Autonomous drilling system, open-platform rig control system, drill floor robots among innovations pushing drilling to next level



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By Katie Mazerov, contributing editor

After decades of discussion and debate, the industry has reached a tipping point, standing at the brink of what may become the biggest and most sweeping change it has ever faced – automation. No longer a pie-in-the-sky idea, drilling automation is fast becoming reality, driven primarily by the need for greater safety and efficiency. Leading the way is a mix of major operators, drilling contractors, rig designers and entrepreneurial innovators who are applying lessons from the aeronautics and auto industries and looking to NASA for solutions to propel drilling to the next level.

But will it be a revolution or an evolution? While many see automation as inevitable, there is no consensus over how to get there. For some, automation simply means a shift to a robotized process, with machines doing everything from picking up pipe to initiating the drilling process. Others want to take a more pervasive approach that would mean more than mechanization and where workers’ roles would be redefined.

“There is a lot of variability in what people mean by automation,” said Chris Papouras, president of Canrig Drilling Technology, a Nabors Drilling subsidiary. Canrig and Nabors have launched a major project to develop and build a highly automated land rig, with construction set to begin next year. “The art of automation is identifying improvements that deliver a change in the status quo as opposed to this nirvana of complete automation,” he said. “Our approach is to do things in stages and focus on value and performance enhancers. The industry is struggling right now over the idea that automation has to be an either/or proposition.”

Regardless of which path is taken, the next decade will bring significant changes from the drill floor to the control system. The rigs of tomorrow will likely be considerably more autonomous, or self-directed, and designed or retrofitted with state-of-the-art technology that will do everything from link the drilling process to the well plan, to eliminate dangerous and repetitive tasks. A significant factor in the automation push has been the boom in US shale plays, where the high density of similar wells provides an ideal opportunity to introduce automation, which carries the best advantages when repetition is involved.

“The industry has been talking about drilling automation for at least 70 years, but the concept has never been pushed over the finish line,” said Mark Anderson,

manager of drilling mechanics technologies for Shell. The company is currently testing prototypes of its SCADAdrill system in The Netherlands and the Marcellus and Eagle Ford plays. “Shell’s first patent on drilling automation – a drilling weight control system on a mechanical rig – dates back to 1942.”

SCADAdrill, which applies a Supervisory, Control and Data-Acquisition system to the drilling function, will begin rolling out by the end of the year in tight-gas plays throughout the US if the test-market implementations are successful. As early as 2014, Shell hopes to deploy a fully commercialized system in areas with high well density, including the Eagle Ford, Marcellus and Monty (Canada) plays, and in China and Queensland, Australia.

Developed in 2009, the system is an autonomous drilling and trajectory control system linked to the well plan. It monitors drilling parameters, determines appropriate controls that need to be communicated back to the rig and navigates the course of the wellbore. The system is being enhanced to perform consistent and reliable directional drilling. In this mode, it will automatically orient the tool face and slide-drill the required distance in the required tool face to correct the actual well path to the preprogrammed well path.

“It is important to understand that we’re not replacing humans with automatic drillers,” Mr Anderson said. “The driller activates the system and is always in control.” Once activated, the system starts the pumps and the rotation, then goes back to the bottom and drills a stand in rotary mode. When the bottom of the joint is reached, it circulates the appropriate amount of fluid and presents the tool joint at the correct height for the driller to engage the system and allow the crew to set the slips and make the connection.

What the system will do is take over the simple, repetitive tasks a rig worker does in a typical 12-hr shift, allowing the worker to perform more high-level tasks, such as safety, crew competency and preventive maintenance, Mr Anderson explained. “Nowadays, for a rig to operate, the driller must determine how much weight to put on the bit, the amount of rotary, and continually manipulate those functions to achieve optimum penetration. With automation, we’re going to the let the computer do that while the driller monitors the situation.”

Digital flow meters provide greater accuracy, speed A key element of automation is the need to know precisely what and how much fluid is flowing in and out of the wellbore. “Today, with the high cost of producing declining resources, accuracy is essential for operators who are trying to squeeze as many barrels as they can from a reservoir,” said Eric Heilveil, flow product manager for Siemens Process Instrumentation. The company recently introduced the Sitrans FC430 digital flow meter, the latest in the line of Coriolis flow measurement technology that can communicate digitally with control systems and programmable logic controllers, and with mobile phones via HTML. The meters deliver a higher level of accuracy than conventional analog flow meters used for measuring return flow on rigs. Analog flow meters often present barriers because they are not precisely accurate or repeatable. Sensor performance is often skewed well before the time the meters require manually recalibration, a task required by the API. With digital flow meters, the data is coming digitally from the sensor, which delivers a higher degree of precision, speed and accuracy on what is actually being measured. “Digital sensors provide more and improved-quality information over longer distances,” Mr Heilveil said. “While conventional flow technologies use volumetric measurements that can be compromised by temperature and pressure changes, the FC430 meter features a vibrating tube to determine how many lbs/min – instead of gal or cu ft – are flowing. Volumetric measure can easily be miscalculated – mass cannot.” The Coriolis sensors are designed to work in any environment. The meter measures the flow and density for separating oil and water and other fluids, so the operator can determine how to treat what is coming out of the ground. “The meter measures mass flow and density for a given volume and measures temperature, which must be monitored,” he continued. “In the past, expansion of oil to due to temperature increases was not a major concern, so the measurements didn’t have to be totally accurate. Nowadays, operators need to know exactly how much oil is contained in every barrel.” Open platform design

The US land market also will be the initial testing ground for National Oilwell Varco’s (NOV) open-platform, automated drilling system, NOVA, that will update the rig’s control system to combine downhole data with surface data to automate the drilling process and eventually move toward autonomous drilling.

“We are learning that with today’s capabilities in both drilling and completions, we can’t afford to drill wells with marginal assets to meet increasing global demand,” said Tony Pink, vice president, automated drilling applications for NOV. “To develop these assets over the next three to five decades, we’ve got to speed up the process.”

NOVA encompasses a new operating control software platform, NOVOS, which includes a planning component that builds the well program into the control system, allowing the rig to automatically follow the well plan, similar to a flight plan. “The operator loads in the depths of the formation, trajectory of the wellbore and bottomhole assembly, and the rig checks against that plan as it drills ahead,” he said. “It’s like Auto Pilot for rigs.”

The key objectives are to improve operational safety, reduce nonproductive time, reduce well construction time by 30% to 50% and drill a quality well in the right place, safely. The rig also will be able to run with fewer people. “People will move away from the heavy lifting and dangerous work and let the machines do that,” Mr Pink said.

A second feature of the system is NEMSIS (NOV Enhanced Measurement System IntelliServ), which uses wired drill pipe to connect to downhole tools, enabling data to quickly come to the surface for direct machine control. The system is currently using high-speed downhole data to control the drawworks and was used recently on a well in the Marcellus.

The open system, or platform, concept means the surface control system will have an application management system, allowing any company, for example, to write an “app” to the control system and perform intelligent well functions using the system as an interface to the rig. “In this way, we’re making connectivity much easier,” Mr Pink said. “Our goal is to provide the drilling contractor with a way for service companies to plumb into the control system very easily.”

Andrew Bruce, NOV’s vice president of controls, said that to develop the system, his company conducted methodical research by interviewing some 30 companies from all aspects of the business. “The industry wants an integrated approach because everyone has a role to play in the process of drilling a well,” he said. “If we keep specializing by solving one industry segment problem at a time, we are narrowing the scope.

“We didn’t want just an incremental improvement on existing controls, we wanted to engineer a step-change in the way rigs are controlled in the future,” he continued. “By taking a more holistic approach with the open platform, drilling contractors can tailor their rigs, write an app for their purposes and use their own drilling algorithms to improve the drilling process.”

He also believes the timing is ideal. “This is a perfect opportunity to capture the expertise of the people who are retiring but also introduce this system to the young people coming into the industry who grew up with computers and are very comfortable with technology.”

The goal, he said, is to provide consistency across drilling crews to deliver consistent and efficient results. “Today, the drilling process involves a human interpreting the well plan, controlling each piece of equipment, such as the top drive and the drawworks, and making sure they all fit together. This system removes the guesswork and delivers a lot of standard safety features that don’t exist now to keep people out of harm’s way.”

Automating step by step

However, as industry moves forward with automation, added value for the customer, culture and scalability must be considered as well, said Canrig’s Mr Papouras. “We can create a tremendous amount of value by automating in steps,” he continued. “Steps are necessary, and culturally, we need to go through all the steps because introducing too much too fast can result in failure.”

In keeping with that value-added philosophy, Canrig’s automated rig design, now under way in collaboration with Nabors, will eliminate human handling of tubulars and integrate all Canrig functions, he explained. The design is intended to reach a broad range of markets and may have multiple versions as a function of depth.

“The drilling process is very complex – for example, no one has fully automated the steering process,” he continued. “If we don’t address that subset, we will fail in attempting to automate the ability to drill a full stand down. Our philosophy involves looking at the pieces we want to automate – ultimately, all the work flows on the rig – to improve performance. We evaluate whether we are automating something for the sake of automation, or creating something valuable for our clients. There’s a trade-off, however. As automation gets more complex, the cost increases.”

He cited the development of the ROCKIT suite of tools for directional drilling as an example of how automation can evolve successfully. The first phase of the technology allowed a directional driller to use the top drive to oscillate the drill string and break up friction in order to speed up the drilling process when sliding. The second generation, ROCKIT HEADS UP DISPLAY, is a feedback system that helps the directional driller slide more effectively by scoring how well he or she is keeping the angle of the tool face. ROCKIT PILOT automates the process, eliminating the third-party directional driller.

“If we had started with all three phases at once, this would not have been a successful product,” Mr Papouras said, noting the system has been installed on more than 200 rigs. “Our approach is to target something we hope will create specific value for our clients, implement it, then look at timing implementation of the next stage.”

Canrig’s ability to retrofit all of its 1,000-plus top drives and the Nabors PACE rigs into a standard code and automation hardware product allows the company to achieve scalability in automation implementation. For example, REVit, which mitigates stick-slip, was installed on more than 50 top drive systems in approximately six months. “Having one automated rig is not only very expensive, it is not going to move the needle in terms of automating the industry,” he pointed out. “When we look at what we want to automate, we have to consider how effectively we can scale it.”

While industry has robotized certain functions, safety, not repetition, has often been the driver, he noted. “Most of the industry has moved to automated wrenches instead of manual tongs, but if the safety aspect hadn’t been there, I’m not sure the technology would have been developed. Robotics has played a huge role in the automation process, but integrating the various stages of a robotized process – tripping, for example – is where it gets difficult.”

Looking ahead, he believes cooperation among the various industry sectors to integrate technology advances into one control infrastructure is critical. Challenges related to mobility, as mobile rigs are harder to retrofit, the number of older, working rigs that will take time to retire and obstacles to repetition also must be overcome.

“There is value in a machine doing a task again and again, but there is so much variability in the drilling of a well that the value of repeatability can be lost,” he said. “Down the road, we will see a much simpler system with fewer people, but a lot of steps need to be automated along the way.”

System takes hands out of pipe-handling By Katie Mazerov, contributing editor Pipe-handling, considered one of the most hazardous and time-consuming jobs in the oilfield, is a key issue being addressed as the drilling industry continues to progress on the path toward automation. To enhance safety, lower costs and reduce nonproductive time (NPT), Weatherford has enhanced its Tubular Management Services to provide an offline mechanized and hands-free system at the well site for the make-up of connections and moving pipe from rack to rack, reducing the use of mobile machinery and cranes. “Tubular Management Services (TMS) is all about the inventory management and preparation of pipe for delivery to the well site,” said Aaron Sinnott, global product line manager for Weatherford’s Tubular Running Services division. “With this system’s configuration and application, we can make up the casing and drill pipe in double or triple stands offline (off the critical drilling path), and dramatically reduce the number of connections made up at the rotary table. The system is ideal for situations where there are a lot of rig moves or batch-setting operations, because we don’t have to break out the entire drill string between wells.” The drill string or work string can be laid out in doubles or triples following the end of the well and broken down off the critical patch while the rig prepares for other operations around the rig move, he explained. When possible, the drill strings can be transported in doubles to the next location, saving further critical path time. Historically, the system was located mainly in workshops. Advancements in the applications now allow the technology to be deployed to field locations and well site operations. Using the horizontal offline make-up and handling system, the casing and tubular pipe are laid out horizontally for inspection and preparation and rolled with a hands-free mechanism onto the loading table, which feeds the pipe into the bucking unit machine. The bucking machine makes up the connections and automatically feeds the drill pipe and completion tubulars out so they can be transported to the drill floor. “We’re seeing significant savings in tubular run times,” Mr Sinnott said. “The process lowers risk exposure by reducing the amount of time workers spend on the rotary table and the rig floor making connections, and significantly reduces operating and maintenance costs on handling equipment. The rig crew can make up the connections offline in a controlled environment while critical path drilling continues.” TMS with Horizontal Offline Make-Up and Handling (HOM) has been used for offshore operators in Karratha, Western Australia to transport, via boat, double stands of drill pipe, casing and completion tubing to the rig, and in Port Fourchon, La., where pipe was made up in doubles in an onshore facility and shipped out the rig offshore. 10-well project in Asia The HOM system is being used by a major operator in Asia to reduce NPT and critical path time during drilling operations for a 10-well land field and to bring the wells on-line more quickly. For this situation, the operator wanted to make up double stands of 13 3/8-in. and 9 5/8-in. casing as well as 4 ½-in. and 3 ½-in. stands of completion tubing with the portable offline make-up system. The system was also used in the handling and break-out of drill pipe doubles on location. The preparatory services were done at an existing facility, and the single joints were shipped to the rig location for the bucking process. The mobile bucking and handling system included Weatherford’s 20-160 ComCam unit with an integrated free-floating backup side with a mounted centering jack, a hydraulic power unit and a remote control unit to create the hands-free component by which the portable pipe-handling system built and broke out double stands of casing and tubing. The system also broke down the drilling tool assemblies on location and provided a mechanized system from pipe rack to pipe rack, reducing the use of cranes. Comparing the HOM system and application with conventional pipe-handling and running methods, the HOM application reduced time on operations requiring tubular and casing make-up and break-out by 30%, Mr Sinnott noted. “Over the period of the 10-well program, at a rig dayrate cost of $65,523, this amounted to a savings of nearly $1.5 million and 23 days – enough time to drill and complete an additional well,” Mr Sinnott noted. To date, the run rate times of the 3 ½-in. and 4 ½-in. completion tubing have been reduced 34% and 38%, respectively.

Built-in redundancy

Ensco also views automation as an evolutionary process, where proven technologies can be enhanced as the industry ventures into challenging ultra-deepwater and ultra-deep reservoirs. “We are all in favor of value-added change, but we need to be careful we aren’t increasing our clients’ business risk,” said Mark Diehl, vice president, engineering.

Ensco continues to be engaged in an ambitious newbuild campaign, with three ultra-deepwater drillships and three harsh-environment, ultra high-specification jackups under construction, all featuring state-of-the-art automation on the drill floor. “We differentiate ourselves with enhanced reliability, capability and durability in all our systems,” said John Knowlton, Ensco senior vice president, technical. “With the very rugged, deepwater environment we’re operating in and the robust equipment we need, systems can break down. To offset that, we also build in redundancy.”

The company is outfitting its newest drillships with advanced dynamic positioning (DP) and power management systems. DP features will enable the crew to tune into two satellite systems and will include four computers, instead of the required two. Built-in features on the power management system allows for automatic isolation of a faulty component and remove it from the power grid without disrupting operations, Mr Diehl said.

The same is true of the thruster system that keeps the rig centered on the proper location. “Our ultra-deepwater rigs will have redundant 5.5-megawatt thrusters that are repairable offshore,” he pointed out. “The latest versions are retractable into the hull, so we can overhaul them in situ while we continue operating. This advance can create huge cost savings.”

On both the drillships and new jackups, the drill floor is fully automated with iron roughnecks and single- or multiple-column pipe rackers for racking triple and quadruple stands of casing or tubing. “These systems allow us to drill ultra-deep wells that are deep both vertically and in terms of total depth conditions that require extremely heavy drill pipe and large casing strings that are impossible to operate manually,” Mr Knowlton said. “With this automatic pipe-handling system, we can rack back large lengths of pipe, up to 40,000 ft, and 10,000 ft of land strings, plus strings of 14-in. or 16-in. casing offline, so when we’re finished drilling we can complete the cementing job more efficiently.” The drillships are also equipped with two column rackers so operations can continue even if one goes down.

Redundancy is also built into the drillship pipe-handling systems that bring the pipe to the deck horizontally and in the riser-handling cranes. “When we’re running the riser, we have two cranes that can handle the riser at any given time,” Mr Diehl said. The benefits go beyond efficiency. “Ultimately, this equipment is enabling us to carry out difficult and dangerous tasks in a safer manner by taking our workers out of harm’s way,” Mr Knowlton said.

Ergonomically, automated systems have matured, with more user-friendly chairs, screens, consoles and other equipment and better noise control, he noted. “The work is more complex but, in some ways, easier for the rig crew.” At the same time, however, automation has also expanded the scope of work on rigs, such as offline pipe-handling, and added equipment that requires specialized maintenance.

“We’re not reducing our need for people,” Mr Knowlton said. “It’s more about increasing our capabilities and scope of service for our clients. We need to achieve improvements in reliability, repeatability and in minimizing maintenance of the equipment. Then, we will start to see real efficiencies occur.”

Robotized drilling floor

Some, however, are taking a more ambitious approach, at least for some phases of the drilling operation. A small, Stavanger, Norway-based company is developing a prototype of a system to completely robotize the drilling floor in a joint industry project with three major operators.

“A robotic drilling rig consists of multiple robotic machines and software that can be retrofitted onto any vessel where they talk to each other like humans to complete tasks such as tripping pipe, considered to be one of the most tedious and dangerous jobs on the rig,” said Kenneth Søndervik, vice president, sales and marketing for Robotic Drilling Systems, which is 30% owned by Statoil Technology Invest.

Mr Søndervik expects the fully robotized drill floor robot, which operates as a cross between a roughneck and an air-tugger, to roll out commercially in Q4 this year, followed by the robotic pipe-handling system. The systems have been run more than 200 times in a testing facility. They are being designed for the drill floor only, not for downhole operations.

The robots will basically do the same work that the workers are doing today – fetching pipe and equipment, cementing equipment, changing out the drill bit, picking up the radioactive source for the BHA – all tasks required for a standard drilling operation, but doing it robotically, he explained. For unplanned events, the robots can be remotely controlled from anywhere in the world.

“All our systems will be open source, meaning third-party vendors like service companies, can tap in and tell our systems what to do. This is robotization beyond automation. The new rigs coming out today may have automated features, but they are not robotized or autonomous – there’s a big difference. You will not need to tell our machines how to do the job, only the end goal.

“One of the reasons progress has been so slow in this industry is because we haven’t been looking at the drilling process with new eyes,” he continued, noting that most of the development work for the robotized rig systems is being done by people outside the drilling industry. The robotic system software, for example, is being developed in conjunction with a Massachusetts-based company called Energid. Robotic Drilling Systems also has an agreement with NASA to develop an autonomous system along the lines of the Mars Rover.

Designed with extreme climates, such as the Arctic, in mind, the no-hands system will be 100% robotized, with no workers on the drill floor, he explained. The second phase of the project will apply the systems currently being tested to a riserless rig that will sit on the seabed itself, making it possible to drill year-round in places like the Arctic, with no workers on board.

“On a robotized rig, everything will be controlled by electric machines which are more robust, easier to control and maintain, and much more accurate, within a tenth of an inch, than hydraulic or pneumatic systems,” Mr Søndervik said. The machines will have internal surveillance systems that will monitor such issues as why an electric motor needs more energy or is generating more heat, or when the motor is nearing the failure point.

The systems also will be standardized. “Today, it is common to have multiple types of hydraulic arms for one specific task,” he pointed out. “All our parts will be interchangeable as much as possible.”

The company has also incorporated easy controls and visual aids in the control room. “Over the last decades, electronics has seen an enormous push in user interfaces, making it both easier and intuitive. We have taken the same approach with our man/machine interface. For instance, you can control our robots using a standard gamepad,” Mr Søndervik said.

In transforming to a robotized system, people will be assigned to new tasks, not displaced, he emphasized. For example, the roughneck will become a mechanic. “With this approach, not only can we reduce the cost of drilling wells, we can drill a lot more wells going forward.”