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ARGUS REMOTE MONITORING / ARM
SYSTEM LIVE
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ARGUS Remote Monitoring industrial sign at oilfield
A thousand eyes on your field
ARM // FIELD-07 // LIVE
W-014 Pad North · ESP kWh/bbl 2.81
W-022 Pad West · Rod VISCOSITY+ −7Hz
W-031 Pad South · ESP kWh/bbl 3.04
W-047 Pad East · Rod SPM 7.2
W-052 Pad North · ESP SLUDGE AUTO
W-068 Pad West · Rod kWh/bbl 2.62
Field-wide kWh/bbl · 24hr ▼ 18.4%
AI-Driven Lift · Gas Lift · ESP · Rod · Purpose-Built for Variable Crude

Every well, watched.
Every watt, accounted for.

ARGUS is an AI-driven remote monitoring and optimization platform purpose-built for oil wells running through sludge, sand, paraffin, gas slugs, and shifting viscosity. Our proprietary ARM technology replaces human guesswork with closed-loop, sub-second control across rod pumps, ESPs, and gas lift — including fleet-wide gas-lift allocation that accounts for compressor capacity, separator constraints, and reservoir drift in ways nodal analysis cannot.

The result: 5–15% production uplift, ~30% lower power costs, failures flagged days to weeks before they happen, and measurable gains across the KPIs operators are actually paid on — kWh per barrel, mean time between failures, uptime percentage, and barrels-of-oil-equivalent per day.

Schedule a discovery call See how ARM works →
30%
Power Cost
Reduction
5–15%
Production
Uplift
40%
Fewer Well
Touches
90d
Pilot to
Live ROI
01 The Problem We Solve

Right now, your operators are guessing — and your power bill is paying for it.

On heavy oil and sludge-prone wells, fluid viscosity changes hour by hour. When sludge enters the pump intake, current draw spikes. Flow drops. The pump works harder for less. Your operator notices on a SCADA screen — twenty, thirty, sometimes ninety minutes later — and dials the VFD frequency by hand.

The well that was perfectly tuned at 8 a.m. is overpumping by noon and damaging itself by sundown. By the time anyone touches it, the failure is already in the metal.

This human-in-the-loop pattern is consistent, expensive, and fundamentally outdated. 75% of rod lift wells run overpumped at any given moment. Power costs climb. Run life shortens. Workover bills compound. And no human operator — no matter how good — can hold optimal setpoints across a hundred wells at 3 a.m. on a Sunday.

The harder problem is judgment at scale. The engineers who knew which wells to coddle, which signatures meant trouble, which adjustments would hold — that knowledge walks out the door with each retirement, and it was never written down. Meanwhile wells age continuously: water cut creeps up, reservoir pressure falls, paraffin signatures shift week to week. A schedule of quarterly reviews can't keep pace with a field that's changing every shift. ARM holds the institutional knowledge in the control loop and applies it across every well, every minute.

// Manual vs. ARM-Controlled
MANUAL CONTROL
90min
Avg. response time
to viscosity change
ARM AUTONOMOUS
3sec
Closed-loop
edge response
MANUAL CONTROL
75%
Wells running
overpumped
ARM AUTONOMOUS
<5%
Wells outside
optimal band
02 Proprietary ARM Technology

ARM is a three-layer control system that senses, decides, and acts faster than any human could.

Most "AI optimization" platforms stop at dashboards and recommendations. ARM is a true closed-loop autonomous control system — built around a viscosity-adaptive control engine uniquely suited to wells producing through variable, dirty, and difficult fluid.

Speed of action is where the economics live. Every minute a pump runs at the wrong setpoint is power burned without barrels to show for it, metal fatigued without warning, and a workover edging closer on the calendar. ARM closes the gap between sensing a problem and correcting it from ninety minutes to under three seconds — and it does that on every well, every minute, without a callout. Power bills come down. Run life extends. Workovers shift from emergencies to scheduled work. Production climbs because wells stay in their optimal band instead of drifting out of it between operator visits. The same crew runs a larger fleet, and the engineering bench is freed from routine tuning to focus on the wells that genuinely need a human.

LAYER 01 / SENSE

Multi-Signal Fluid Detection

ARM fuses motor current signatures, downhole pressure gradients, vibration spectra, and surface flow telemetry to detect viscosity shifts, pump-off, gas locking, rod buckling, scale buildup, sand intrusion, and motor wear — often days or weeks before they reach a failure threshold. It sees sludge ten minutes before your operator does, and it sees a coming workover in time to prevent it.

VFD CURRENT VIBRATION DOWNHOLE Δ ACOUSTIC
LAYER 02 / DECIDE

Hybrid Physics + ML Engine

A live nodal-analysis model runs in parallel with an ML anomaly model trained on heavy-oil failure patterns. ARM matches each well to its optimal inflow curve in real time — not a fixed setpoint — and for gas-lift fields it solves allocation across hundreds of wells simultaneously, weighing compressor capacity, separator constraints, and reservoir drift in a way no engineer or nodal study can hold in their head.

NODAL LSTM PHYSICS-INFORMED
LAYER 03 / ACT

Edge-Resident Closed Loop

ARM runs the full control loop locally on edge hardware at the wellsite — no cloud round-trip, no connectivity dependency. Setpoints adjust the moment conditions change: rising water cut, falling reservoir pressure, a new viscosity signature at 3 a.m. There is no "wait for the quarterly review." Every change is logged, explainable, and reversible. Operators stay in command.

EDGE COMPUTE VFD CONTROL EXPLAINABLE
03 Coverage

One platform. Every optimization factor. Every form of lift.

Most platforms specialize in one fluid problem and one lift type. ARM was built to handle the entire envelope of conditions that show up in real fields — including the messy, variable cases that competitors avoid.

01 Gas Lift Allocation Field-wide gas distribution across hundreds of wells, solving compressor capacity, separator limits, and reservoir interactions in real time. Beyond what nodal analysis can resolve.
02 Sludge & Paraffin Real-time viscosity tracking with adaptive frequency response. Our origin use case.
03 Sand & Solids Vibration-based abrasion detection prevents pump erosion before it cascades.
04 Heavy Crude Viscosity Continuous fluid-density inference from current-to-flow ratio shifts.
05 Gas Interference & Slugging Acoustic and pressure-pattern recognition for gas locking and pump-off events.
06 Water Cut Variability Auto-tuning to changing water-oil ratios across the well's life — no scheduled review required.
07 Scale & Tubing Issues Drift detection on baseline current signatures flags scaling early.
08 Predictive Failure Detection Rod parts, hole-in-barrel, fluid pound, motor wear, bearing degradation — flagged days to weeks ahead. Workovers become scheduled, not emergencies.
09 ESP Run Life Coordinated speed and backpressure control to maximize uptime.
10 Pump-off & Plunger Lift Cycle optimization, idle-time tuning, premature-opening prevention.
11 Energy / kWh per Barrel Field-wide power optimization as the unifying objective function.
04 Results

Numbers from real, comparable field deployments — not aspirational targets.

The figures below are drawn from published outcomes on platforms operating with the same general control architecture as ARM. We benchmark against them and our pilot KPIs match or exceed.

30%
Reduction in operating costs
Across rod-lift fields running autonomous setpoint management — energy, workovers, and crew time combined
FIELD AVG.
15%
Production uplift on 200-well deployment
Independent operator, 12-month measured outcome — wells matched to optimal inflow curves, not fixed setpoints
CASE: BAKKEN
22%
Compression cost reduction on gas-lift fields
Field-wide allocation routing gas to highest-marginal-value wells; high-water-cut wells throttled automatically
GAS LIFT
33%
Longer ESP run life
Coordinated pump speed + tubing pressure control with early-warning failure detection
ESP COHORT
50%
ESP failure rate reduction
Sub-second autonomous adjustment vs. manual control; signatures of motor wear and bearing degradation flagged days ahead
ESP COHORT
$17.7M
Annualized incremental value
West Texas operator across 4,000+ wells — small per-well gains compounded across a mature fleet
PUBLISHED
CASE STUDY · HEAVY OIL · LATIN AMERICA
"We stopped fighting sludge events. ARM started catching them ten minutes before our best operator could."
−24%
kWh / Barrel
+11%
Avg. Uptime
−62%
Operator Touches
63d
Time to ROI

A 60-well heavy-crude operator deployed ARM across two pads as a controlled pilot. Within nine weeks, kWh-per-barrel dropped 24% on instrumented wells. The operator expanded to the full field within the quarter. Full case study available under NDA.

Capability
Weatherford ForeSite
Ambyint
ARGUS ARM
Sludge / viscosity-adaptive control
Generic
Generic
Native ✦
Edge-resident closed loop (no cloud dependency)
Yes
Cloud-first
Yes ✦
Lift-method agnostic (ESP, rod, plunger, gas, PCP)
Yes
Rod / plunger
Yes
Outcome-shared pricing option
No
No
Yes ✦
Pilot deployment time
6–12 mo
2–4 wk
90 days, full ROI
Built for mid-market & heavy-oil regions
Enterprise only
NA shale
Yes ✦
Transparent / explainable setpoint reasoning
Black box
Partial
Full audit trail ✦
05 Why ARGUS

Four ways ARM is fundamentally different from what's on the market today.

We didn't build another general-purpose production-optimization dashboard. We built the system the heavy-oil and sludge-affected operator has been waiting for.

01

Built for dirty fluid first

Competitor platforms assume relatively clean shale-oil conditions. ARM's core control engine was designed from day one around variable viscosity, sludge events, and the kind of fluid composition shifts that wreck conventional optimization logic.

02

Edge-first, built for fleets

ARM's full control loop runs on hardened edge hardware at every wellsite. If the network drops, optimization continues. The architecture scales linearly: a hundred wells or four thousand, each one tuned independently, every minute. Small per-well gains compound into the kind of P&L impact that only shows up at fleet scale.

03

Outcome-shared pricing

Two pricing tiers: a low flat per-well subscription for predictability, or an outcome-shared model where we earn when you save on power and lift OPEX. Skin in the game. Most competitors won't offer this — we will.

04

Transparent AI, not a black box

Every setpoint change ARM makes is logged with the reasoning, the sensor inputs, and the model confidence. Your engineers see exactly why the system did what it did. Operator trust is built on visibility, not promises.

06 Deployment

From discovery to autonomous control in 90 days.

Our pilot model is built to de-risk the buyer. You start in advisory mode, validate that ARM matches or beats your best operator's decisions, and only then move to autonomous control — with kill switches and override authority preserved at every stage. ARM is remote-by-default, so site visits, vehicle emissions, methane leaks from preventable failures, and the driving risk that comes with crew callouts all drop alongside OPEX.

DAY 0–14
Discovery & Instrumentation
Site survey, identify problem wells, integrate with existing SCADA & VFD infrastructure. No rip-and-replace.
DAY 15–45
Advisory Mode
ARM observes, recommends setpoints in real time. Operators implement and validate. Calibration to your wells.
DAY 46–75
Supervised Autonomous
ARM begins making setpoint changes within pre-approved bounds. Operators retain override authority on every well.
DAY 76–90
Full Closed Loop
Performance KPIs validated against pilot agreement. Expansion plan finalized. Field-wide rollout begins.
Begin · Pilot · Scale

Stop paying for guesswork.
Start optimizing every well, every watt.

The ARGUS team will walk through your field profile, identify the highest-friction wells, and propose a no-risk 90-day pilot with pre-agreed success metrics. Most operators see measurable savings within the first 30 days.

Schedule discovery call Download technical brief ↓