Walk into a wellsite automation demo and the screen shows dump valves cycling, separators staging, tanks leveling, all in green. Walk onto the actual pad and a blowing norther has iced a sensor line, the dump is stuck open, and the pumper is out there with a propane torch trying to thaw a valve before the separator carries over. The aspirational version lives on the laptop. The real version lives with a man and a torch at 5:30 AM in February. Both matter. They just aren’t the same thing.
TL;DR. Wellsite automation is the iron-and-wiring layer of oilfield automation at the pad: pump-off controllers, separator controls, tank instrumentation, safety shut-ins, local RTUs or PLCs, and local HMIs. It does not include the central SCADA host (that is field-level) or the pumper’s daily data capture (that is workflow-level). The right sequence is cheap safety and equipment-level automation first, instrumentation second, full pad-level RTUs only where rate and downtime cost justify it. On conventional wells where a SCADA build never penciled, a drop-in SCADA alternative at the tank battery handles the remote-visibility piece without the trenching, the panel work, or the IT burden.
This page is for the operator trying to figure out what belongs on the pad, what it costs, and where to spend first.
What Belongs on the Wellsite
The wellsite automation stack typically includes:
- Pumping unit controls: pump-off controller on rod-pumped wells, variable speed drive where stroke-rate modulation makes sense, plunger lift controller on gas wells with loading issues.
- Separator controls: automatic dump valves, level controllers, pressure controllers.
- Tank battery instrumentation: tank level transmitters, high-level shut-in switches, temperature sensors.
- Wellhead and flowline instrumentation: pressure transmitters, flow meters, temperature sensors.
- Safety automation: high-level shut-ins that kill the well when a tank is close to overfill, pressure relief valves, emergency shutdown logic.
- Local RTU or PLC: aggregates the sensors, runs local logic, hosts the HMI, and (optionally) communicates back to SCADA.
- Local HMI: a touch screen or panel display the pumper or technician uses on site.
Not every well has every piece. A 3 bpd stripper well might have a timer-based POC and a tank level shut-in and nothing else. A multi-well horizontal pad (Texas, Oklahoma, North Dakota, Pennsylvania, anywhere the rock pays for it) might have full instrumentation at every well, a dedicated PLC, and telemetry back to a SCADA server.
What Each Layer Actually Costs
Ballpark costs vary by region, integrator, and scope, but the rough ranges look like this:
| Component | Typical cost |
|---|---|
| Basic timer-based POC | A few hundred dollars plus install |
| Dynamometer-based POC | Few thousand dollars plus install |
| Plunger lift controller | Few thousand dollars installed |
| Tank level transmitter | Hundreds to low thousands each |
| High-level shut-in switch | Hundreds plus install |
| Separator level / dump automation | Few thousand dollars |
| RTU or PLC at the pad | Several thousand dollars plus panel work |
| Full pad instrumentation + RTU + HMI | Tens of thousands |
| Telemetry (radio, cellular, satellite) | Thousands per site |
Real numbers vary widely. A greenfield horizontal pad build-out routinely runs into the low-to-mid six figures for automation alone. A retrofit on a legacy vertical well might be a few thousand dollars well-by-well.
Where to Spend First
A reasonable first-dollar-in sequence:
- Pump-off controllers on rod-pumped wells that don’t already have them. Payback is usually fast.
- High-level tank shut-ins on any tank battery where overfill is a realistic risk. Cheap, often required by insurance or regulation.
- Plunger lift controllers on gas wells with liquid loading.
- Tank level transmitters on tanks where manual gauging is expensive or unreliable.
- Pad-level RTU/PLC with instrumentation on wells where the rate and downtime cost justify continuous monitoring.
- SCADA telemetry tying the RTUs back to a central dashboard: if the operator has enough instrumented wells and a team to maintain it.
The common mistake is jumping to step 5 or 6 before steps 1 through 3 are even in place. A fully instrumented pad with no POCs on the pumping units is a strange investment pattern but happens more often than it should.
The Operational Layer That Sits Beside Wellsite Automation
Wellsite automation handles what happens at the well within the broader picture of automation in upstream oil and gas. The data chain: what the operator sees on their screen: is a separate layer.
A fully automated pad with every sensor and every controller is still only as good as the operational workflow that turns that data into production reports, regulatory filings, and business decisions. Many operators under-invest in the operational layer because it doesn’t come in a pumping-unit-shaped box.
Pumper-data capture apps fill the gap between wellsite automation and operational reporting. The pumper shows up at the site, sees what the automation is telling them (alarms, stroke counts, tank levels), captures the gauges and run tickets that the automation doesn’t produce, and logs any observations. That data goes straight to the operator’s dashboard.
TinyPumper is built for that gap. On a conventional well where SCADA never made the math work (or where legacy SCADA is breaking down and the maintenance bill no longer earns its keep), TinyPumper delivers the remote-monitoring piece without the wiring, the integrator, or the IT burden. The producer buys it. The pumper (company or contract) uses it alongside GreaseBook on their phone.
The producer who runs a tight wellsite program doesn’t think of themselves as an automation shop. They are the operator who keeps the iron working, the safety gear honest, and the data clean enough to make real decisions from. The automation is the tool. The operating discipline is the identity.
Amateur vs Pro: How Operators Actually Build a Wellsite Stack
| The amateur… | The pro… |
|---|---|
| Spec’s a fully instrumented pad on the first project | Installs the POC, the tank shut-in, and the pumper-data app first, then layers up |
| Buys the RTU before the tank-level sensors that feed it | Commissions the sensors, proves the readings, then adds the RTU logic on top |
| Treats the HMI screen as the win | Treats the pumper’s phone as the win and uses the HMI as the backup |
| Leaves the high-level shut-in untested for years | Walks every shut-in with the pumper every tank cleaning cycle |
| Copies the horizontal pad build to every conventional well | Matches the automation depth to the rate, the risk, and the maintenance capacity |
Tank levels, pressures, runtime, pushed to the cloud from a matchbox-sized gateway. Installs in 10 minutes. Works on conventional wells at any scale.
See how TinyPumper works →What Wellsite Automation Doesn’t Cover
A fully automated wellsite still doesn’t:
- Tell you how much was sold. Run tickets from the transport driver are the sold-barrel record, not the flow meter.
- Track BS&W on sold oil. BS&W is measured on the run ticket, not at the lease meter.
- Log who was at the site, when, and what they did. Pumper visit logs are a workflow record, not an automation feed.
- Feed regulatory production reports. State forms want monthly sold barrels, disposition, purchasers, and inventory: not just flow meter totals.
- Coordinate routes across multiple sites. That is a pumper workflow problem, not a wellsite automation problem.
The smart operator treats wellsite automation and operational data capture as two different spends with two different ROI curves. Both are worth doing; neither is a substitute for the other.
What To Avoid: The Gap Between the Demo and the Pad
- The SCADA Silo at the pad level. Every vendor adds their own HMI. If they don’t speak to each other, the pumper has five screens and trusts none of them. Pick the consolidation layer first.
- The Paper Lag underneath the automation. If the pumper is still writing tickets on paper and keying them into Excel at month-end, all the tank telemetry in the world won’t close the data chain.
- Spec’d for the best day, not the worst. The demo works in March. Design for January in North Dakota and August in West Texas. Thermals, dust, freeze, brush, cell coverage holes.
- Nobody owns the alarm stream. An unowned alarm screen is a silence. Assign an on-call rotation before the first alarm rings.
- No plan for the ninety-first day. Automation that works for the first 90 days and then gets abandoned when the first sensor fails costs more than never installing it. Budget the maintenance line on day one.
Wrong Fit for This Page
If you are a major operator with a full automation program already in place on high-rate unconventional pads, this page is too ground-level. Your wellsite automation is a program managed by your automation team, not a decision at the well. This page is for independent producers (anywhere from a handful of wells to 2,000+) who need to understand what fits on the pad and where to sequence the spend, regardless of whether the field work is done by company pumpers or a contract pumping outfit.
FAQ
Is TinyPumper classified as wellsite automation?
Yes. TinyPumper is a matchbox-sized solar-powered gateway plus radar and pressure sensors that install in about 10 minutes. It monitors tank levels, pressures, and engine and compressor runtime, and pushes data to the cloud over cellular or satellite. On conventional wells where full SCADA never penciled out (or where legacy SCADA is on its last legs), TinyPumper delivers roughly 99% of SCADA’s upside without the cost or complexity. Works at any scale.
What is wellsite automation?
Wellsite automation covers the controllers, sensors, RTUs, and instrumentation at the individual well pad or tank battery that run equipment and coordinate local logic without human intervention. It does not include central SCADA (which is field-level) or operational data capture (which is workflow-level).
How much does wellsite automation cost?
From a few hundred dollars for a basic POC to tens of thousands for a fully instrumented pad with RTU and HMI. Cost depends on well count, rate, and how much automation is truly needed.
Do all wells need wellsite automation?
No. Conventional wells often get by with a POC and a tank shut-in plus TinyPumper for remote monitoring. Higher-rate wells, gas wells with loading issues, and regulated sites typically justify more extensive instrumentation and, sometimes, full SCADA.
What is the difference between wellsite automation and SCADA?
Wellsite automation runs the equipment at the pad. SCADA aggregates the wellsite data across many pads into a central dashboard with alarms, history, and supervisory control. Both can coexist, but they solve different problems.
Related Pages
- Oil and gas automation: the pillar guide to automation in the industry.
- Oilfield automation: the field-level view of automation.
- Pump off controller: the most common piece of equipment-level wellsite automation.
- Automation in oil and gas industry: the four-layer automation stack.
TinyPumper arrives in a box, installs in 10 minutes, and starts pushing tank levels, pressures, and runtime to the cloud. Roughly 99% of SCADA's upside without the capex or the IT burden, on a 50-well operation or a 5,000-well operation.
See how TinyPumper works →