May 2024
SPECIAL FOCUS- Well completion technology

The five A’s on the road to completions automation

As fracturing intensity continues, operators are looking for additional ways to increase efficiencies. One such solution is automation in the fracturing process. Accordingly, a platform of digital software controls and hardware enables operators to pursue automation, while executing completions safely and more efficiently.
Rip Stringer / Intelligent Wellhead Systems

Over 12,000 unconventional wells were completed in the U.S. in 2023, nearly returning to activity levels not seen since 2019. The average lateral length and number of stages completed in these horizontal wells continue to increase, while the time to complete them has been reduced by as much as 40%. Current completion techniques often involve multiple pads, wells and wireline operations working simultaneously, allowing fracturing processes to operate continuously, resulting in the completion of more stages and wells with less non-fracturing time. 

Coordination of these complex, simultaneous work streams relies on the automation of completions processes, to improve safety, efficiency and quality, while advancing performance and reducing costs. Those who fail to automate may miss opportunities for increased efficiencies, compared to those who embrace automation—with wells that not only produce more, but also produce faster, safer and more cheaply. 

Intelligent Wellhead Systems’ inVision® digital controls platform combines hardware and software to provide five key elements necessary to facilitate automation of unconventional well completions. These can be summarized in the five 5 A’s of automation: 

  • ALERT: Notify users of a condition with visual and/or audio cues. 
  • ADVISE: Suggest a next step, remedy, or course of action. 
  • ASSIST: Mechanically aid in the execution of user-preferred operating procedures. 
  • AUTOMATE: Execute a sequence of activities in unity. 
  • ANTICIPATE: Identify risks and variations in activities and process alternatives. 


The IWS inVision system provides an integrated platform to keep users situationally aware of current conditions and the status of their completion operations. A digital twin of the pressure control equipment is created, utilizing hydraulic valve position and accumulator handle position sensors. All critical activities—such as starting a wireline run, frac stage or pressure equipment maintenance—are kicked off with a Digital Handshake.® 

Fig. 1. SIMPOS Interface Digital Twin notifies the operator of a condition with visual or audio cues.

All critical stakeholders—including the well site manager and frac, wireline and pressure control supervisors—enter their personal pin codes, confirming their agreement to start and stop the activities outlined in the standard operating procedure, Fig 1. This is done through a user interface on a tablet residing in the treatment control vehicle, wireline unit or from an off-site location as required. 


Fig. 2. SOPs are digitized to user preferences to advise on next steps.

The various operating procedures, specified to user preferences, are digitized in the process logic—including interlocks—assuring each step in the procedure is safely executed in the most efficient manner. The control software not only advises what the next step should be, but, if it is not safe to execute the next step in the process, it also advises why and recommends a course of action to remedy the situation, Fig. 2. An example might be: “Pressure too high to place wireline, bleed off pump-down pressure.” The system would prevent the crown valve from being opened until this action takes place. 


The software is mechanically enabled to assist in the precise execution of the users’ preferred operating procedures. Valve position, accumulator handle position and pressure and wireline detection sensors provide the data, which create software interlocks. Accumulator handle position lockouts mechanically prevent opening or closing the wrong valve, either manually or with a remotely actuated digital valve controller. 


Utilizing the Digital Valve Control (DVC) software with remote valve actuation hardware facilitates operators’ completion automation initiatives. With fracturing services on the critical path to improving overall completions efficiency, operators can focus on the preparation of each well’s next stage, ensuring the fracturing process runs seamlessly with fewer interruptions. 

Operators are moving to implement continuous pumping procedures, moving from frac stage to frac stage in zipper fashion without shutting down. IWS automates the continuous pumping swap from well to well by sequencing the opening of valves required to move the fracturing operation to the next well (or wells) ready to be fractured and then the closing sequence of valves on the well (or wells) where the fracturing stage has been completed, Fig. 3. 

Fig. 3. Continuous pumping with simultaneous fracturing.

The definition of the key performance indicator for swap time has changed for many operators. The time from when fracturing pumps shut down to when they restart is no longer relevant, nor is measuring total pumping time. Operators have now started measuring pumping time above a threshold treatment pressure and rate as the “effective fracturing time.” Operators are now interested in measuring the total time spent at fracturing rate and pressure in a 24-hr period, Fig. 4. 

Fig. 4. Total effective fracturing time per well, per day.

Data captured by the inVision Live Control System (Fig. 5) illustrates how operators are using this platform to automate their completions processes, to move the fracturing treatment safely and most efficiently from well to well.  As the frac stage on the 7H well comes to an end, the frac pressure is monitored until it falls to a level below a set threshold and where the differential pressure between the 7H and the well to be fractured next—the 9H—is within the range established in the operator’s standard procedure.  

Fig. 5. Continuous pumping, non-fracturing time.

With the conditions of the pressure interlock met, valves are sequenced to first open the mono-line isolation valves, then open the zipper manifold to the 9H and then close the zipper manifold to the 7H. Fracturing is then initiated on the 9H. Effective fracturing time for this operator is now measured from frac complete, (pressure under 3,000 psi) on the completed 7H, to frac start on the 9H (pressure greater than 3,000 psi). 

While the automation of completions processes in unconventional wells is still in its infancy, the positive results on safety and efficiency are already clear. A recent operator completed a five-well, 263-fracturing stage pad in 12 days, 7 hrs and 17 min. Of the 17,717 min. of treating time available, 15,512 min. were “effective fracturing time” (88%). 

Figure 6 graphically represents the time between frac stages—or the non-fracturing time—on this pad (12%). The 12 events, where pumping was actually stopped and non-fracturing delays were typically an hour or more, are identified by the large peaks. Average non-effective fracturing time, including all swap times, was 8 min. and 16 sec. Outside of the large delays in the 12 events, the non-effective frac time seems to be nearly zero in this graphic and, until recently, largely ignored. 

Fig. 6. Non-effective frac time between stages.

By automating a sequence of valve movements to move fracing to the next stage and close fracing on the previous stage, average non-effective fracturing time was decreased. By implementing automation and removing these events, the customer can now observe non-effective fracturing time, even while continuously pumping on 236 of the 263 stage swaps (90%). 

There is still much work to be done to achieve a robust, continuous pumping process. By automating a sequence of valve movements in one step, to move frac to the next stage and close frac on the previous one, stage transitions become more consistent and average non-fracturing time is decreased. 

Figure 7 removes the 12 events where non-fracturing time was delayed—typically, for more than one hour—and pumping was stopped. Average non-fracturing time while continuously pumping on this pad resulted in an average of 1 min., 19 sec per swap. The longest transition was 4 min. and 22 sec, and several stages were over 3 min. As illustrated in Fig. 7, there are events during continuous pumping operations to improve and further increase the effective fracturing time. 

Fig. 7. Continuous pumping, frac closure to frac initiated.

Figure 8 is a comparison of a completions team, utilizing a standard continuous pumping digitally controlled valve (DVC) sequence, versus an enhanced system (EDVC) that automates the sequence of valve movements in a unified step. The comparison is on nearly identical four-well pads, in the same basin for the same customer. While demonstrating an overall average transition time improvement of 14%, the enhanced process also shows a much more consistent swap time. 

Fig. 8. Continuous pumping with enhanced digital valve control automating valve sequences.

Equipment uptime and field service support are critical for completion operations, as well as utilizing a real-time dashboard and data service, to observe and action all the completion data being gathered. 


The platform’s bi-directional data service capabilities allow operators to execute their own proprietary software and algorithms, either on the edge, on site, or in cloud-to-cloud, using the completion data to anticipate and identify risks. Examples include exceeding monitored data thresholds, pointing toward a likely screen-out or nearby well fracturing hit, and taking action to prevent these events by alerting onsite personnel to shut down fracing and move to the next stage, as shown in Fig. 9. 

Fig. 9. iHub control center.

The road to automation can be complicated and difficult. Intelligent Wellhead Systems has identified five key elements necessary to facilitate automation of unconventional well completions. Employing these five elements ensures the road to automation is complete and inclusive, and it enables insights and KPIs not previously used to create further efficiencies throughout the process. 

About the Authors
Rip Stringer
Intelligent Wellhead Systems
Rip Stringer is vice president of corporate affairs for Intelligent Wellhead Systems. He has extensive international and domestic experience and served in executive roles for many years at SLB. Mr. Stringer graduated from the Missouri University of Science and Technology with a degree in petroleum engineering and an Award of Professional Distinction.
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