Over the next 10 years, thousands of wells are planned to tap unconventional resources in North America alone. As drilling technology develops, the industry will begin to make uneconomic wells in unconventional resources economic. The biggest drivers for the operators are drilling efficiency and cost.

E&P interviewed experts in different aspects of drilling to find out what technology these companies are developing. Efficiency and effectiveness continue to be the key emphasis in drilling, whether it is in deep water or onshore unconventional plays.

Safety is at the top of every list of priorities when it comes to introducing new technology, followed closely by environmental concerns. There is an emphasis on simplifying the technology to make it more reliable and available for operators and contractors. Being able to gather downhole data and use it in predictive software for advanced warning of potential problems is gaining more attention.

Because of the differences in unconventional plays and the need for factory drilling, the industry is targeting fit-for-purpose tools and technology.

MWD targets improved drilling efficiency, production effectiveness

With longer horizontal laterals, operators want to know more about drilling dynamics downhole. MWD/LWD tools are meeting the challenge with more rugged, robust technology along with more automation in the technology.

“Operators want more information about the efficiency of their drilling as measured down at the bit, and they are looking for more information about the geology,” said Paul Deere, founder and president, Tolteq Group LLC. “Operators are frequently requesting the availability of more information so that they can make decisions while they are drilling. They are getting away from preplanned drilling and starting to make real-time decisions based on what they see in the geology.”

The systems and tools that comprise MWD have evolved, he explained. The electronics have improved in quality and are a lot smaller. Even the mechanical materials have improved.

“However, basic directional measurements and sensing elements still use the same physics for what’s needed to navigate the formations. What has changed is the processing of that information and the devices required to do that,” he continued.

The most critical information that MWD gathers is directional information. “The main point of the MWD is to be able to steer,” he added. “That’s number one. If the tools are not telling the driller where they are located to help steer, it doesn’t matter how good the other stuff is. Getting accurate data back to the surface is critical so that they know that they’re drilling efficiently and can increase their ROP.”

Enhancing MWD measurements

In the early days of MWD, operators were looking for the direction the drillstring was headed, which was just enough information to meet the well plan. Now, if there is more information about the downhole dynamics and accurate formation data, operators are appreciative.

“Several years ago we put in shock and vibration data that could be sent to the surface. Everyone jumped on that and said, ‘We want access to more drilling dynamics. We want to know more about what is happening downhole.’” Deere explained.

Providing that additional data is Tolteq’s focus. The company sells its equipment worldwide and uses the information from the equipment in the field to improve MWD/LWD systems and tools.

“Our long-term vision is to build more integration with MWD, particularly with LWD components and the BHA [bottomhole assembly],” he said.

As he pointed out, much of the data gathering has become standard. For example, all operators want gamma ray measurements so they can tell what type of formation they are in.

“There is a lot of information available, and we provide access to much of it, but we are constantly asking ourselves, ‘Can it be refined? Can the information that we send up to the surface be more accurate and timely?’” he continued. “There is definitely room for increased measurements and better understanding of those measurements. We need more bandwidth, which would get more information to the surface.”

Improved use of measurements

Deere said that what needs to be developed to improve drilling efficiency and production effectiveness is better understanding and use of the measurements.

“More logging instruments need to be developed that can tell you not just omnidirectional types of measurements but actually provide a visual indication of the formation’s characteristics,” he added.

There are other types of information needed about downhole dynamics. For example, drillers are putting agitators on the drillpipe along with other equipment to “move the pipe down because gravity is not working for them. This places strain on the sensing equipment that’s downhole because [the sensors] are subjected to more shock and vibration. To meet some of those demands, we are developing top-mount sensors that are more secure instead of the retrievable pulsers that are not locked in place,” he explained.

“We are also developing more robust boards and shock-vibration snubbers to meet those demands,” he added. “The environment has changed a lot since they started doing these longer reach horizontals.”

As far as placement of the wellbore, Deere said operators always have a strong, detailed plan of what they want to do and are able to place the drillstring where they want. When they have access to more information, they can drill a lot more smoothly and efficiently. The result is less dogleg; it’s a smoother bore. “But if they are making decisions based on what they see in the geology, there may be some deviations from the well plan that will hopefully increase the return on the investment in the well.”

The industry is moving toward different types of tools for different applications. For example, in the Woodford shale, the use of lost-circulation material (LCM) is a big issue.

“We’ve developed several tools to meet that demand,” he explained. “There are some formations that take on fluid. They’ll put LCM in the mud system and pack that formation off so it doesn’t take on fluids, trying to plug holes. We’ve got a pulser down there that is opening and closing a hole to provide a signal up to the surface. The LCM wants to plug that off as well.

“There are quite a few differences between formations, rigs, and drillers. Our goal is to develop complete systems that will meet all the demands. That’s what our customers expect, and we are rising to the occasion,” he emphasized.

Fit-for-purpose technology drives drilling economies

Drilling automation in the industry is generating a growing amount of interest. Many people are trying to figure out where it is going. Automation is really about the repeatable drilling of hundreds of wells and, in the long term, thousands of wells.

“Automation is obviously about delivering real-time control of the drilling process to make sure that the process is repeatable and free from errors,” said Clive Rayton, vice president of drilling service solutions for Baker Hughes. “We can leverage the expertise we’ve got out there in terms of people and stretch that across a big portfolio of unconventional and deepwater rigs. It is really about repetition. It is about risk reduction, reducing nonproductive time [NPT], and ultimately improving performance by closing the measurement-execution loop.”

Striving for closed-loop automation

The culmination of drilling automation will be when the entire drilling process is being controlled in a closed-loop fashion. The technology will drive the drilling process. It will help in an unconventional wellbore manufacturing environment by cutting down the risk of human error.

“It boosts the effective experience base in the field because it takes that experience and captures it in an automated system, which then allows people to leverage this knowledge across all of the rigs that they have,” Rayton said. “Ultimately, drilling automation is going to improve efficiency by reducing NPT due to human error. This is a critical aspect, and it’s going to evolve through time.

“Right now people are looking at boosting the drilling rates through automating the process. But you can see that soon people will be directionally drilling wells without the need for a directional driller or by just having remote oversight from a directional driller since the system is basically drilling the well for them. You can really see things evolving through time to true automated drilling,” he emphasized.

Service solutions for drilling

With a lot of operators moving toward manufactured drilling and fracturing, Baker Hughes is working on what is needed to improve the process and make it more effective. As the industry has moved toward pad drilling, for example, it has created a lot of operational efficiency and reduced the environmental footprint.

“Technology has evolved to be fit-for-purpose for this manufacturing drilling environment,” he continued. “It’s become standardized for unconventional drilling and unconventional completions, which wasn’t the case three or four years ago. At that time we were using a lot of technologies that had been developed only for conventional drilling.”

For example, Baker Hughes developed the FracPoint multistage fracturing completions system and high-powered drilling motors for long horizontal sections. “The FracPoint system was developed as a fit-for-purpose solution for the unconventional manufacturing drilling environment. These are now standard technologies, whereas three or four years ago they were more niche products. It is really the fit-for-purpose technologies and processes that are improving well manufacturing efficiencies,” he said. “It’s driven by development of technology that is truly designed for the wellbore manufacturing environment and unconventionals.”

Improving drilling efficiency

One key piece of technology that has dramatically improved drilling efficiency is the rotary steerable system (RSS). “It is a mature technology in many applications, but in terms of unconventional drilling it is new,” Rayton said.

The technology is continuing to advance. One example from Baker Hughes is its AutoTrak Curve RSS, which allows operators to drill high build-rate curve sections and the lateral sections in one run.

“That was really an evolution because prior to that tool wells required two different BHAs, and drilling efficiencies weren’t optimum,” Rayton said. “The AutoTrak Curve assembly allowed us to drill both of those sections in one run with high drilling rates. It is a cost-effective solution for operators that was developed specifically for the manufacturing unconventional drilling environment.”

That is RSS technology that’s fit-for-purpose for land drilling. It was launched last year.

The company also just launched its SHADOW series frac plug for plug-and-perf operations. There is a dissolving element in the plug that eliminates the need for the operator to drill out the plugs. “Again, this tool is really focused on efficiency and time savings, and it’s truly fit-for-purpose technology for this environment,” he said.

New tools being developed

Unconventional reservoirs are not homogeneous. Formations can have widely different characteristics across a relatively short distance. A key part of what’s evolving now is really on two fronts. One area of focus is reservoir navigation, where specific LWD technology is being used to stay in the right zone, the sweet spot within the unconventional reservoir. The main service deployed on such applications today at Baker Hughes is AziTrak, which is an azimuthal resistivity tool that allows the operator to see the different beds within the formation.

“What we’re developing now are much deeper reading tools that can see farther into the formation to allow the operator to react faster and give a better chance of staying in the right zone. That’s something that we’re starting to deploy in the field, and it’s a tool for the future in terms of widespread application,” he added.
“The other piece is using specific LWD technologies to understand what we’re drilling through as it applies to the completion. With the move away from just geometric completions of the well, we can use image and other LWD logs to see where the most fractured or brittle parts of the formation are and then design the completion appropriately based on those image logs.

“We can then pump the frac stages that are designed specifically for different formation properties and zones, so we’re moving away from just treating every part of the formation the same way to where we really tailor a completion that is based on evaluation data that we’ve measured when we are actually drilling the well,” he explained.

In deep water, the company is using a steerable liner drilling technology, SureTrak. The system has a rotary steerable BHA that drives the liner, basically drilling down the well with the liner in place. The BHA is then pulled out, and the liner is left in the well. This technology and its application is unique in the industry.

Revitalizing drilling motors

One of the basic technologies that has been used for many years is drilling motors. “Drilling motors have been the workhorse of directional drilling in US land for many years,” Rayton explained. “What we’re doing now is upgrading a lot of that technology to really take the next steps forward in terms of performance.

“Through this year we’ll be launching a series of new motor technologies aimed at drilling the vertical section, the curve section, and the lateral section in unconventional wells. That’s exciting. Reengineering and relaunching technology have been and will continue to be at the forefront of activity. We’ve actually spent a lot of resources reengineering and improving these tools,” he said.

HP/HT oil, gas projects benefit from geothermal technology

The Haynesville shale has been and will again be a major driver for HP/HT tool development to 204°C (400°F) capability – but only if natural gas prices rebound to revive interest in shale gas drilling in the high-temperature plays.

“I think the natural limit for HP/HT technology is on the financial side,” said Gerald Heisig, senior vice president and general manager of the drilling division at Scientific Drilling International. “It is a fairly small market, and the investment requirements to get there are quite high. There is risk for service companies, specifically for a mid-sized company like Scientific Drilling International, to make this a focus and a strategy.”

In Heisig’s opinion the main hurdle is the temperature. The pressure is less of a challenge. “When people talk about HP/HT, a lot of the applications tend to be one or the other: high temperature or high pressure. There is a high-pressure market in the deepwater arena. However, there is a limited group of applications challenging both the temperature and pressure,” he explained.

Scientific Drilling is predominantly an oil and gas drilling service provider; however, certain niche technologies have given it a strong position in the geothermal marketplace. It has developed wireline-conveyed sensors for steam quality logging up to 316°C (600°F) along with caliper and survey measurements.

“We are currently developing high-temperature electronics to achieve the same reliability with our standard systems rated to 150°C [302°F] for electronics rated up to 177°C [350°F]. To get there, we have made major investments into environmental and destructive testing capabilities. The 177°C capability is driven by our focus on the North American unconventional market, which is limited to 177°C,” Heisig continued. “The highest temperatures are encountered in the deepest section of a well; hence, the failure costs are particularly high. As such, there is a lot of work going on in the service industry to push high-temp range MWD reliability.”

Drilling expertise transfer

On a routine basis, the company transfers drilling expertise and best practices from geothermal applications into high-temperature oil and gas applications. This starts with planning a high-temperature well as simple as possible, he explained.

“If you have to do directional work, for example, consider doing that work in sections where you can run MWD at normal temperatures. Then simply align your well to drill straight ahead into the high-temp area. There are staging practices to enter a wellbore and cool down the electronics in between by circulating, among other temperature mitigating best practices,” he added.

Also from its geothermal applications, Scientific Drilling has experience in flasking sensors and electronics. Deployed via wireline, sensors and electronics will spend only a limited time in the high-temperature environment, he explained. For some cased-hole logging applications the electronics are within the flask while the sensors are outside, e.g. spinners for steam quality measurements.

High-temperature feasibility studies
Scientific Drilling is undertaking feasibility studies to go to even higher temperatures. “We are evaluating everything about the electronics, including hybrid electronics, components, soldering techniques, sensors, active cooling options, and other related options,” Heisig said. “We are developing sensors that will work in environments up to 316°C to identify fluid properties such as density.”

Targeting high-temperature projects

For each HP/HT project, operators need to determine the bottlenecks to that project. “Then you can see what is necessary to overcome this bottleneck or maybe work around it. You can revert to traditional drilling methods such as rotary drilling without motors or RSS and take electronic multishot surveys,” Heisig said.

Traditional electronics design and manufacturing methods have a temperature limit in the range of 200ºC (392ºF) due to limitations in high-temp soldering. Completely different techniques must be considered for higher temperatures to install electronic components on a board. Some processes under investigation include a brazing process. That is a very different process from soldering and requires specialized equipment, materials, and skills.

“For true high-temperature applications, essentially everything related to electronics development and manufacturing for normal temperatures has to be questioned, from coating to glues and final assembly. To test properly, you have to build a specific system from scratch for the high-temp environment above 200ºC and look at every single aspect of the manufacturing process,” he emphasized.

Cased-hole logging

The Gulf of Thailand is a major high-temperature area and a significant area of focus for Scientific Drilling. The company works closely with local operators to provide solutions for certain cased-hole applications.

The Thailand market is a good example of what Heisig mentioned. “Operators there have been impressively successful in optimizing their drilling programs,” he said. “The attempt there is to try to keep the drilling as simple as possible – do all the directional work in the proper sections and then drill the reservoir sections with the simplest directional control technologies possible. After the drilling and completion we often provide the definitive survey to give the customer final well location and placement data.”

Natural-gas powered rigs improve environmental footprint

Drilling contractors are fully aware of the environmental impact of drilling operations on landowners and communities. Contractors emphasize new technologies that improve safety, drilling efficiency, and environmental footprints.

Patterson-UTI Drilling Co. LLC focuses its technology on safety, reliability, and mobility while bringing the best technology to the market in those areas as a drilling contractor. At the same time, the company also values the operator’s perspective in terms of technology to improve efficiencies, said Matt Pye, Patterson-UTI’s senior vice president of marketing.

“We’re always interested in knowing not only what’s going on in rig technology but also in what is going on below the rotary table in terms of the efficiencies that can be gained in that area,” he said.

Mike Garvin, Patterson-UTI Drilling’s senior vice president of operations support, added, “We also look at it from the perspectives of the communities in which we operate. We ensure that we’re providing technologies that are conducive to being good stewards while we operate.”

Environmental impact of pad drilling

Landowners and communities are aware of the surface impact of oil and gas drilling. With the advent of pad drilling, the industry has been able to reduce the footprint left behind when oil and gas wells are drilled.

“It allows us to drill multiple wells while minimizing any disturbance to the landscape. I think that’s good for the community. It is good for the industry. It is good for the US. From that perspective, I think there’s huge value there,” Garvin said. “Without being able to pad-drill, you’re building a lot more roads through the environment; you’re creating more drillsites in the environment. Pad drilling can minimize potential for environmental incidents. I think pad drilling technology allows us to be more environmentally aware and conscious.”

Pye pointed out that this technology reduces road traffic alone by 70% – even 80% in some cases – which adds to the value.

Running on natural gas

With increasing natural gas reserves and production, the impetus to move to natural-gas powered rigs, vehicles, and frac spreads has been accelerating over the past three years. These natural gas technologies impact the environmental footprint, especially with emissions.

“We currently have 28 of our rigs configured to use natural gas as the primary fuel source. We’re continuing to build new rigs and retrofit some of our existing rigs. By the end of the year we’ll have approximately 45 rigs that are capable of operating on natural gas. That’s just good for everybody. From an economic perspective, it provides value to our customers, and as we all know, it’s a clean burning fuel,” Garvin continued.

One of the unique aspects of Patterson-UTI’s fleet is that it is a market leader in terms of rigs that operate on 100% natural gas, according to Pye. “We currently have seven of our rigs running on 100% natural gas. We anticipate having nine or 10 by the end of this year.”

The engines are capable of using field gas, compressed natural gas (CNG), LNG, or propane. “Obviously field gas is the fuel of choice and then LNG/CNG after that,” Pye added.

Walking rigs

Patterson-UTI expects that every new rig it builds this year will have walking capabilities, Garvin explained. The company has used walking rig technology as an option for the operator since 2006.

“The technology for walking capability has been engineered into all of our new APEX rigs, and we’ve also developed an engineered solution to put a walking system on any existing rig in our fleet,” he said. “We can convert any of our rigs into a walking rig. We’ve been very proactive in terms of making sure that, regardless of the rig in our fleet, we’ll have a solution to make it a pad drilling rig if that is what the customer wants.

“I think going forward we’ll see operators in the industry going back to existing pads. As an example, they’ve drilled the Bakken in North Dakota and are now going back and drilling the Three Forks – sometimes from the same pad. Being able to come in and walk over existing wellheads and around existing structures is a flexibility that we definitely consider when we’re designing our rigs. I think that is a key component that our customers will continue to look for in the future,” he emphasized.

The rigs have a full range of “x-y” movement capabilities with virtually no restrictions in terms of the well design on the pad. “We can move our rigs on to any design,” he said, “whether it is a straight line, two or three rows, or quads, which we see as a huge advantage over skidding a rig on a rail system,” Pye said.

Full automation still ahead

People have different ideas about automation, Garvin continued. He breaks automation into two categories: above the rig floor and below the rig floor. “For our customers we believe the most recent progress has occurred with automation that takes place below the rig floor,” he said.

“The constant journey for us and our customers to realize greater efficiencies, however, supports our belief that automation above the rig floor will continue to evolve and that great opportunities exist.”

To that end, Patterson-UTI is currently participating with some customers in automation processes and is very much engaged and willing to participate in these endeavors.

Garvin noted that collaboration between contractors and customers is extremely important to achieving advances in automation, and the company values the commitment of customers to drive automation efforts.

With any technology being developed for drilling rigs, safety is the number one consideration. The company places importance on developing technology to protect its employees. “The safety of our people and the safety of the environments in which we work is extremely important to us. If we can add value to our customers such as these gas-burning engines while assisting and partnering with them to drill the wells cheaper, that is also extremely important to us,” Pye said.

“Number one is safety. What we’ve learned is that as our rigs operate safely, they also operate efficiently. Those two things tend to run hand in hand,” Garvin continued.

Value proposition

The business is all about drilling the wells in an efficient and inexpensive manner. “That is the value proposition for our customer. Consistent high performance is driven by technology, which must not only be developed by innovative people but utilized by skilled operators,” Garvin emphasized.

Drilling shifts from efficiency to effectiveness

Operators are very much focused on the efficient well concept – getting wells down as quickly as possible and reducing the cost per meter. The biggest driver for the producers is improving the economics in the field. What’s getting some market uptake now is an understanding that the industry is squeezing efficiencies and is looking for help with the effectiveness.

“A significant percentage of the unconventional wells being drilled today are subeconomic,” said Jon Hill, vice president of marketing and technique for PathFinder, a Schlumberger company. “The challenge for the industry is to make every well count. That’s why reducing performance variability actually boosts both efficiency and effectiveness.

“If you look at the performance in places like the Eagle Ford year-on-year over the last several years, you will see that while the industry has been pushing the envelope in terms of drilling efficiency and cost, there is still a large variance in production from well to well. We’re starting to see interest from the producers to improve the effectiveness of these wells,” he continued.

Onshore factory drilling

PathFinder is involved in oil and gas reservoirs that require high-intensity horizontal drilling campaigns on land throughout the world. What differentiates the company is its focus on resource economics for unconventional drilling, which are marginal when compared with deep water and some of its prolific fields.

“The Factory Drilling approach for field development is about standardization to reduce variability, not just in terms of drilling efficiency but also with respect to production performance. This is a different approach, and it is aligned with the customers’ objectives. Factory Drilling is at the center of everything we do at PathFinder and is mainly driven by the needs of our customers in North America,” Hill said.

“Unconventional resource economics are fundamentally different in comparison to conventional resources. We’re aligning ourselves with our customers’ objectives. North America has led the unconventional story, and it has fueled the growth in the directional drilling market for about the last five years. It’s now emerging in other parts of the world,” he explained.

Factory Drilling applies to reservoirs where the players face more challenging resource economics. The technologies are focused on two elements. The first is efficient drilling technology, which is drilling as fast as possible with simplified logistics and a simplified and reduced wellsite footprint. The second is the effective well concept, which reduces performance variability in production by bringing fit-for-purpose measurements that are designed specifically for these reservoir types.

“In the unconventional market in the US and Canada, production performance still varies from well to well, and this variance is not always well understood. We want to help our customers get the maximized production and the same yield out of every dollar spent on a well-by-well basis,” Hill said.

The heterogeneous nature of the reservoirs impacts the production variability. “I think we are starting to make a difference in the market by reducing uncertainty for our customers. And this is not so much about reducing the uncertainty but rather about getting this cost per barrel produced down by reducing the number of subeconomic wells for our customers,” he added.

Tools designed for factory approach

In terms of technology that lends itself to a Factory Drilling or automated approach, RSSs such as the Schlumberger PowerDrive RSS and PowerDrive Archer high build-rate RSS offer some of the latest telemetry systems that are being introduced into the market.

“You’ve got a really exciting couple of years coming up as development is aimed at this market segment driven by customer demand,” he emphasized. “And the customers are creating this segment. Some customers operate in both the deepwater and unconventional environments. They have the challenge of having two completely different business models to manage.

“From a drilling point of view, we recognize that every unconventional is different from an efficiency point of view. Yet a single focus on the drilling in unconventionals allows a narrow technology portfolio when compared with something like deep water.

“This enables us to specialize our technology, competence, and processes on delivering repeatable high-performance efficient wells. We define the difference between efficient and effective wells as quantified by cost per foot drilled and also cost per barrel produced, and we also believe that our integrity and quality of service is a big part of that,” Hill explained.

HSE point of view

Integrity on the quality side of the workflows for unconventionals is different from a risk point of view. Drilling a well in deep water is a very high-risk environment. It requires a detailed management system to handle that risk – absolutely every element of it.

There is still a lot of risk in the unconventional plays, but it is a different risk level approached in a slightly different way. A different set of work is required from an HSE point of view.

“One thing I’ve noticed in my career is that quite often it is these high-intensity drilling campaigns – even when technically less challenging – that have the worst HSE performance at the field level,” Hill said. “For high-intensity drilling campaigns, it makes no sense to keep multiplying the number of people the industry deploys to the wellsite. The more processes we automate, the more tasks we can complete remotely, resulting in less traffic.

“One of the things we’ve taken a conscious decision to change is the amount of interfield traffic of both equipment and personnel. With every less mile driven and every less person on the wellsite, we reduce the HSE exposure for both Schlumberger and our customers,” he continued.

Downhole data acquisition, telemetry

Part of the effectiveness is understanding the reservoir quality to place the well in the right place in an automated fashion. “The completion quality, if we can get it in real time, gives us a head start. At the end of the day, we need that data at the surface before we run the completion,” Hill said.

The industry standard for moving data to the surface is likely going to move away from mud-pulse telemetry. How much effect will that have on the entire industry?
“Electromagnetic telemetry is something that we’re interested in. If you look at the trends in the market, Canada is a good example of early adopters of electromagnetic telemetry,” he said.

Wired drillpipe is another interesting technology. The industry needs to figure out the economics. If the economics justify the investment, the technology will be used in certain environments. “It is a new technology and has many applications such as deep water where you need many measurements downhole,” he continued.

Adaptive condition monitoring improves health of drilling system

When people look at the drilling system, they normally see discrete pieces of technology within the system. “However, when researching what operators are trying to achieve and how they view technology, it was found that they want to feel as if the drilling system has their back,” said Karl Appleton, business and technology director, National Oilwell Varco (NOV).

In an analogy based on pilots, he described seeing the drilling system as a wingman for the operator (pilot). “If we were going to invent a drilling system as the wingman for the operator, what would it do for them? Would it keep them going so they don’t miss anything? Would it keep them away from potential problems?” he asked.

Fred Florence, director of advanced drilling technologies in NOV’s corporate engineering group, added that his company is at different levels of introducing these elements into its equipment. As new equipment models are introduced, NOV is adding these features to some of its products. Modifications are similar to those made to later-generation top drives, for example, where internal sensors and diagnostics were installed that were not in the earlier versions measuring hydraulics, electrical performance, and more.

Adaptive condition monitoring

What would it be worth to have a drilling system that could give a company the state of health of its components? “Downhole monitoring can look at how hot equipment is and how much vibration there is and give you results,” Appleton explained. “However, we’ve also come up with adaptive condition monitoring, which allows you to set the drilling system so it learns today’s state of health. It then examines over time if there is any degradation in the system as a whole and starts to predict when the system will be under stress or if the system is going to be sick.

“From that point, it makes it a business decision. If you as the driller want to do something and you know that your system is healthy, then you can go ahead and start. If you know that your system is not going to be in the best of health, you might take a step back before you get into any kind of critical section of your drilling process,” he continued.

Simplifying offshore BOP systems

One of the main areas of concern offshore is with the BOPs. NOV developed its eHawk BOP platform. The company has already built a first variant of eHawk with adaptive condition monitoring.

“BOPs are complex systems. If you’re a subsea engineer, you are looking at six or seven different screens that show all the details about how the BOP is working and the health state of every component. How can we make that simpler? How can we bring everything to just one screen? And how can we look at it in terms of criticality?” Appleton said.

There are some things that could happen on a BOP that don’t really impair anything. But there also is the impact of having two or three things happen at once that could put an operator in a critical state. Flagging absolutely everything can be overwhelming. However, flagging something that could be critical makes it easier to use the system more effectively, he explained.

“That is all being pulled together with eHawk. The system is looking at the state of diagnostics today and what people think the state of diagnostics will be in the future. The eHawk is being developed along those lines. The idea is to try to deliver reliability much more than we’ve ever been able to do,” Florence said. “The industry also is looking at monitoring the health of the well and what conditions are critical.”

He pointed out that this is a tool to notify the drill crew. “It is not automated well control yet. As an industry, we’re not ready to rely on all the sensors and algorithms to do autonomous well control. We do automated pressure control for managed-pressure drilling, but there is always a person supervising as well. However, kick detection to automatically close the BOPs is not being done to my knowledge.”

The company introduced a kick monitoring display that looks for alterations in flow and volume and differences between past pump shutdowns and current pump shutdowns. If there is something critical, it pops up on the screen. If it doesn’t see anything critical, it keeps the information out of the way so it’s not an added distraction, Appleton added.

Downhole problem avoidance

“In keeping along the lines of the wingman conducting equipment monitoring to try to prevent problems, there are some efforts under way that are looking at problem avoidance downhole. How can we model the drilling process, measure what we can at the surface and downhole, transmit through either mud pulse or wired pipe, and be able to improve the downhole drilling process?” Florence asked.

The industry now provides automation products to drill faster, which is a metric easily understood by customers – a faster ROP. However, explaining the value of drilling smarter or drilling a better well is very difficult to measure, he emphasized.

“You can measure a poorly drilled well because you can’t put the completion string in it, but you can’t measure a well and say it’s good or excellent,” he said. “Until we learn how to measure that, it is going to be hard to measure these performance improvements. Otherwise, it will someday be that enough of these improvements stack up to where the operator can’t live without them.”

Florence noted that he is involved with a Society of Petroleum Engineers technical section, which is currently doing “drill a stand.” NOV has also done this process.
“The idea is to have the driller get the pipe in position in the well at a certain place and push the automatic button,” he said. “It lowers the pipe, touches to the bottom of the hole, and begins drilling in a way that they want. It drills that stand, picks up off bottom, sits there circulating, and tells the driller, ‘Now go make the next connection.’”

Long-term, drill a stand will be fully automated, but that will be a long time from now, he continued. The first steps will be to take a fairly well-known process with variability in it and find a way to coordinate all of those machines that are used in drilling a stand and have them do that in some semi-automated fashion, he continued.

Advances in tools, technology

There are a number of developments to address tortuosity in the well bore. In drilling, for example, drillers try to drill straight. If they still have some drag problems, the NOV Agitator vibrates and helps free the stuck object. The Agitator looks like a mud motor, but it creates a vibration in the drillstring that changes static friction to dynamic friction, which is lower and allows the bit to advance further, Florence explained.

“For stick-slip the company has a system called SoftSpeed. It can be switched on and off, and the next stage is to have it wait passively. Then when it detects an approaching stick-slip, it will alert the driller to switch it on,” Appleton added.

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