In 2019, the question was whether High-Pressure Gas Lift could deliver reliable artificial lift results as an alternative in wells presenting a hostile environment to ESPs.
By 2026, that question has been answered—with 5,0003,500+ installations across multiple basins and the industry's first published recommended practices.
HPGL isn't experimental anymore. It's a proven option for high-rate artificial lift in unconventional wells. Here's how we got here and what it means for you as you consider lift choices going forward.
The Early Years: Proving the Concept (2017-2019)
HPGL as a lift method isn't new. The underlying physics, injecting compressed gas down the tubing and producing up the annulus, has been understood for decades. What changed in the late 2010s was the convergence of completion technology for longer laterals with higher IPs, compression technology (reliable high-pressure boosters), and economic pressure (costs of failure for other forms of artificial lift in unconventional wells).
The first serious field pilots came in 2017-2018, primarily in the Permian and SCOOP/STACKD.
Operators were testing a simple hypothesis: can HPGL match ESP production rates without the downhole mechanical complexity?
The 2019 pilot program with SM Energy, an operator with over a century of experience, was the first to generate peer-reviewed data. The results, published as SPE 195180, showed that HPGL could:
- Match or exceed ESP production rates in comparable wells
- Operate with zero rig intervention over the study period
- Run longer than offset ESPs without failure
- Deliver competitive drawdown without downhole rotating equipment
That pilot didn't prove HPGL was universally better than ESP. It proved HPGL was a viable alternative worth scaling in applicable well environments.
The Scale-Up: Multi-Well Programs (2020-2022)
With proof-of-concept established, operators began deploying HPGL in multi-well programs designed to generate statistically meaningful comparisons.
BPX Energy (Delaware Basin, 2024): BPX ran a 5-well pilot using 150-hp electric compressors. After six months, the program showed 99%+ runtime. The operational simplicity was striking and field teams described it as "set it and forget it" reliability.
Devon Energy (Delaware Basin, 2022): Devon's 9-well program directly compared HPGL to conventional gas lift (not ESP). The results were significant:
- 37% increase in cumulative total fluid production
- 123% higher peak daily total fluid rate
- 12% uplift in NPV10
- 97.7% total system availability, 99.2% mechanical availability
This wasn't HPGL beating a straw man. Conventional gas lift is a proven, reliable lift method. HPGL outperformed it substantially and did so with surface-only equipment.
DG Petro (Permian Wolfcamp, 2024): DG Petro's case study provided the most direct HPGL-vs-ESP comparison. The HPGL well achieved:
- 99.5% mechanical availability
- Surpassed offset ESP production by month 4 (oil) and month 8 (gas)
- 2.4x ROI by January 2024
- Zero workovers versus interventions required in neighboring ESP wells
The economic case was clear: in wells where ESP run life was challenged by downhole environments and workovers were required, HPGL delivered comparable rates with lower operating costs.
The Turning Point: Recommended Practices (2025)
The transition from "promising technology" to "standard practice" requires more than case studies. It requires engineering guidance that operators can apply consistently across their programs
That milestone came at SWPSC 2025, when Flowco, Coterra, and Diamondback published "Recommended Practices in High Pressure Gas Lift Installations"—the first comprehensive engineering guide compiled from seven years of HPGL deployment.
The paper:
- Establishes field‑proven recommended best practices drawn from seven years of HPGL installations and multi‑operator experience.
- Positions HPGL as a high‑rate artificial lift method that has already demonstrated strong fit for early‑life unconventional production.
- Shows how engineering‑driven design, especially nodal analysis, unlocks measurable HPGL performance gains in real‑world applications.
- Highlights how right‑sized infrastructure and deep EOT placement work together to lower bottomhole pressure and fully realize HPGL’s production potential.
- Confirms that corrosion and key operational considerations are well understood and actively managed in the field.
- Reinforces the value of early planning and flexible production tree design to ease transition to future lift methods and support scalable HPGL programs.
When operators ask, “How do I implement HPGL properly?”
This paper provides a documented answer grounded in field experience. It is not a sales piece, but a concise discussion of the issues that matter most to successful HPGL installation and operation, offering brief explanations of each core issue, related considerations, and references to supporting research and case histories so practitioners can more effectively implement and optimize this increasingly popular form of gas lift.
What the Data Shows: Where HPGL is a Strong Usecase
Seven years of field data have clarified where HPGL outperforms alternatives:
- High GOR wells: HPGL uses gas as the lift mechanism. Where ESPs are challenged with gas-lock and gas handlers add complexity, HPGL sidesteps the problem. Wells with GOR above 2,000-3,000 scf/bbl are often better HPGL candidates than ESP candidates.
- Highly deviated or tortuous laterals: ESP efficiency degrades with dogleg severity. Motor cooling becomes unpredictable. Pump stages don't perform to spec. HPGL doesn't care about wellbore geometry—the compressor is on the surface.
- Sandy or frac-hit-prone formations: Downhole equipment is a target for solids damage. Parent-child interference accelerates failures. HPGL removes the downhole target entirely.
- Power-constrained locations: HPGL can run on wellhead gas without grid power. In areas where electrical infrastructure lags development, that's a decisive operational advantage.
- Short ESP run-life history: If your formation consistently delivers ESP run lives below 15 months, the intervention economics favor HPGL regardless of other factors. The $150,000+ cost per workover adds up fast - AOGR - Artificial Lift Technology
Where ESPs May Be a Better Fit
Honest engineering requires acknowledging limitations. HPGL isn't the right answer for every well:
- Very low GOR wells: If your wells produce minimal gas, HPGL requires importing lift gas—which may not be economical. In this scenario ESPs are a likely better alternative.
- Very low flowing pressure: HPGL needs sufficient bottomhole pressure to achieve reasonable lift efficiency. In severely depleted reservoirs, other lift methods such as ESPs, conventional gas lift, or plunger lift could be more effective.
- Wells where ESP run life consistently exceeds 24 months: If you've solved the ESP reliability problem through completion design, gas separation, or formation characteristics, the efficiency advantages of downhole lift may outweigh HPGL's simplicity.
The Lifecycle Integration
Whether you choose ESPs or High Pressure Gas Lift for early production, the mid-life and late-life roadmap is the same. As rates decline and flowing pressure stabilizes, HPGL wells can transition to conventional gas lift—using the same compression infrastructure with modified injection parameters. As rates decline further, the path leads to plunger-assisted gas lift and eventually full plunger lift.
The lift method you choose on day one can determine your first 12-36 months. But the automation, compression, surveillance, and field service infrastructure shape the majority of the life of the well. Flowco's model is built on this reality. Whichever Flowco lift system you choose, our team and technologies are there to support your journey and the life of your well.