Wellsite automation is the chunk of oilfield automation that happens at the actual pad or well location: the pumping unit, the separator, the tank battery, the wellhead. It covers the controllers, sensors, panels, and logic that run individual equipment and coordinate what happens on the site without a human being physically there. It does not include the central SCADA server (that lives in the office) or the production data capture layer (that lives on the pumper’s phone). It is the iron and the wiring at the well.
Wellsite automation covers five things: equipment-level controllers (POCs, plunger lifts, VSDs), safety shut-ins (high-level tank switches, pressure relief), instrumentation (tank level sensors, flow meters, pressure transmitters), RTUs or PLCs that coordinate local logic, and local HMI screens that let a pumper or technician interact with the controls on site. Above all of that is SCADA, but SCADA is not technically wellsite: it is field-level.
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 in the Permian 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
For a smaller operator or contract pumper, 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. 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 exactly that operational layer: particularly for contract pumpers who run across multiple operators and need a unified workflow regardless of what automation exists on each site.
TinyPumper captures pumper visits: gauges, run tickets, observations: so the operational data chain keeps up with the wellsite automation.
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.
Wrong Fit for This Page
If you are a major horizontal operator with a full automation program already in place, 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 smaller operators, independents, and contract pumpers who need to understand what fits on the pad and where to sequence the spend.
FAQ
Is TinyPumper classified as wellsite automation?
Workflow automation, yes. Hardware automation, no. TinyPumper automates the data capture and reporting loop without automating the equipment itself. For most stripper operators, that’s the ROI-positive slice of wellsite automation.
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. Low-rate stripper wells often get by with a POC and a tank shut-in. Higher-rate wells, gas wells with loading issues, and regulated sites typically justify more extensive automation.
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 is the version that arrives as an app on your pumper's phone. Because on a 15-BPD stripper, the question isn't 'how automated can we make it?' It's 'how cleanly can the pumper tell us what's happening?'
See how TinyPumper works →