Ground-breaking production solution applied in the Permian

Digital chemical production solutions and innovative equipment optimization result in production uplift and extended wells life in the Permian. 

Dean Gaddy wakes up early each day at his home in Midland, Texas and scans the live well data from our remote monitoring and control system for a Permian Basin operator’s 45 electric submersible pumps (ESPs). He can see which wells are running smoothly and which wells need optimization of the chemical injections that keep the ESPs running efficiently. Sometimes the remote monitoring system signals the need for other troubleshooting. 

“I might reach out to my counterpart in field services and say, ‘Hey, you know, the electrical current (amps) and vibrations are going up on this one, which may be indicative of solids getting in there; maybe we ought to go and take another sample,’” says Gaddy, Senior Services Manager of Field Services and Technical Advising for Baker Hughes in the Permian Basin. 

The flow of Gaddy’s day is smooth, seeking to continue to build on a production solution that has already delivered this operator an extra 29,000 barrels of crude oil (bbl) per month — or an annualized value of $9 million. 

Optimization of artificial lift is at the heart of this solution. Combined with remote monitoring and automation of chemical application, it is also vastly reducing Health, Safety and Environmental (HSE) risks associated with servicing the operator’ far flung wells.

Gaddy has decades of oil and gas experience, starting as a driller in the oil patch in 1977. A geologist and petroleum engineer by training, he has worked in the U.S. Rockies, Russia, Ukraine, China, and of course West Texas. His enthusiasm for his work and his knowledge of the industry are admirable. 

Gaddy is dedicated to achieving his customer’s objectives, which started with two main goals: extending the run lives of all 44 ESPs (and growing) and maximizing production. 

Wells go through several life stages, and artificial lift modes like gas lift or electrical submersible pumps are implemented when natural flow abates. 

“Gas lift might be chosen due to local abundance of cheap gas,” says Gaddy. “But ESPs are remarkable because they offer flexibility. You can near instantaneously control how an ESP runs with control modes such as intake pressure, amps, frequency, complimented by precision chemical injection. In comparison, with gas lift you inject a certain rate, and you get what you get.”

The Baker Hughes team behind Gaddy saw the potential for optimizing chemical types and rates for the customer’s ESPs. The operator in question also has around 1000 gas lift systems in place in the Permian Basin, and many of these wells are reaching the stage where the greater control offered by ESPs can vastly improve production. 

When trust facilitates remarkable innovation

That’s when Baker Hughes’ digital expertise came into play. 

Eric Lonseth, Baker Hughes Operations Specialist for Upstream Chemicals in the Permian Basin recalls: “Dean came to me and said, ‘We’re looking to automate chemical rates based on our ESP data. What would you recommend for the technology?’” 

Lonseth proposed a novel solution to pair our advanced digital algorithms with a well-recognized industry intelligent controller to automatically adjust the speed of an injection pump in response to virtual production flow rates.

“This unit will change its chemical rate to the new indicated rate directly in response to changing flow behavior, which is like having a chemical representative on site all the time,” says Lonseth.

The goal for chemical injection is to avoid under treatment, but at the same time to avoid overspend. At the customer sites in the Permian Basin, chemicals are injected to prevent corrosion and the buildup of scale in the pumps due to the quality of the water brought to the surface with the oil. Ideally, chemical injection perfectly matches the level of production from the well. But production can vary wildly over days. 

“With the old school method where service personnel go to site once a month to adjust chemical injection based on expectations of production over the next 30 days, it’s hard to ensure chemical injection rate variance,” says Lonseth.

The variable speed controller turns what Gaddy calls “normal pumps” into “smart pumps,” now known as the InjectRT™ intelligent chemical treatment optimization service. But he adds that the real smarts are on the engineering side of artificial lift and Baker Hughes’ ability to calculate virtual flow rates. 

On this project, the team implemented Machine Learning that considers all kinds of live information coming from the ESPs via Baker Hughes digital solutions, to record production flow rates in real time. This provides precise instructions to the controller, which then adjusts individual pump speed and chemical injection in rapidly changing reservoir conditions.

Best Practice? Nobody does it better

The benefits of this novel implementation for the operator have been substantial, with outputs for some wells increasing between 50 and 400 barrels a day. Just as importantly, wells utilizing InjectRT have not seen any ESP failures because of corrosion or scaling influences.

 “We are focusing on flawless execution; putting that ESP in the well and making it run optimally with the right chemicals, so you don’t have to pull it for a long time,” says Gaddy.

Lonseth has noted that enabling continuous visibility and autonomous control of the chemical program has radically reduced the need for field service engineers to drive for hours each month to remote areas. This frees them up to focus on sampling, analysis and chemical program optimization. Operation costs are reduced, and the risks associated with people spending too much time traveling from well to well are mitigated.

Baker Hughes began working with this operator on its Permian wells in Lea County, New Mexico in late 2023, but the success of this solution has led experts in other counties, as well as other companies to request, “I’ll have what Lea’s having!”

“This combined automated solution could be applied anywhere that uses ESPs and where there is connectivity – or cell communication or satellite communication for that matter,” says Lonseth.

Chemical smart pumps, optimized chemicals, energy-efficient motors, and remote monitoring of far-flung sites all add up to increased production, lower costs and improved viability of wells throughout their later life cycle.

“The whole is definitely greater than the sum of its parts,” says Lonseth. “We have four teams working together across product lines and then combined the effort with our digital team and automated it with our automation team. With our digital solutions, we have a holistic view of what we’re all working towards. It’s really opened doors for what our team is capable of.”