The Autonomous Operations Center
Every completed cycle triggers a full re-evaluation. The AI reads recent history across 145 input features, predicts what the next cycle requires, and dispatches fresh control setpoints — before the cycle begins.
Why Gas Wells Lose Production and Money
Liquid loading in mature gas wells silently erodes production, inflates operating costs, and exposes operators to growing environmental and regulatory risk. Conventional plunger lift systems — governed by fixed timers and manual rule-of-thumb adjustments — were never designed to adapt.
Declining Production & Revenue Loss
Liquid accumulation in the tubing restricts gas flow, causing significant production decline and direct revenue loss. As reservoirs mature, liquid loading intensifies while conventional fixed-timer controllers remain blind to changing well behavior cycle by cycle.
High Operating Expenditure
Frequent manual interventions, trial-and-error cycle adjustments, and unplanned wellsite visits drive up maintenance and labor costs. Engineers managing multiple wells cannot physically review hundreds of plunger cycles per day — operational problems remain invisible until they become expensive failures.
Unplanned Methane Emissions
Traditional blowdown methods result in substantial methane venting, exposing operators to EPA regulatory penalties and environmental compliance risk. Without cycle-level precision control, operators over-vent or under-vent with no systematic mechanism for correction.
Limited Scalability Across Portfolios
Managing hundreds of wells with different reservoir behaviors, tubing configurations, and liquid rates is operationally infeasible using conventional fixed-timer or basic threshold-based automation. Each well demands individual attention that engineering teams simply cannot provide at scale.
Poor Adaptability to Changing Conditions
Reservoir depletion, varying liquid loads, seasonal pressure fluctuations, and wellbore skin changes make static control systems progressively less effective over time — leading to chronic underloading, overloading, failed lift cycles, and accelerated equipment wear.
No Early Warning Before Failures Occur
By the time a stuck plunger, liquid loading event, or pressure decline is visible in production data, 24–72 hours of production and thousands of dollars in intervention costs have already been lost. Manual review covers only 10–20% of all cycles.
What Operators & Managers Control
Eight purpose-built modules covering every dimension of plunger lift operations — from individual cycle decisions to fleet-wide intelligence.
GLR Feasibility Check
Before investing in plunger lift infrastructure, the system automatically verifies whether a well meets the physical minimum requirements. Avoids $15,000–$60,000 per well in capital misallocation.
Pressure & Velocity Analysis
Arrival velocity is classified every cycle as slow, optimal, or excessively fast. High-velocity prediction triggers automatic shut-in reduction before damage occurs. Saves $500–$2,500 per plunger set.
Shut-In Optimization
Replaces fixed timers with dynamically computed optimal shut-in every cycle using live pressure buildup rate, liquid height estimate, and predicted arrival velocity. Recovers 2.7–6 hours of deferred production per well per day.
Afterflow Management
Afterflow is the only phase where gas is being sold. The system predicts the optimal minimum flowrate threshold every cycle, keeping the valve open while production is healthy. Up to 40% production gain — zero capex.
Insights Dashboard
Production forecast with 80% confidence intervals. Root cause analysis ranks parameters by significance. Replaces 4–8 hours of weekly well log review per engineer and achieves 100% cycle coverage vs. 10–20% manually.
AI Advice Engine
Every key metric carries an instant AI recommendation. When reviewing casing pressure, load factor, or velocity, the system tells operators exactly what action to take. Reduces new operator training time by 40–60%.
Multi-Well Portfolio View
Top and lowest performing wells, multi-metric comparison across velocity, arrival rate, and health score. Full fleet situational awareness in under 5 minutes. Unified alerts from every well in a single feed.
Explainable AI
Every cycle logged, timestamped, and retrievable. When the model predicts low arrival velocity, operators view the exact trend driving the prediction — verifying AI reasoning before acting. Supports regulatory reporting and warranty claims.
Setpoints Updated Every Cycle
Every completed cycle triggers a full re-evaluation. The model re-reads recent history, computes fresh optimal values, and validates them against physics rules — in 0.2 seconds. No human required.
Reduces well monitoring and analysis time from 30–60 minutes per well per week to under 5 minutes. Reduces operator labor by an estimated 20–40 hours per well per month.
Intelligent Mode Switching
TOUR + HOLD
Stabilizes setpoints during an observation window, building a reliable operational baseline before any optimization adjustments begin.
PR OPT
Production Optimization mode actively adjusts setpoints toward the production target when conditions are favorable — extracting additional output exactly when the well has reservoir energy to deliver it.
RESCUE
Automatic emergency stabilization that activates when the system detects conditions indicating a developing failure. Protects the well and prevents damage without waiting for operator intervention.
Deploy in 24 Hours. Results in 30 Days.
Run a no-upfront-cost pilot on 3 wells for 30 days. We prove performance before you commit.
Initialize Pilot Launch