It is 10:47 PM on a Thursday. A stock tank is five feet from the top and filling. Nobody is watching. The pumper gauged it at 7 AM, wrote “half” on the ticket, and went home. By 6 AM Friday the oil is on the ground, the regulator is on the phone, and the cleanup is into five figures. That is the hole oilfield monitoring is supposed to close.

Oilfield monitoring is how an operator knows what is happening at a well, a tank, or a facility without being there. In practice it covers tank levels, runtime, line pressures, gas flow, water cut, and alarms for things like high tank, low suction, or a comm failure. The tools range from a pumper writing numbers on a route sheet to a phone app the field team checks on the drive between sites to SCADA pulling from programmable logic controllers every few seconds. This guide walks through what each approach actually does, where it breaks down, and which operators fit which stack.

One thing to get out of the way up front: most operators already have more dashboards than they watch. The question is rarely more monitoring. It is which monitoring actually reaches the person who can act on it. That is the thread that runs through everything below.

This is written for the producer (the operating company that owns the wells) and the ops lead or field supervisor inside it who is trying to decide what to install next. Not for the vendor writing a brochure. If that is you, keep reading.

This post is for you if:

  • You run anywhere from 15 to 2,000+ wells and your production data is 2 to 3 weeks late by the time anyone sees it.
  • You have tanks, pressures, or runtime you cannot see between pumper visits, and you have already been burned by a tank overflow, a stuck pump, or a leak nobody caught.
  • You want the honest read on when SCADA earns its keep versus when a phone-first app plus drop-in monitoring covers ~99% of the upside.
  • You are tired of dashboards nobody opens and alarms that go to an inbox nobody reads.

If none of that fits, the oil and gas SCADA guide is the next step up in instrumentation and the oilfield automation guide covers when monitoring becomes control.

What Oilfield Monitoring Actually Covers

The word monitoring gets used for everything from a pumper’s daily route to a fully instrumented automated lease. It helps to split the scope into what is being watched.

Production volumes. Daily oil, gas, and water numbers per well or tank. This is the core number for allocation, revenue, and regulatory reporting. Usually captured once a day by the pumper and reconciled at month end.

Runtime and downtime. Is the pump on? For how long? What stopped it last night? Runtime feeds optimization decisions (clock setting, rod pump cycling) and is the first thing engineering looks at when production dips.

Tank levels. How full is the stock tank? The saltwater tank? This drives haul scheduling and tank overflow prevention. Level is checked manually with a gauge line, or automatically with a radar or guided-wave sensor reporting back to a controller.

Pressures. Tubing pressure, casing pressure, line pressure, separator pressure. Trends matter more than single readings. A gradual casing pressure climb is a different problem than a sudden line pressure drop.

Alarms. High tank, low suction, comm failure, ESD (emergency shutdown), freeze alarms in winter, fire and gas alarms at larger facilities. Alarms are the thing monitoring exists to surface.

Equipment health. Motor amps, VFD frequencies, compressor runtime, chemical pump status. Mostly lives in SCADA for operators that have it.

Not every operator needs all of this. A conventional operator (could be 15 wells in Oklahoma or 1,500 across the Midcon) may get by fine with daily pumper rounds, a phone app for field capture, and remote tank and pressure monitoring on the sites where the math pays. An unconventional operator with active compression, high-volume horizontals, and meaningful control needs usually runs SCADA on top of or alongside the rest. The stack has to match the economics of each site, not the total well count on the ledger.

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The Real Approaches Operators Use

Not counting the “we’ll watch everything with 200 sensors per well” vendor pitch that doesn’t survive first contact with a real operator, there are about four patterns that actually show up in the field.

1. Manual pumper rounds with a paper ticket

One pumper, a route of 8 to 30 wells, a clipboard, a gauge line, and a truck. They drive the route, write down volumes and any concerns, and hand the ticket in at the end of the week or scan it to the office.

This is still the most common pattern for conventional stripper operations. It works. It is cheap. It also loses data regularly, depends on one person’s handwriting, and makes month-end reconciliation painful.

2. Phone-based field data capture

Same pumper, same route, same truck. But the paper ticket is replaced with a phone app. Volumes, runtime, and comments go into the app at the site. The office sees the data in close to real time, with photos, timestamps, and GPS.

This is the sweet spot for most conventional operators, whether the route covers a handful of wells or a couple thousand. Greasebook sits in this category for producers who want structured field data capture flowing into allocations, state reports, and an executive dashboard. TinyPumper pairs phone-first field capture with the hardware monitoring side (tank levels, pressures, runtime) for producers who decided SCADA was never going to pencil on the wells in question. The data still comes from a person (or a sensor), but the capture is structured, timestamped, and searchable.

3. SCADA + telemetry

Programmable logic controllers (PLCs) or remote terminal units (RTUs) at each site pull data from sensors and send it over cellular, radio, or satellite to a central server. The office sees continuous data and can set up alarms that text the pumper or the engineer.

This is the standard approach for unconventional operators with 50+ wells, for any facility with compression or water handling, and for anyone with meaningful automated control needs (plunger optimization, gas lift, injection). SCADA systems are the workhorses here. Costs are meaningful, installation takes weeks or months, and the system needs someone to maintain it.

4. Hybrid: SCADA at facilities, app at the wellhead

Most growing unconventional operators land here. The central tank batteries, compressor stations, and disposal wells are instrumented with SCADA. The wellheads and satellite sites rely on a pumper with a phone app. The app and the SCADA system may or may not talk to each other. When they do, the app shows runtime and alarms alongside the manual gauge entry.

This is what most growing unconventional operators actually run, whether they are at a hundred wells or well north of 2,000. It is messier than a single system, but it matches the economics: instrument the expensive, centralized stuff; trust the pumper (and the right phone-first tool) for the rest.

How the Tools Compare

Approach Typical well count Data latency Upfront cost Monthly cost Best for
Manual paper rounds A handful to a few dozen Days to weeks Near zero Near zero Stripper wells, one-pumper shops
Phone field data app A few wells to 2,000+ Minutes Low (no hardware) $50 to $500 per user Conventional ops at any scale
SCADA + telemetry Any scale with instrumented sites Seconds $3K to $15K per site $50 to $200 per site hosted High-volume wells, compression, injection, facilities
Hybrid (SCADA + app) Any scale Mixed Depends on instrumented site count Depends on mix Growing ops with central facilities

These are honest ranges. The SCADA per-site number varies wildly based on what is already at the site, what you are metering, and whether you are doing the install yourself or paying an integrator. The phone app per-user number depends on whether you are pricing a pumper-facing app or an enterprise platform.

Which Stack Fits Your Next Site

If you… Then… Because
Run conventional wells where SCADA never penciled Phone-first app plus drop-in remote monitoring like TinyPumper You get ~99% of the SCADA upside without wires, trenches, or an integrator
Run aging SCADA that costs more to maintain than it returns Swap in drop-in monitoring on the hurting sites Kills the maintenance drag without a rip-and-replace
Run high-rate horizontals, compression, SWD, or a gas plant SCADA is still the right tool Supervisory control and facility safety loops are not an app job
Mix conventional and unconventional Hybrid: SCADA at facilities, phone app plus TinyPumper at the conventional sites Match the stack to the site economics, not a spreadsheet count
Have more dashboards than anybody watches Route alarms to a text or push notification first, buy nothing else More sensors will not fix an alert-routing problem

Where Oilfield Monitoring Breaks Down

Three failure modes come up over and over in operator conversations.

Data that nobody looks at. The monitoring system captures everything. The dashboard shows everything. Nobody opens the dashboard. The alarms fire into an inbox nobody reads. The fix is almost never add more sensors. It is route the signal to the person who can act on it (usually a text, a push notification, or a morning report).

The stack stops matching the footprint. A producer instruments 50 wells with SCADA, then acquires 200 more that don’t have it. Or a growing op takes on a block where half the sites use a different telemetry vendor than the rest. The monitoring system gets abandoned because keeping it current is more work than the data is worth. The honest version: monitoring tools have to be as easy to expand and contract as the footprint they cover.

Pumper-facing tools that fight the pumper. A phone app designed by someone who has never gauged a tank is obvious in under five minutes of use. The screens are too complicated, the sync is brittle, the offline mode doesn’t work, the login times out. Any monitoring tool that relies on the field hand has to earn their cooperation. Most don’t.

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Which Tool for Which Operator

Forget the well-count bands. The axis that actually matters is site economics: does SCADA pencil on this site, or does it not?

Greasebook: the production software layer. Producers use Greasebook whether they run 15 wells or 2,000. The job is the same: get pumper-entered data (gauges, pressures, run tickets, photos) from the field to the office in minutes, automate state reports (Texas RRC PR plus Mississippi, Alabama, Wyoming, and Michigan, with more added over time), run allocations, and feed decline-curve tools like PHDwin. Horizontal operators running SCADA on their best wells plug Greasebook in alongside it; field-entered data and SCADA-sourced data live in one screen. Greasebook is the centralized production source of truth, regardless of how the data got there.

TinyPumper: the SCADA alternative on conventional sites. TinyPumper is what you reach for when SCADA does not pencil, or when the legacy SCADA you already have is breaking down and costing more to maintain than it returns. It delivers roughly 99% of the upside of SCADA (tank levels, pressures, engine and compressor runtime, threshold alerts) without the wiring, the electrician, the IT burden, or the five-figure per-site capex. That value prop holds for a 50-well operator and a 5,000-well operator. The gate is not well count. The gate is whether the site is conventional and whether the SCADA math ever worked.

Two questions are worth asking on every site:

  1. Is this a conventional well, tank battery, or facility where SCADA either never got installed (because the ROI did not pencil) or is now breaking down? If yes, TinyPumper is the honest drop-in. Ten minutes of install, no wires, flat rate per site, lifetime hardware replacement.
  2. Is this a high-volume site where full supervisory control (actuation, setpoint changes from the office, PLC-driven logic) genuinely earns its keep? If yes, SCADA. That is what it is for. Nobody is pretending TinyPumper replaces DeltaV on a compressor station.

Most producing companies end up with a mix. Greasebook for the production layer, TinyPumper for the sites SCADA could never justify, and SCADA where the economics demanded it all along. The stack matches the site, not the spreadsheet count.

For deeper reads: oilfield monitoring app for the phone-first side and oilfield monitoring software for the broader software category.

What “Real-Time” Actually Means

Vendors throw around real-time like it means the same thing in every context. It doesn’t.

  • Real-time on SCADA usually means data arrives within a few seconds of the measurement, polled on a cycle (often 5 to 60 seconds).
  • Real-time on a phone app usually means the pumper’s entry shows up in the office within a minute, once the phone has signal.
  • Real-time on a dashboard can mean anything from seconds to “whenever the last batch job ran.”

The question is rarely how fast is real-time. It is is it fast enough that I can act before the problem gets worse. A tank filling at 2 barrels per hour doesn’t need second-by-second polling. A compressor trip does. Match the tool to the decision window.

Where Monitoring Ends and Control Begins

Monitoring tells you what is happening. Control changes what is happening. A tank level sensor is monitoring. A valve that opens when the tank hits 80% is control. SCADA systems typically do both. Phone apps do not.

If the conversation shifts from “I need better visibility” to “I need to start and stop pumps from my desk,” you are past monitoring and into oil and gas automation. The cost and complexity step up sharply.

How Much Does This Cost

Honest ranges, not vendor sticker prices.

Phone field data capture. $20 to $100 per pumper per month for basic tools. Higher for enterprise platforms with integrations.

SCADA per site. $3,000 to $15,000 up front for hardware (RTU, sensors, cabinet, communications). $50 to $200 per site per month for hosted monitoring, support, and cellular data. Plus an integrator or in-house hand to maintain it.

Full stack across a few hundred to a few thousand wells. Expect meaningful capex spread over a few years for instrumentation (often six to seven figures depending on site count and what is already in the ground), plus a recurring operating cost in the high five to mid six figures per year for software, hosting, and someone to keep it alive. The numbers scale roughly linearly with instrumented site count, not total well count.

These are not small numbers. They also aren’t optional for most unconventional operators past a certain size. The question is always what the stack has to do, not what it costs in the abstract.

Who This Is Not For

Single-well stripper operators with no cell reception. The cheapest phone app in the world still needs the pumper to have a phone, signal, and the habit of opening the app. If any of those are missing, paper still wins.

Downstream or midstream operators needing full DCS-grade control. Oilfield monitoring tools handle upstream production and facility work. Full distributed control systems for refining, compression stations at pipeline scale, or NGL plants are a different category with different vendors.

Operators who want a single vendor for everything. There is no tool that does paper replacement, SCADA, automation, IoT, analytics, and regulatory reporting under one roof well. Anyone pitching that, in our experience, does one part well and the rest poorly.

What pumpers and operators actually deal with in the field

Monitoring only earns its keep when it connects to what is happening at the tank battery. These are the field-side guides we point operators to when they want to understand what the data is describing.

The SCADA alternative for conventional wells at any scale

TinyPumper installs in 10 minutes, flat rate per site, no wires, no IT team. It works whether you run 50 wells or 5,000.

Start with TinyPumper Or take the fit quiz

About the author: Greg Archbald is the founder of GreaseBook and TinyPumper. He built both products from inside the oil patch and has spent 15+ years on the operator side of oil and gas technology.

Frequently Asked Questions

What is the difference between oilfield monitoring and SCADA? Monitoring is the broad category of knowing what is happening at your wells and facilities. SCADA (Supervisory Control and Data Acquisition) is one specific approach that uses PLCs or RTUs with sensors, telemetry, and a central server. All SCADA is monitoring. Not all monitoring is SCADA. A pumper with a phone app is also monitoring.

Do I need SCADA if I already have a pumper doing daily rounds? Depends on site economics, not total well count. On conventional wells and tank batteries where SCADA never penciled (or the legacy SCADA you have is breaking down), a phone app plus a light hardware monitor like TinyPumper covers roughly 99% of what SCADA would have given you without the wiring, the electrician, or the ongoing IT drag. Where you have compression, injection, high-volume horizontals, or genuine supervisory control needs, full SCADA still earns its keep.

Can I run monitoring without cellular service at the site? Yes, though the options narrow. Satellite telemetry (Iridium, Inmarsat) works anywhere but is expensive per site. Radio networks work if you have line of sight back to a base. Offline-capable phone apps work as long as the pumper eventually gets signal on the drive back. Pure paper also still works.

How long does it take to roll out oilfield monitoring? Phone apps deploy in days. SCADA rollouts take weeks to months per site depending on power availability, permitting, and whether the site already has instrumentation. A full facility retrofit can take a quarter or more. Budget realistically.

Who actually looks at the monitoring data? If the answer is “nobody consistently,” the monitoring system isn’t working. Good setups route alarms and daily exceptions to the specific person who can act (pumper for tank-fills, engineer for pressure anomalies, supervisor for missed rounds). Dashboards are for the people who look at data in batches. Notifications are for the people who need to act on it.