No more tradeoffs: RSS innovations allow drilling speed, precision to coexist

By Stephen Whitfield, Senior Editor

Rotary steerable systems (RSS) have become indispensable in some basins, as operators continue to push the boundaries of directional drilling with longer laterals and more complex well designs. However, with the higher costs required compared with conventional downhole tools, this means the performance of RSS is always put under a microscope.

“The customer base is drilling more complex wells, and they’re trying to drill the wells faster,” said Derek Nelms, Global Product Line Manager – Drill Bits at Baker Hughes. “It’s a continuous improvement cycle. When you pick up a rotary steerable system, you’re basically choosing at the very beginning of the process to invest more in the hardware required to drill the well, because your other option is something like a conventional bent motor assembly. In order for them to get their return on investment on that rotary steerable system, it has to meet specific performance KPIs. We have to keep focusing on developing these systems that allow us to drill the well faster.”

Modern horizontal wells demand two things that were once considered tradeoffs: speed and precision. Drilling faster but not staying in zone sacrifices reservoir contact, while drilling accurately without speed or efficiency inflates well cost. In today’s environment, however, operators may not have to choose one over the other. By integrating RSS with high-performance measurement while drilling (MWD) technology, some say, both goals can be achieved simultaneously.

RSS tools use internal steering mechanisms to change the trajectory of the well without stopping rotation. This provides a significant advantage in long laterals and high dogleg environments where sliding becomes inefficient and unstable. Adding MWD technology on top of that then provides real-time downhole measurements so the RSS and wellbore can be accurately steered. For MWD providers like ProDirectional, this means it’s critical to optimize their systems so that minimal setup is needed to receive data with any RSS.

“As an MWD company, our main objective is to be able to communicate with any rotary steerable system that’s available in the market,” said Seth Lastrapes, Senior VP of Technology at ProDirectional. “That’s where we’ve made our focus the last couple of years, integrating with all of these different technologies and being able to offer it as a service, but still be able to provide the information from the MWD system and the rotary steerable.”

Beyond hardware improvements, some companies are also looking toward artificial intelligence (AI) as a tool that can help bolster steering performance. Real-time operating centers (RTOCs), for example, are utilizing AI algorithms to provide insights into RSS tool health and allow directional drillers to make more informed decisions that help the BHA stay on target.

“AI is pretty much in our lives right now,” said Anton Makarov, RTOC Supervisor at Altitude Energy Partners, a provider of directional drilling services. “Because it can evaluate a tremendous amount of data in a matter of minutes compared to what a human could do, it’s such a valuable tool. We are assessing RSS performance by analyzing the goals achieved with specific tools and benchmarking those results against historical performance reports to provide the best tool that suits the client’s challenges. This entire evaluation process can now be accelerated.”

Finding the right bit to run with the RSS

Pairing RSS systems with the right PDC drill bit can make a big difference when trying to drill faster, more complex wells and longer laterals. Baker Hughes has been looking at developing bits that meet specific performance requirements in order to help operators justify the added cost over bent motor assemblies. The bit must also drill with low vibrations to protect the RSS from premature failure and high maintenance costs.

These considerations are what motivated the company to develop its new TRU-Steer RSS and PermaFORCE-TRU PDC bit combination, launched at its Annual Meeting in Florence, Italy, on 30 January.

Unlike its other RSS tools, the TRU-Steer was designed to neutralize drilling dysfunction at the source, protecting the entire BHA from damage. Primarily, the system itself is ruggedized to maintain performance even in harsh environments. Its multi-chip modules are housed in a ceramic enclosure rated to up to 175°C, compared with the 150°C rating of earlier systems. Additional magnetometers and accelerometers have also been incorporated to increase the resolution of azimuth and inclination measurements.

Further, the sensor package is calibrated to autonomously autocorrect and self-position to stay within a predefined target. Hassan Fawaz, Rotary Steerable Portfolio Manager at Baker Hughes, said this calibration is critical in enabling the consistent measurements needed for accurate wellbore trajectory control, even in situations where the BHA encounters higher vibration amplitude.

“When we talk about sensor measurements, older systems with a non-calibrated setup can expose you to errors like bias offset, misalignment, magnetic distortions, or maybe temperature drift where the azimuth readings start shifting as the temperature increases in the well,” Mr Fawaz said. “But when you add magnetometers and accelerometers that are calibrated like we’ve done with this system, you can ensure much higher precision and accuracy of the inclination and azimuth, which you need to have with an RSS.”

The development of the PermaFORCE-TRU bit focused heavily on reducing downhole dysfunctions, particularly high-frequency torsional oscillation (HFTO), Mr Nelms noted. The company used bit drilling simulations to predict lateral and HFTO stability windows and designed the cutting structures to improve side-cutting efficiency, which he said is valuable in minimizing damage to an RSS BHA. In addition, matrix shankless technology reduces the distance between steering ribs and bit to increase the responsiveness of the RSS BHA.

“When it comes to designing a bit for RSS, it’s all about allowing the RSS to do its job,” Mr Nelms said. “One of the value propositions of any rotary steerable is that you can place that wellbore in a tighter window and geosteer more effectively. That’s why we really focused on side-cutting efficiency. We wanted to create a drill bit that could cut to the side with a lot less force requirement because all of our RSSs use the pads to engage the formation and push the bit to the side. You don’t want your bit fighting the RSS when you’re trying to push it in the direction it needs to go.”

While the bit was designed to run with TRU-Steer, it has also shown positive results when paired with other rotary steerable systems in trial runs.

For instance, running with Baker Hughes’ Lucida RSS in one Marcellus well in 2025, the bit helped maintain a higher ROP (410.8 ft/hr) in the build section compared with the four other wells on the same pad, which ran the Lucida system with another Baker Hughes bit. The four other wells averaged 349.48 ft/hr in their build sections. The higher ROP achieved with the new bit enabled a savings of 7.5 hours, according to the company.

The TRU-Steer RSS has undergone field trials in several regions, including North America, the Middle East, Asia and Australia, racking up more than 500,000 ft drilled as of January 2026 through prototype and pilot tool testing. One trial run last year involved a pad in a North America land basin where the operator had experienced high HFTO when drilling with a conventional RSS and third-party dampener. Deploying the new RSS in another well on the same pad led to an average 15% increase in weight on bit, as HFTO was almost completely eliminated, according to Baker Hughes.

Curve and lateral performance also improved when using the new RSS. In the curve, average ROP increased by 19.65 ft/hr while distance drilled increased by 183 ft. In the lateral, footage per day increased by 1,165 ft and average ROP increased by 74.94 ft/hr. Overall, this translated to two fewer days spent on the well.

“We’ve had repeat requests from customers to have this equipment run in other wells,” Mr Fawaz said, “and we’re seeing that consistency with run lengths, operational impact and directional performance.”

Integrating MWD with RSS

ProDirectional deploys its own MWD technology with both third-party RSS tools and owned assets as a single drilling system – an integration that Mr Lastrapes says is vital in helping operators mitigate downhole risk. When RSS and MWD systems operate together, drilling teams can gain full control of the wellbore, as the real-time measurement enabled by this integration allows for immediate steering adjustments. This can reduce sidetracks, unplanned trips and lost-in-hole incidents.

“Integration gives us a clearer understanding of what the rotary steerable is doing,” he explained. “You have a clear line of communication, as opposed to just sending commands and downlinks to these rotary steerable units. You get the feedback that the communication was accepted, you’re drilling in the right direction and the commands are effective. You’re not just looking at the next survey station to see whether the tool performed as expected.”

ProDirectional currently offers direct connectivity of its MWD with four RSS tools: SLB’s PowerDrive Orbit and NeoSteer, Halliburton’s iCruise, as well as the D-Tech Omni-Steer RSS. Enabling direct connectivity involved installing azimuthal gamma sensors into the MWD system, as well as a transmitter that connects those sensors to the RSS. Each transmitter is specific to the RSS and comes from the provider, but integrating these third-party transmitters required ProDirectional to engineer its own solutions.

For instance, to connect with the two SLB systems, wiring and connection crossovers for that company’s BabelFish real-time short hop receiver had to be custom engineered. This allowed the receiver to translate the RSS-generated data directly into ProDirectional’s MWD telemetry sequences. The data spans things like system status, downlink confirmations, steering information and RSS survey information. After that, the data is transmitted to the surface systems and decoded through the MWD system’s telemetry signal-to-surface technology.

“Every rotary steerable has a different type of transmitter that’s associated with it, and that requires a separate receiver that we build into our MWD tool,” Mr Lastrapes said. “You have to verify that the communication works, that the protocols aren’t too complicated, that the directional sensors in our system actually understand the protocol coming from the RSS, and that we’re able to telemeter and display that in real time.”

ProDirectional has used this MWD-RSS technology combination on a number of wells in North America over the past few years. In the Permian Basin, the company has recorded a 3-mile lateral drilled in 156 hours using a rotary steerable system, assisted by a ProDirectional mud motor, then guided by high-resolution MWD data. In other wells, ProDirectional says it has navigated significant true vertical depth changes mid-lateral while maintaining formation position, completing both the curve and the lateral in a single run.

“What’s allowing us to see these results is the decoding methods that we use, both downhole and at surface, and the ways that we receive, evaluate and send information,” Mr Lastrapes said. “But it’s tricky. With how long these wells are, how tight the configurations can be and the restrictions we’re adding to the BHA, it can be difficult to send a signal from 30,000 ft out back to surface. Having a system that can read and decode that data is imperative.”

Optimizing RSS performance with RTOCs

RTOCs are not a new concept, but in recent years service companies have begun rethinking the way they’re used in operations. The focus has shifted from using them merely as monitoring hubs that provide data visibility to serving as active extensions of the rig. With AI entering the picture, RTOCs are helping companies automate processes that were previously manual more than ever before.

“While this approach does not replace human expertise, it significantly accelerates many routine processes and helps us identify discrepancies in our paperwork more efficiently. It allows us to quickly correlate performance of specific BHAs across formations and depth intervals, providing clearer insight into execution trends. It also improves our ability to evaluate compliance with established SOPs (standard operating procedures) and identify areas for operational improvement,” Mr Makarov said.

Altitude currently maintains two fully functional RTOCS — one in Casper, Wyo., and another in Houston. These centers give the company’s directional, MWD and engineering teams access to the same real-time data so everyone is working from the same information.

While the RTOCs weren’t built specifically to improve RSS performance, the data being reviewed by the company in these centers has helped it to spot potential RSS issues early, Mr Makarov said. Altitude’s directional drilling services are run primarily with SLB’s PowerDrive Orbit G2 RSS, though it has also used other third-party RSS depending on customer needs.

“The value of a real-time center is exactly what the name suggests — it’s real time,” Mr Makarov said. “We’re now able to monitor RSS performance and overall tool behavior as we drill. In the past, we didn’t have that level of visibility during operations, so we wouldn’t know if adjustments were needed until much later. Today, we can immediately see when performance begins to drift from target, analyze the parameters affecting tool response, and work with our clients to make timely corrections that keep the well on track.”

After being field-tested on real wells and active rigs across multiple regions, AI-based algorithms were incorporated into Altitude’s RTOCs, enabling the centers’ data analytics systems to automate critical analyses.

Primarily, the internal AI applications have involved the processing of data sets and automating the detection of SOP compliance during drilling operations. Further, color-coded outputs can flag deviations on the human-machine interface within the RTOC, which can be communicated directly to the rig team.

Altitude is currently evaluating additional AI agents focused on predictive maintenance and drilling parameter optimization. Mr Makarov said he expects these developments to further enhance real-time steering performance evaluations.

“We’re still in the early stages of using AI, but I believe it has the potential to support nearly every aspect of our operations,” he said. “Whether it’s analyzing bit performance in each formation, evaluating how the RSS steered between specific intervals or identifying which parameters influenced tool response, AI allows us to process vast amounts of data quickly. The algorithm can review hundreds of thousands of data points to determine areas where the tool may have been operating outside its optimal performance window.”

In addition to its own RTOCs, Altitude joined a partnership in 2025 involving Corva, CoreGEO and DRAAS Command’s real-time operations center in Houston. The center brings together technical expertise to support drilling operations, guiding key decisions such as well design, real-time trajectory management and BHA selection. By leveraging multiple layers of AI, including Corva’s data analytics platform, the team is able to identify potential downhole risks earlier, shorten planning cycles and enhance the quality and speed of decision making during drilling.

The facility is staffed by specialists and engineers focused on well planning, early event detection, mitigation strategies and continuous monitoring of wellbore positioning. The foundation of this model is having all stakeholders involved in well construction working within the same environment, aligned on the same real-time data and shared objectives, which enables faster, clearer and more coordinated operational decisions.

The partnership is in its trial stage, with Corva and Altitude working closely alongside a major Haynesville operator to define the overall workflow.

“As with any collaboration between multiple organizations, clear alignment on roles and responsibilities is essential,” Mr Makarov said. “When deviations from normal operations occur, the focus is on identifying the root cause and determining the most effective corrective action. Establishing a structured and coordinated approach ensures that operational issues are addressed promptly and with the appropriate technical input from all parties involved.” DC