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 operator, contract pumper, or field supervisor who is trying to decide what to install next, not for the vendor writing a brochure. If that is you, keep reading.

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 20-well conventional operator in Oklahoma may get by fine with daily pumper rounds, manual gauging, and a phone app for the supervisor. A 500-well unconventional operator in the Permian needs SCADA, telemetry, automated tank level, and an app layer on top. The stack has to match the footprint.

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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 from 5 wells up to a few hundred. Phone apps like Greasebook for operators and TinyPumper for contract pumpers sit in this category. The data still comes from a person, 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 operators in the 100- to 1,000-well range actually run. It is messier than a single system, but it matches the economics: instrument the expensive, centralized stuff; trust the pumper for the rest.

How the Tools Compare

Approach Typical well count Data latency Upfront cost Monthly cost Best for
Manual paper rounds 1 to 50 Days to weeks Near zero Near zero Stripper wells, one-pumper shops
Phone field data app 5 to 500 Minutes Low (no hardware) $50 to $500 per user Conventional ops, contract pumpers
SCADA + telemetry 50 to thousands Seconds $3K to $15K per site $50 to $200 per site hosted Unconventional ops, instrumented facilities
Hybrid (SCADA + app) 100 to thousands 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.

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. An operator instruments 50 wells with SCADA, then acquires 200 more that don’t have it. Or a contract pumper adds a 4th operator’s route and discovers each operator uses a different app. 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

This is the short version of what I would tell an operator over coffee.

  • 1 to 5 wells, stripper. Stay on paper if it works. If the pumper is on a smartphone and willing, move to a free or cheap phone app so volumes survive when someone switches routes.
  • 5 to 50 wells, conventional. Phone-based field data capture is the right default. Greasebook is the common pick for operators. TinyPumper is the common pick for contract pumpers handling multiple operators.
  • 50 to 200 wells, conventional or early unconventional. Phone app plus some SCADA at the biggest tank batteries. Do not try to SCADA every wellhead unless the math works.
  • 200 to 1,000 wells, unconventional. Hybrid is the honest path. SCADA at facilities, app at wellheads, reconciled monthly. Consider production optimization platforms for the analytics layer on top.
  • 1,000+ wells, full instrumentation. Full SCADA plus an oilfield IoT layer plus analytics plus the phone app for the people still doing rounds. The stack is big and the ops team managing it is not small.

If the operation is mostly contract pumping across several operators, the calculus is different. See 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 at 500 wells. Expect $300K to $1M capex spread over a few years for instrumentation, plus a recurring $100K to $500K/year operating cost for the software, hosting, and someone to keep it alive.

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.

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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 well count, facility complexity, and what decisions you need to make faster than a daily round. For most operators under 50 wells with conventional production, a phone app for the pumper is enough. Past 50 wells or once you have compression, injection, or water handling facilities, SCADA usually 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.