longer to drill these less economic fields, we’re not really aligned with the needs of our customers,” Mr Hill explained. Additionally, as well spacings get tighter, there is a growing need for survey management services to avoid well collisions.
“Remote drilling allows us to tackle performance variability and lessons learned by putting experts in a central facility, thereby providing broader oversight on multiple drilling operations and rigs simultaneously,” he continued. “This builds scalability into our customers’ operations as we can respond to demand changes very quickly and even add rigs on short notice if needed.
“We want every well to be the best well. In order to do so, we must get the production part of the factory on track, which requires technologies to understand geological variability, optimize well placement and deliver effective stimulations,” Mr Hill noted.
For horizontal land drilling, which dominates the US onshore market, well placement has improved through new MWD/LWD technologies. The Schlumberger iPZIG at-bit inclination, gamma ray and imaging service provides inclination measurements and gamma ray image data of the formation to optimally place the well in the sweet spot, even in complex reservoirs.
The iPZIG service enables the operator to precisely position the BHA, both stratigraphically and geometrically. An at-the-bit inclination measurement yields a real-time online dogleg severity indicator, which helps to minimize borehole tortuosity.
“Years ago, we would have placed the well in the sweet spot with multiple geological sidetracks and been challenged to figure out where the wellbore was in relation the seismic model,” Mr Hill said.
Revolution is a registered term of Weatherford, and MotarySteerable is a trademarked term of Weatherford. PowerDrive, PowerDrive Archer, PowerDrive Orbit, Microscope HD, Periscope HD and iPZIG are marks of Schlumberger.