Capture field data once. Put it to work everywhere else.
Oklahoma was the sixth-largest producer of both crude oil and marketed natural gas in 2024, according to the U.S. Energy Information Administration. The work spans the Anadarko Basin, SCOOP, STACK, and Woodford plays, often across lean field and office teams.
But much of the operational work that keeps wells producing still depends on manual processes. Pumpers drive routes filling out daily gauge reports by hand. Safety compliance documentation lives in filing cabinets or scattered spreadsheets. Equipment failures surface as emergency calls instead of planned maintenance events. Production engineers spend hours building reports from data that should assemble itself.
Much of the data already exists in SCADA systems, production databases, and field reports. The opportunity is to connect that information, reduce duplicate reporting, and surface changes for the right person to review.
Oklahoma field conditions and regulatory context shape the local work. Remote projects focus on reporting, dashboards, and integration, with state-specific requirements scoped separately.
Start with the field report everyone touches.
Reporting, equipment review, production comparisons, and contractor coordination can share the same approved operational data without making the field team rebuild it each time.
Field Reporting Automation
Pumpers and field operators capture daily reports from voice memos and phone photos instead of filling out paper forms at the end of a 12-hour day. AI structures the data, populates production volumes, flags anomalies, and files the report into your operations system.
Operator impact
Field crews spend less time on paperwork and more time on the wells that need attention.
Equipment Monitoring & Predictive Maintenance
Monitoring rules and models compare runtime data from pumping units, compressors, and tank batteries against an established baseline. Vibration changes, pressure drift, and temperature trends are routed to qualified personnel for review.
Operator impact
Earlier visibility into equipment behavior that deserves an operator's attention.
Safety Compliance & Documentation
Operational data can pre-fill approved forms and flag overdue inspections, training renewals, and permit dates. Staff review the record before it is filed or used for an operational decision.
Operator impact
Documentation is easier to review without shifting responsibility away from the operator.
Production Data Analysis
Well-performance dashboards combine approved SCADA and production-accounting data. The workflow identifies decline-curve deviations, compares offsetting performance, and surfaces wells for engineer review.
Operator impact
Production engineers spend less time building reports and more time making optimization decisions.
Subcontractor Coordination
Automated scheduling for roustabout crews, hot oil trucks, wireline operators, and other field services. The system tracks certification status, safety training records, and insurance expiration dates. When a contractor falls off the approved list, the scheduler flags it before they show up on location.
Operator impact
Fewer scheduling gaps, fewer compliance surprises, and less time spent chasing confirmations by phone.
Anonymized client record
A 75-well Oklahoma operator, measured over 90 days.
Voice-to-report automation, production comparisons, and equipment alerts went live in a 60-day rollout.
Where time and visibility were getting lost
The operator ran 75 wells across three counties with one office manager, two pumpers, and an owner handling engineering and business decisions. Pumpers spent two hours a day on paperwork, equipment problems often surfaced after production changed, and required records were scattered across binders and spreadsheets.
Before
- Pumpers averaged 2 hours/day on handwritten gauge reports and driving to the office to file them
- Equipment failures discovered reactively, costing $5K-$15K per emergency repair call
- OSHA and OCC compliance docs maintained in binders, updated quarterly at best
- Owner spent 5+ hours/week manually comparing production against decline forecasts
After 90 days
- Voice-to-report automation cut daily field reporting time by 75%
- Predictive alerts flagged three rod pump failures before they caused downtime
- Approved forms were pre-filled from operational data and organized for staff review
- Automated production dashboards replaced the weekly manual comparison while engineering interpretation stayed with the owner
How it rolled out
Field reporting came first using the phones and operational data already in place. Pumpers captured voice notes and photos, and the workflow structured them into daily report drafts. In week 3, the same data began filling client-approved OSHA and OCC templates for staff review. Equipment monitoring followed in month 2 after the SCADA connection and baseline operating patterns were approved. All three workflows were live within 60 days.
Oil & Gas AI FAQ
Do we need to install new sensors or equipment?
Not necessarily. Most operators already generate the data AI needs through SCADA systems, tank gauging, and production accounting software. We start by connecting to your existing data sources. If there are gaps where sensor data would add value, such as vibration monitoring on rod pumps, we recommend specific upgrades as a second phase after the initial workflows are running and delivering ROI.
How does this work with our existing production accounting software?
We integrate with the tools you already use. Whether that is WolfePak, Enertia, OGsys, P2 Merrick, or even spreadsheets, AI layers on top of your current stack. During the assessment phase, we map your data flows and confirm compatibility. The goal is to make your existing systems smarter, not replace them.
How is our production data handled?
The project scope identifies where production data remains, which approved systems can access it, and how long operational copies or logs are retained. We use the client's approved infrastructure and document permissions, connection methods, retention, and logging before the workflow goes live.
What size operator is this designed for?
We work with operators running 20 to 500 wells. Smaller operators (20-100 wells) typically start with field reporting automation and compliance tracking where manual work consumes disproportionate time. Larger operators (100-500 wells) get more value from predictive maintenance and production optimization at scale. The assessment phase identifies which workflows deliver the most impact for your specific operation.
How long before we see results?
A field-reporting workflow can often be scoped for the first 30 days because it uses a process crews already follow. Equipment anomaly work takes longer because it needs a reliable data history and a baseline that qualified personnel approve. Multi-workflow timing is set after the assessment, once data access and system compatibility are clear.