Automation technologies must deliver efficiency, cost savings, safety to make economic sense on rigs, land and offshore
By Katie Mazerov, contributing editor
When Chesapeake Energy had the opportunity to be one of the first operators to test an automatic drilling system on a rig in Ohio’s promising Utica play earlier this year, the company took a forward-thinking view of what it might mean to be at the vanguard of what could be the future of drilling.
“In my view, the value of an automated drilling system comes out of consistency and repeatability, putting controls in place to remove the human factor, in this case the driller, and other variables in order to ensure that every rig runs above average,” said Rob Ford, Chesapeake’s district engineer for the Utica Shale. A key example, he continued, involves the connection process, which varies considerably based on the skill, speed and decision-making behavior of the driller and crew. It can also be impacted by whether the crews are working during the day or at night.
This Utica well was a testing ground for the NOVOS operating control software platform from National Oilwell Varco (NOV). Under the watchful eyes of two drillers, Chesapeake’s well plan, including all anticipated surface drilling parameters, was programmed into the NOVOS control system. With the operator’s affiliate Nomac Drilling, Chesapeake used NOVOS to drill a 7,000-ft vertical well section, representing what Nomac president Jay Minmier calls true automation.
“NOVOS did exactly what a good driller tries to do to increase rate of penetration (ROP) – monitor and adjust all the surface parameters like weight on bit (WOB), torque, rotation and pressure and controlling the drawworks and top drive,” said Mr Minmier, who this year serves as vice chairman of IADC.
NOVOS and its sister system, NEMSIS (NOV Enhanced Measurement System IntelliServ), which uses wired drill pipe to connect to downhole tools, are key features of the NOVA open-platform automated drilling system. It sits at the cutting edge of a new era that many believe is inevitable for an industry confronting the Big Crew Change while looking to optimize performance and reduce costs.
However, moving into this new era not only requires innovations to develop technologies, it also requires companies to recognize the value of these technologies so they can be applied in a meaningful way to achieve step-changes. While debate continues over how new technologies should be adopted and how quickly the adoption process should go, experts agree that technology for the sake of technology is not the answer. New technologies must deliver value in the form of safety, efficiency and economics to make sense in the oilfield.
IADC, SPE form new joint work group to develop roadmap for drilling systems automation
By, Katie Mazerov, contributing editor
The IADC Advanced Rig Technology (ART) Committee and the SPE Drilling Systems Automation Technical Section (DSATS) are collaborating to develop a drilling systems automation (DSA) roadmap outlining the steps anticipated in the development of drilling automation. Shell is among operators that have already joined the new group.
The roadmap will incorporate best practices from oil and gas and other industries, including aerospace, the military and academia, to address topics such as advanced controls and robotics, unmanned ground systems, cybersecurity and smart grids. The work is intended to reach a large audience using internet tools and will be available to all sectors of the oil and gas industry, as well as companies outside oil and gas production and consulting organizations.
The IADC ART Committee, which has been collaborating with DSATS for years to advance drilling automation, is supporting the DSA effort. “Technology is changing the way that equipment is used in the industry. Through the collaborative effort of DSATS and the IADC ART Committee, the industry is able to stay abreast on changing technologies. Giving members a voice during the development of automated equipment, processes and procedures is our main focus,” said Scott Maddox, director of IADC’s Drilling & Well Services Division.
John de Wardt, president of De Wardt and Co and one of three industry experts spearheading the effort, believes that DSA embraces many facets of the drilling and completion process requiring collaboration to achieve success “Furthermore, the adoption of DSA will have a profound effect on the roles and responsibilities of workers, organizational structures and business models.
“A roadmap is a very powerful tool for guiding the development of an emerging technology,” Mr de Wardt said. “It is a plan that describes short-term and long-term technology solutions to meet the technology application goals.”
Transforming the industry
Other industry leaders coordinating the effort are Dan De Clute-Melancon, technical adviser for Halliburton, and Ed Tovar, president of InTechSys, a technology consulting firm. “A collision of Big Data, the Big Crew Change, unconventionals, robotics, the evolution of business and the quest to achieve zero non-conformance is pushing us to transform into an automated oil and gas industry for the 21st century,” Mr De Clute-Melancon said.
The committee’s goals are to develop a comprehensive graphic showing anticipated development in steps over a multi-year period in distinct streams, such as technical and non-technical, along with a report describing the details and reasoning behind the steps in the graphic. The graphic will address issues such as automation interoperability standards and protocols, real-world and cybersecurity, human interaction and fail-safe controls, simulation and testing, personnel training, legal liability, global regulatory issues, sustainability and job creation, intellectual property, and the business aspect of an automated upstream oil and gas industry.
The roadmap will elaborate on the current status of each stream and work in progress and identify gaps and needs for research and development. Where possible, specific examples will be referenced and analogies used with other similar technology roadmaps.
“Automation has been implemented in several other industries, and overlap is expected,” Mr de Wardt said. “It is hoped that much of the evolutionary process, hardware, software and lessons learned can be applied directly or quickly adapted to the unique and challenging aspects of oil and gas drilling and completion systems automation.”
For more information or to join the DSA Roadmap Virtual Forum, e-mail email@example.com.
“Our current area of interest for drilling automation is optimizing ROP with an electronic control system to adjust weight on bit and rotary speed to continuously optimize the drilling parameters to achieve the lowest cost per foot of hole,” said John Willis, chief of drilling for Occidental Oil & Gas.
“Full automation, where the driller pushes a button to trip or make a connection, is not the best area for immediate technology development for land rigs,” he said. “That adds a lot of complexity for minor improvement. We don’t see a significant payoff right now, but there potentially could be one. We have a fleet of very high-quality rigs. Our rigs are working extremely well, our drilling costs are down this year, our drilling safety performance is significantly improved, and we continue to develop the full use of the capabilities we already have. ”
Where Mr Willis does sees value for automation is in remote control technology and advanced mechanization and instrumentation. Oxy uses existing automation, such as through managed pressure drilling, as well as automation built into the basic control systems of advanced rigs. Oxy has also been involved in field trials for ROP optimization systems and believes on-the-rig intelligent monitoring is a future area of interest to identify, warn against and even prevent rig operations that could hurt people or damage equipment or wellbore. “Any automation that can be implemented primarily through software, without mechanical changes or additions, has potential in the near term.”
Mr Willis listed the AC drive, which delivers fuel efficiency, as a distinguishing element of an advanced-technology rig. Other elements are having a highly modular, fast-moving design that reduces move time and an electronic control system that replaces air controls and the brake handle with buttons and joysticks. Some features can also be retrofitted onto older but well-designed SCR rigs. These include instrumentation systems, top drives, bigger pumps, the pipe makeup system, powered catwalks, a rig-walking system and a BOP handling system. “These elements have a much bigger effect on our program than automating a particular mechanical operation,” he said.
“Whether we’re using an older rig that has been upgraded or a modern rig, we need to be able to drill with polycrystalline diamond compact bits at maximum ROP, keep the hole clean, and make very fast and safe rig moves,” he continued. “Well-equipped and advanced-technology rigs make a dramatic difference on unconventional wells with long horizontal sections. But we’re also using advanced rigs on simple, vertical wells to reduce the total well cost. The priorities are a little different on improving an advanced rig that enables drilling a complex well and improving a rig to drill simple wells more economically. We’re focused on reducing well cost for all our wells, both the simple and the complex.”
Oxy operates approximately 70 rigs globally, almost all land rigs. Advanced rigs make up more than half the fleet, and most are equipped with features such as top drives, big pumps, pipe-handling systems and hydraulic catwalks. However, the company also keep a few small, older mechanical rigs on contract to drill shallow, simple vertical wells. “They work and are economical,” Mr Willis said.
Catalysts for change
When it comes to full rig automation, or autonomy, there is a wide spectrum of viewpoints among industry experts. David Reid, NOV chief sales officer and senior VP for global accounts, believes the industry is about halfway down its path to full drilling autonomy. He maintains there are multiple definitions for automations. “The barriers are more about culture and the current business model than the technology itself,” he said. “Crisis will be the catalyst to change the culture. Right now, we are having a people and a cost crisis. We have thousands of wells to drill but not enough skilled people to drill them.”
Slowly, industry is starting to look at automation as something more than just an interesting subject or an expensive way to get to deepwater and extreme drilling environments, he suggests. “Automation is actually what is going to get us from A to B. There comes a point where, when we start looking at ultra-high speed data capacities on both the surface and downhole measurements, combined with high-speed communication capabilities, we starting to see a potential for significant financial benefits,” he said.
“Field tests are showing that almost every time we apply independent decision trees for the machines without the interruption of the human, we see improvement, especially downhole,” he said.
“By creating a closed loop between the surface data and downhole data, we are allowing the well to tell us what is going on so we can make the necessary adjustments with human oversight, but allowing elimination of human involvement when not necessary.” The plan calls for NOVOS and NEMSIS to eventually be joined to deliver surface and downhole data. NEMSIS measures parameters downhole, sends the data back to the surface quickly through wired drill pipe, then makes changes at the surface machinery to affect changes at the bit, Mr Reid said.
For the NOVA system, “the financial discipline of land is fantastic for development, and we’re seeing enough value right now to do more testing,” Mr Reid said.
The case for automation
For Chesapeake’s Utica test well, the objective was twofold. “NOV wanted to prove the software and the automation features programmed into the system, and Chesapeake wanted to test the technology without adversely impacting the drilling of the well,” Mr Minmier said. “Both objectives were met.”
With NOVOS installed on Nomac’s Rig 77, the newest rig in the company’s Peake series, Chesapeake drilled the total vertical section of 7,000 ft in under three days, achieving an average ROP of more than 2,000 ft/day.
NOV’s AMPHION Integrated Drilling Control System operated in the background in the event something went wrong. Except for a few occasions when the drillers had to take over the controls in the intermediate section, the operation went off smoothly, with no downtime. Mr Minmier attributes the improved ROP to several factors, including the ability of NOVOS to make adjustments on a microsecond basis versus a driller making adjustments at a slower pace.
Further, NOVOS doesn’t need to take breaks and performs consistently compared with drillers’ variable skills and attention spans. “The NOVOS system also has the potential to bring younger, less experienced drillers up the learning curve much more quickly,” Mr Minmier noted. “Just hit the button and the computer will drill for you.”
Going forward, Nomac and Chesapeake are hoping to take NOVOS to the next level and drill the lateral and possibly the curve as early as Q4 this year. “We need to walk before we run,” Mr Minmier said. “Directionally, the curve is more difficult and requires a lot of adjustments.”
Citing culture and a hesitance to invest significant capital upfront to upgrade older, mechanical rigs to accommodate automation as a significant barriers to change, Mr Ford believes there will be challenges to get the industry to adopt technologies like NOVOS and move toward widespread utilization.
Citing aging equipment and a lack of capital, along with culture, as significant barriers to change, Chesapeake’s Rob Ford believes there will be challenges to get the industry to adopt such a new technology and move toward widespread utilization. “If this test had not worked, the driller and crew would have taken control of the rig exactly as they would have,” he explained.
“Automation isn’t taking away the driller’s job; it’s simply changing the driller’s job,” he continued. He noted that increasing activities related to the US shale boom, along with an aging workforce, has provided incentive for industry to automate the drilling process. “Automation has the ability to provide a quicker learning curve for the younger and less-experienced workforce of today’s oilfield, allowing them to perform at a high level. The new workers coming into the industry also will likely embrace new technology more readily.”
The case for mechanization
While drilling automation is getting a lot of attention these days, other technological advances have played significant roles in moving the industry forward and cannot be overlooked, said Tom Bates, chairman of Hercules Offshore. Mr Bates is a firm believer that technology must make financial sense for both the user and the provider. “Two relatively mature technologies, directional drilling and hydraulic fracturing, when applied in an innovative way in unconventional shales, created enormous value for both the industry and the American consumer.
“Automation, however, is also a relatively mature technology in other industries that has yet to translate to the oil and gas industry to a large extent,” Mr Bates said, noting he believes automaton is defined as using control systems with sensors and feedback loops to essentially replace the human interface. The term is also sometimes used to describe mechanization, which also has delivered value to the oilfield.
“The industry has done a particularly good job with mechanization,” he continued. “Iron roughnecks, for example, improve safety and quality because they create a reliable process driven by feedback from measurements that is at the fringe of automation. We’re not eliminating people but using a system to improve safety, reliability and quality of the product we are delivering.”
A similar incremental transformation has occurred with pad drilling and creating a factory-like environment in land operations. Mr Bates, who is also chairman of the board of Independence Contract Drilling (ICD), cited the case of Continental Resources, an operator that was able to reduce its cycle times by 35% and lower direct costs by 26% after switching from conventional to pad drilling in the Bakken. It was also able to bring on production faster.
Ed Jacob, chief operating officer for ICD, noted improvements in bit and motor technology are allowing operators to drill laterals of 10,000- to 12,000-ft or even longer. “What the industry has done is take mechanization to the next level, not by replacing people but by taking people out of harm’s way.” He sees a bifurcation of the current market, similar to an auto factory that is retooling. “We’re finally coming to a point in the life of some of these legacy rigs that provided excellent technology when they were designed but have outgrown their usefulness.
“At a minimum, new rigs are 1,500 horsepower, with AC top drives, iron roughnecks and hydraulic catwalks, all operated by humans,” he added. “The next step in land rig mechanization will be pipe-racking systems that take the human out of the derrick, which is safer and eliminates the risk of a catastrophic event.” Bi-fuel systems and the capability to walk the rig in multiple directions on pads are also becoming standard features. All five of ICD’s ShaleDriller walking rigs are working in the Eagle Ford, and Permian basins.
While the US land market may be the testing ground for a lot of drilling automation, the more expensive offshore sector, with permanent platform installations, will be where automation technology gains a foothold first, Mr Bates believes. “With spread costs ranging as high as $1 million to $1.5 million per day, the offshore market has an economic structure where any incremental improvement in time and costs is worth a lot compared to a land rig, where spread costs might only be $50,000.” This trend, especially true in deepwater plays, has already been seen in the integration of automatic pipe-handling systems into offshore rig designs, something that has not yet occurred to a significant degree in the land market.
“The offshore environment is also more conducive to other technological advancements, such as sensors in the rig floor and sensors on equipment and even on workers’ boots that enable systems to track people and equipment on the rig,” Mr Jacobs added.
Operators in the driver’s seat
From a drilling contractor’s perspective, said Dustin Torkay, technical superintendent for Seadrill Americas, most new technologies have been transferred from adjacent industries. “But, even though technologies may be mature in an adjacent industry, these technologies are considered new in the oilfield because of a slow technology adoption rate, which is typical of a heavy industry,” said Mr Torkay, who is also vice chairman of the IADC Advanced Rig Technology (ART) Committee and oversees its Future Technology Subcommittee.
“In our industry, people have often used the word ‘automation’ synonymously with ‘technology,’” he said. “Automation or technology, when added to a drilling rig, must show a clear value proposition.” Contractors have traditionally been risk-averse in promoting new methods that pose potential financial loss with minimal gain. “No one is ever punished for purchasing the tried-and-true method, but if someone deploys a new technology and it causes downtime, even the same amount of downtime, it is frowned upon.”
That thinking has put offshore operators in the driver’s seat to sponsor and accept the risk for new technologies they believe will add value. “That value may not be just dollars and cents. It might be improving a safety issue or moving people out of harm’s way,” he noted. “Contractors have always been open to technology step-changes focused on reducing downtime. Currently (post Macondo), there is a specific need for BOP technologies not only to increase equipment uptime but to meet the needs of constant and intense scrutiny.” The dual BOP feature on rigs is not a new technology, he explained, but installing them offers the benefit of reducing maintenance time between wells, which can save operators a spread cost of two to three times the rig dayrate for between-well maintenance.
“Cultural stubbornness and the current dayrate model do not incentivize contractors to adopt significantly new technologies and move forward at a faster pace to deploy advances, such as automated kick detection, and accepting wireless technologies for use offshore,” Mr Torkay said.
He believes cultural stubbornness and the “dated” dayrate business model are keeping the drilling industry from moving forward at a faster pace to deploy advances such as automated kick detection and accepting wireless technologies for offshore use. “As an industry, we still have a long way to go,” he said. “Many still hold the belief that the driller knows best and needs to be in full control. By comparison, in the subsea sector, the completions side of the business is moving at a much faster pace than the drilling side in what they are developing in terms of subsea architecture and control systems.”
He believes the next step will be the deployment of disruptive and/or enabling technologies, lower-cost options that force change by doing 90% of what conventional methods do, for a fraction of the cost. As industry continues to push into the ultra-deepwater and harsh environments, the emphasis is on size – 1,500-ton rigs, 20,000-psi BOPs and piping systems, he said. “However, rigs don’t just perform drilling operations. They are multipurpose tools. Sometimes a high level of automation can lead to a reduction in operational flexibility. In the future, there may be an option for smaller and more specialized rigs that employ the use of enhanced technologies and automation.”
Some examples of offshore drilling technology are equipped on Seadrill’s new-generation rigs that feature a sophisticated zone management system called PIMS (pipe interface management system). It manages the way various pieces of equipment interact with one another. For one client, Seadrill has installed simulators on two drillships going to the Gulf of Mexico that provide a full virtual representation of the drill floor equipment to facilitate onboard training.
“The value in this case is that it’s a way for us to provide hands-on experience with minimal risk to equipment while building measurable experiences and competencies,” Mr Torkay said. “Training and maintaining an experienced workforce is a major challenge for every contractor, and these simulators provide a partial solution to this problem.”
AMPHION is a trademarked term of NOV.
ShaleDriller is a trademarked term of Independence Contract Drilling.
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