Modernizing rod-lift automation for deviated wells

PETER WESTERKAMP, Vice President of Automation - Global Sales, Lufkin Industries 

Fig. 1. Field shot.

Rod pumping automation has long relied on wave-equation models, developed for vertical wells. The foundational wave equation approach dates back to the 1960s and was refined through industry projects in the early 1990s to accurately model vertical well behavior. This served the industry well when most wells were straight and vertical. However, drilling practices have evolved dramatically; today, roughly 86% of new wells are drilled with deviated or horizontal trajectories.¹ 

This evolution has created a growing mismatch between legacy rod lift software and modern well designs, Fig 1. The traditional models assume vertical wellbore and neglect critical forces encountered in deviated (inclined or horizontal) wells. In deviated wells, the rod string routinely contacts the tubing, introducing mechanical friction and altering rod loading; conditions the original vertical-well algorithms were never designed to handle. The result is that yesterday’s rod pump automation software, when applied to today’s complex well profiles, becomes inaccurate, inefficient and, in some cases, counterproductive. 

The disparity between legacy algorithms and modern well conditions has real consequences. The wave equation model that was appropriate for vertical wells is simply inefficient and inaccurate in the deviated well scenarios that have been prevalent since the 2000s. The industry has been slow to update these algorithms, and this has led to a situation where drilling technology has outpaced production software. As deviated and horizontal wells have surged in number, it has become clear that continuing to use vertical-well pump models has undermined production optimization. 

CONSEQUENCES OF OUTDATED ROD LIFT ALGORITHMS 

Relying on legacy vertical well models can negatively impact operations in several ways. One of the most common is reduced production efficiency. 

Legacy algorithms often misjudge downhole pump dynamics in deviated wells, leading to sub-optimal pump control. For example, a legacy model can overestimate actual pump stroke length or pump fillage when extra friction shortens the effective stroke. This misinterpretation can cause pump off controllers to make premature or overly conservative decisions, throttling back pumping speed unnecessarily and leaving oil in the hole. 

In practice, operators have learned to manually limit pumping speeds (often below six to eight strokes per minute) in deviated wells, to avoid damaging rod friction effects. While manually imposed limits improve reliability, they also cap the well’s production rate. In short, inaccurate modeling of the true pump stroke and fillage means the well cannot be produced optimally, lowering daily output. 

Perhaps the most serious consequence of applying outmoded algorithms to today’s drilling scenarios is mechanical stress and equipment failure. Vertical well software doesn’t account for the drag and side loads on rods in a curved wellbore. This blind spot leads to rod strings and pumps being operated outside their ideal conditions. Designs based on vertical models in deviated wells are often either oversized (to compensate) or run in a highly stressed state, both of which are problematic. 

The inability to model and control the added friction is, in fact, identified as the leading cause of sucker rod failures in deviated wells today.² These failures manifest as parted rods, tubing wear or pump damage—all of which require deploying a workover rig to pull the equipment. Consequently, wells using outdated algorithms tend to require more frequent interventions, incurring unplanned downtime and higher maintenance costs. Every additional workover not only hits the operational budget, but it also interrupts production, compounding the losses. 

When software cannot accurately predict downhole conditions, oilfield companies either err on the side of caution or unknowingly push equipment too hard—and both scenarios carry financial consequences. Some legacy implementations end up oversizing surface units or rod strings, effectively pouring capital and energy into brute-force solutions for friction that wasn’t modeled. On the other hand, if a system is undersized or runs blind to friction, it struggles to achieve target production, often prompting operators to increase speed or horsepower beyond efficient levels. 

In deviated wells, significant frictional losses mean the surface pumping unit must expend extra power to move rods and fluid, compared to a friction-free scenario. Field experience has shown that ignoring friction leads to underestimating the horsepower and speed needed to lift the fluid. The result is wasted energy and higher fuel costs for the same (and in some cases, less) production. In addition, erratic loads from unmodeled forces can cause inefficient pump-offs and cycling, which wear out equipment faster. All of these factors—energy inefficiency, accelerated wear and more workovers—drive operational costs up, when outdated algorithms are used in modern wells. 

Clinging to legacy rod lift models in an era of horizontal drilling means accepting weaker performance and higher costs. The industry has been grappling with these issues for years, but until recently, solutions were limited. Fortunately, new approaches are emerging to directly address the shortcomings of legacy wave equations in deviated wells. 

ADVANTAGES OF NEW DEVIATED WELL ALGORITHMS 

Modern automation algorithms—purpose-built for deviated and horizontal wells—tackle the above problems by incorporating the real physics of these wellbores. Adopting a validated deviated-well model yields several key benefits. 

By accounting for the true well trajectory and forces, new algorithms dramatically improve the fidelity of downhole pump modeling. Rather than assuming an ideal vertical motion, they factor in inclination angle, rod-on-tubing friction and gravitational effects along the deviated path. This provides operators with true visibility into subsurface conditions in deviated wells. Improved diagnostic accuracy means the surface controller can correctly determine pump fillage (how full the pump is on each stroke) and stroke efficiency in a horizontal section. 

In practice, this translates to maintaining optimal pump speeds without guesswork—the controller can slow down or speed up, based on accurate pump fill data, ensuring each stroke produces fluid and avoiding phenomena like gas pound. With a clearer window into the pump’s actual performance, production can be maximized in real time with confidence, rather than limited by uncertainty.

Fig. 2. NOVAWAVE old vs new pump card.

A model that properly reflects deviated well dynamics allows operators to design and run rod lift systems in a much less demanding, failure-resistant manner. By predicting the additional stress and drag on rods, the software can recommend appropriate hardware (or settings) to handle those loads, preventing unexpected stress reversals and fatigue. Moreover, during operations, the automation can detect abnormal friction or pump conditions early. This capability lets operators identify true failure risks before they happen, reducing surprise breakdowns. 

The net effect is a significant extension of rod string and pump life. Preliminary field data show that using the deviated well-specific algorithm calculated a more accurate pump card (Fig. 2), which will lead to better pump-off control and fewer rod parts, compared to Legacy control. 

Field data indicate that using a deviated well-specific algorithm will lead to fewer rod parts and unnecessary pump-offs when compared to legacy control. With fewer downhole failures, the number of costly workovers drops accordingly. Avoiding even one full workover during the life of a well can save tens of thousands of dollars, not to mention the value captured by reducing lost production. By keeping the rod lift system in its comfort zone, these advanced algorithms boost overall equipment reliability and the time in-between failures. 

Modern rod-lift automation doesn’t just crunch numbers differently—it actively uses its improved insight to control the well in smarter ways. For instance, with a continuously updated model of downhole conditions, the controller can implement adaptive speed control: slowing the pumping unit when the pump fill approaches 100%, to avoid fluid pound, or gently increasing speed when there’s capacity to pump more. Features like variable-speed pump fill control, automatic fluid-pound avoidance and torque management are now achievable in deviated wells. 

These advanced control strategies directly translate to energy savings—the system only expends as much power, as needed, to efficiently lift fluid, rather than running blindly and coming up against fluid or friction limitations. In addition, by maintaining smooth rod motion and preventing shock loads through torque and pound control, energy is used more effectively, with less wasted in vibrations or heat. 

Operators also gain the ability to remotely fine-tune and respond to well changes in real time, as modern systems come with improved telemetry and data analytics. Overall, the total lifting cost drops, because the well is being produced under optimal conditions rather than fighting unmodeled forces. At the same time, these algorithms tend to increase base production by minimizing downtime and inefficiencies.³ The combination of better efficiency and higher uptime yields a double benefit for operators embracing data-driven control. 

Fig. 3. With Lufkin's LWM 2.0 with NOVAWAVE, operators can experience a 40% improvement in downhole diagnostic accuracy, which reduces costs and downtime.

In essence, new deviated-well algorithms bring rod lift into the 21st century—aligning automation with the realities of current well designs. This empowers operators with accurate information and fine control, which leads to more oil, produced at lower cost and with fewer costly complications. A real-world example helps illustrate just how impactful this can be. 

FIELD VALIDATION: A NEW WAVE EQUATION IN ACTION 

The development of validated algorithms for deviated wells represents a significant engineering achievement. Through extensive field testing, with downhole measurement tools across various well profiles—from straight verticals to extreme horizontal departures—engineers have created mathematical models that accurately predict the complex dynamics of modern rod pumping systems. 

The Lufkin Well Manager 2.0 with NOVAWAVE advanced wave equation technology is an example of what’s possible, Fig. 3. Developed over a decade, with collaboration from operators and academic institutions, this system demonstrates how purpose-built algorithms can transform rod lift performance. 

In trials, the advanced wave equation technology demonstrated up to a 40% improvement in modeling accuracy, compared to traditional software. This offers a substantial impact on reliability that can eliminate at least one full workover intervention over the lifespan of an average well. 

Eliminating just one workover rig intervention over the life of a well represents substantial savings, and when multiplied across hundreds of wells, the economic benefits become compelling. Additionally, the ability to run pumping systems at optimal speeds, rather than compensating for inaccurate models, extends equipment life toward the industry target of three years between rod string replacements. 

LOOKING FORWARD 

As the industry continues to push into more challenging formations with increasingly complex well geometries, production optimization technology must reflect current well dynamics. Operators that embrace advanced algorithms designed specifically for deviated wells are positioned to maximize production time while minimizing operational risks. 

The transition from legacy vertical well mathematics to validated deviated well algorithms represents not just a technical upgrade, but rather, a fundamental shift in how the industry approaches artificial lift optimization.  

By providing accurate, real-time insight into actual downhole conditions, these technologies enable a new level of production efficiency that directly impacts profitability. 

For an industry focused on extracting maximum value from every well, the message is clear: the algorithms controlling rod lift systems must evolve to match the sophistication of modern well designs. Technology exists today to bridge this gap, validated through extensive testing and ready to deliver measurable improvements in both production performance and operational economics. 

REFERENCES 

1. LUFKIN Industries. (n.d.). NOVAWAVE. https://www.lufkin.com/solutions-services/automation/novawave/
2. Artificial Lift Research and Development Council. (n.d.). Horizontal Well Downhole Dynamometer Data Acquisition Project (HWDDDA). https://alrdc.com/horizontalwelldownholedynamometerdataacquisitionproject-hwddda/
3. LUFKIN Industries. (2025, April 23). LUFKIN introduces Well Manager™ 2.0 with NOVAWAVE™ [Press release]. Globe Newswire. https://www.globenewswire.com/news-release/2025/04/23/3066416/0/en/LUFKIN-Introduces-Well-Manager-2-0-with-NOVAWAVE.html

Peter Westerkamp Lufkin.

PETER WESTERKAMP is vice president of Automation – Global Sales at Lufkin Industries. With a career spanning global engineering, sales, and product innovation, he has led numerous R&D initiatives and is a frequent speaker and contributor to organizations, such as SPE and ALRDC.