Technologies old, new and hybrid being developed to reduce risk, help operators navigate complex formations
By Joanne Liou, associate editor
How have service companies been affected by the boom in unconventional drilling and the rapid pace of operations?
It means we must have a very reliable supply chain and a very efficient operations organization, with fast-turnaround of tools, maintenance and the fast supply of new tools to the market. High-intensity work also demands a lot of people, and we need to have an efficient process of hiring and training. It’s also critical to have highly reliable tools due to the volume of work so we can efficiently manage our fleet of tools and provide the best value for the customer.
We’ve had a big success in unconventionals on the drilling side over the past two years with the AutoTrak Curve rotary steerable system, which was developed for the unconventional market. We saw an opportunity to drill the build section and long laterals in one run. Traditional rotary steerable systems were seen as too expensive or not cost effective. We developed a fit-for-purpose system in AutoTrak Curve to target that application.
How can industry ensure equipment reliability in this higher-volume work environment?
We’ve done two main things. One is that we’ve focused on the initial design of the tools and the development process for a new tool. We’re making sure that the tool will be reliable, minimizing the number of components and looking for potential weak spots before it gets to the field. That’s the first avenue to ensure reliability.
The second area is the testing of the tools before they get to the field. In the last two years, we’ve introduced completely new tests in relation to heat, temperature and vibration, as well as specific tests for rolling and bending of the tools to test reliability in a more robust way. Both aspects have been important for us in driving forward the reliability of our equipment.
Two operational imperatives are to reduce NPT and cost. How is Baker Hughes addressing those issues?
When you look at NPT, it’s important to develop new differentiable technology that will attack those flat times in the well. We’ve developed systems, such as the SureTrak steerable drilling liner service. It is focused on drilling the well with a rotary steerable system and a liner at the same time to reduce risk in unstable wells. At the end of the day, it’s about reducing the amount of time it takes to drill a well.
In terms of fluid testing in the drilling BHA, our FASTrak LWD fluid analysis sampling and testing service reduces the need for extra trips or running wireline tools in the hole. With a drilling BHA, you can take a measurement of the formation pressure and get a fluid sample from the formation. It’s developments like these that specifically reduce the need for nonproductive efforts at the rig.
Newer technologies, such as the SureTrak you just mentioned, incorporate existing technology. Are the technologies that exist today meeting operational challenges, and is it a matter of optimizing what is already available?
We have a tremendous portfolio of products, and we’re really striving to bring many of those aspects together in new ways to do new things. SureTrak brings together technology that existed, such as AutoTrak. SureTrak is a hybrid system that comes from our drilling group and from our completions group. We’ve had our rotary steerable system for many years, and that does a great job in a directional drilling sense. Giving that technology the capability to directionally steer the well, with a liner, in one run is a fantastic new development.
It’s a matter of coming up with the concept of bringing two existing technologies together to provide something completely new. The FASTrak tool is focused on what has traditionally been a wireline tool application, and still is, but it’s combining that technology into a drilling BHA to measure the properties of the formation fluids. That’s something that we’re really trying to focus on at Baker Hughes across our product lines – to bring things together in new ways to focus on a completely new application.
What are the latest developments in real-time reservoir navigation and visualization?
On the reservoir navigation side, the real developments have been tools that look much deeper into the formation than traditional sensors so that you can spot formation bed boundaries much earlier in the drilling process, react to them and steer away appropriately. We’re looking at tools that can see 20 to 30 meters into the formation, which is a big improvement from what is available today. When you can see that far, it is easier to steer and stay in the reservoir.
The other development on the visualization side is the directional drilling software that we have in our real-time reservoir models. From a software standpoint, we’re really tying the drilling piece into the reservoir model and visualizing that for the customer.
With LWD/MWD/SWD, what are the remaining obstacles or areas of improvement to truly see ahead of the bit and deliver the wellbore in the sweet spot?
It’s really not a question of evolving technology; it’s the development of completely new technology to look ahead of the bit. We have several projects working in this area to really be able to look ahead of the bit, which obviously is important for our customers. It’s been an area that service industry has yet to completely solve, and we’re diligently working on it.
There seems to be hesitation within industry to be the first to try a new product or service. How are you working with your customers to deploy or to try out these new technologies?
We’ve strived to partner with customers in the development of new technology, especially given that technology is becoming more and more complex and many of the applications are becoming more complex. It’s great to have a customer onboard to give their insight into the application needs and to collaborate with them on development.
We’re pulling together dedicated, integrated and multidisciplinary product development teams. They bring in people from the field operations, field engineering and customers who are required, along with our technologists, to focus on developing a specific technology. It benefits both Baker Hughes and our customers in having that greater understanding of the application because we can develop new equipment, new processes and new services faster.
When we deploy the new technology, the customer is invested in trying that technology and making sure that it works.
In 2010, DC reported on Baker Hughes’ BEACON platform and how the future of these facilities was geared toward drilling automation. How have drilling services been affected by automation?
We’ve been growing the BEACON centers globally. It helps to have another set of eyes on operations in remote locations. It helps us to be more efficient and to deliver new services to customers based on a remote platform. For example, with automation, we’ve developed the WellLink Radar remote drilling advisory services that takes information from the drilling operation at the rig site and processes that through a case-based reasoning software system. The system matches data against previous wells in an automated way and flags any potential problems on a radar screen.
The system starts to flag issues hours before they actually occur, and all of this happens without human intervention. People are then able to monitor multiple wells, if required, and they can use this information that is displayed in a user-friendly format to see issues before they become true problems.
We use BEACON as a platform to deliver new services to our customers. BEACON continues to grow as a platform for real-time collaboration and decision support. Because collaboration is key, we are committed to application interoperability by complying with industry standards, such as OPC and WITSML.
There are sometimes telecommunications bandwidth limitations in terms of the communication between a rig and the office environment. This can limit the ability to really drive drilling automation in real time. While it is possible to remotely control actual rig parameters and the drilling processes in real time, it will require improvements in communications to make it feasible from an HSE perspective.
What progress do you expect to be made toward drilling automation in the next couple of years?
It’s one of the industry’s hot topics right now. We’ll see more and more companies developing smart applications that can drive the drilling process in real time. With automatic closed-loop control of the drilling process, we’ll take information from our downhole sensors and feed those into a system and then feed control inputs back to the rig to drive the overall process.
What challenges must be overcome to achieve closed-loop automation?
The biggest challenge is there are so many different players involved, between the rig contractors and rig manufacturers, to the operators, the service companies and then other equipment providers. That makes it challenging when you’re looking at a system that needs to integrate different equipment components to truly achieve automation.
Details, such as a common communication language on the software side and data handling side, become problematic when you have so many different companies involved.
However, there is progress through the SPE Drilling Systems Automation Technical Section (DSATS) and IADC Advanced Rig Technology Committee. Industry groups are working on guidance for these communication protocols and languages so that different companies can work together using common languages for automation.
Where will the majority of Baker Hughes’ investment be focused on the coming year?
Formation evaluation and advanced drilling systems are very important. We’ll continue to grow our capability with new tools, new visualization and new processes. The improvements feed into automation and real-time systems. Years ago, people looked at an operation – planning before drilling the well and then analyzing afterward – but now people want that same information in real time. We’ll continue to invest in systems and services that can provide this information in real time to our customers.
Given the access to real-time data, is industry able to process and use all the data being collected?
Most of the information comes after the well is drilled, when engineers sit down to analyze and work with it. The industry has a long way to go in terms of using that data in real time. We have data overload, and it’s a matter of taking that data and pulling out the pieces of information that you actually need.
Automation is about having the infrastructure platform to better interpret real-time information and use it in real-time. Even if you’re not completely closing the loop in terms of true automation, you’re able to provide that real-time information in a very user-friendly format. While flying a modern airplane, the pilot is shown what information they need to see when they need to see it. We, as an industry, need to do the same so people can see the critical information at the time that they need to see it to be able to react.
In 2012, Baker Hughes became the first oilfield service company to receive full IADC accreditation under its Competence Assurance Program. What is the significance of having a competence assurance program?
For a service company, the benefit is that the operator knows, in a documented way, that we have the appropriately trained and qualified people who will do the job. The program focuses on demonstrated abilities, and it provides operators with the confidence that our employees have the right training, skills, experience and behaviors to execute flawlessly at the well site. That is very important, not only from an execution standpoint, but it also gives us a competitive edge because operators want to know that they have competent people at their rig site, especially in high-risk drilling environments.
Baker Hughes also benefits in that we have less maintenance to do on our tools because they’re run properly. More efficient drilling also reduces requirements for backup equipment.
What were the challenges to moving from a traditional training approach to a competency approach within your organization?
A traditional training approach focuses on knowledge. While it’s a good start, it does not validate the employee is competent. The biggest challenge was to build a unique competency framework best suited for our company. You have to look at the documentation requirements so that it doesn’t become a paper exercise. This way you can truly understand the individuals’ competencies as they evolve in their careers.
The competence assurance program seems twofold with people and equipment. How does it differ from past programs?
The competency program takes it to a new level. Employees are individually assessed regularly on the job, where learning, skills, experience and behavior all come together. Competency is not a one-time event; it’s developed, maintained, validated and monitored over time.
It is like the improvements in quality programs for our tools and services; they’ve evolved over time. Along with the equipment quality programs, you also have to have the development of quality of people because they are what the customer sees at the rig site and what drives the job.
You can’t have great tools and services without great people. The program focuses on confirming that a person is capable of doing the work that they will be expected to do at the rig site.
A drilling contractor recently pointed out that the onshore industry is essentially operating with the same number of people onsite as 20 years ago. Does that apply to the service side, and is this something that needs to be addressed?
I don’t think that’s true necessarily in the service business. We have a lot more people than we used to have, but we also expect more out of them because the tools, equipment and the measurements that we’re taking downhole have evolved.
The unconventional drilling and formation evaluation markets require higher-end technology, which requires more training and higher competency. Wellbores are much longer than they were 10 to 20 years ago. Drilling long horizontal sections requires a different level of skills and expertise from our people than before.
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