# Greasebook — Full Content Dump Generated: 2026-08-31T14:47:01Z Source: https://www.greasebook.com This file concatenates the canonical pillar guides in raw markdown for LLM ingestion. For a concise index see llms.txt. ===================================================================== # Oil and Gas Software: The Complete Guide for Independent Operators (2026) > Every category of oil and gas software explained (production, accounting, allocation, data management, monitoring, and automation) with honest guidance on what small and mid-sized operators actually need. Source: https://www.greasebook.com/blog/oil-and-gas-software/ Published: 2026-04-18 --- Your back office is re-keying paper gauge sheets into Excel at 9 p.m. again. Your engineer is pulling production numbers out of three different systems to model one acquisition. Your pumper forgot which tank fed which well and nobody can tell from the software. That is the mess this market is supposed to solve, and most of the products sold into it make the mess worse. Oil and gas software covers eight meaningful categories: production capture, production accounting, production allocation, land management, production data management, oilfield monitoring, SCADA, and oilfield automation. Most independents (operators running a handful of wells up to 2,000+ in Texas, Oklahoma, North Dakota, California, Pennsylvania, or anywhere else oil and gas gets produced) only need two or three of them. The rest are for a different kind of company. **This post is for you if:** - You run anywhere from a handful of wells to 2,000+ and the software market is flooding you with options built for a company ten times your size. - You want a plain-English map of what each category of oil and gas software actually does so you can rule most of them out before the demo calls start. - You know your production data is more than 48 hours behind reality and you want the honest read on where to start fixing it. - You have outside working interest partners, royalty owners, or multi-state tax exposure and you are not sure whether you need new software or a better CPA. If you want a vendor brochure, close the tab. If you want the straight version, keep reading.

## The Eight Categories of Oil and Gas Software Every product in this market fits one of eight categories. Some tools blur two categories. Very few honestly cover three or more, regardless of what the sales deck says. | Category | What It Does | Who Typically Needs It | |---|---|---| | **Production software** | Captures daily well production (oil, gas, water) from pumpers in the field and turns it into reports, dashboards, and historical trends. | Every producer with wells that report daily or monthly volumes. The foundational layer. | | **Production allocation software** | Splits commingled or multi-well production into per-well, per-lease, and per-owner volumes. Two jobs: revenue distribution, and knowing which well is actually pulling its weight on a shared tank battery. | Any operator with two or more wells feeding a common tank battery (even 100%-operated), plus operators with multiple owners per lease or complex working interest structures. | | **Oil and gas accounting software** | Joint interest billing, revenue distribution, AFE tracking, severance tax, 1099 reporting. A different discipline from production. | Any operator with outside working interest partners, royalty owners, or multi-state tax exposure. | | **Land management software** | Lease records, mineral rights, rentals, HBP tracking, landman workflow. | Operators acquiring leases, managing large acreage portfolios, or running an active leasing program. | | **Production data management software** | Long-term storage, cleanup, and analysis of historical production data for decline curve work, reserves estimation, and forecasting. | Operators with 50+ wells, reservoir engineers, or anyone doing economic modeling on production history. | | **Oilfield monitoring software** | Real-time or near-real-time sensor data from tanks, wells, and facilities. Often paired with hardware (RTUs, cellular modems, tank level sensors). | Operators with remote leases, long pumper drive times, or theft/leak exposure. Adjacent to SCADA. | | **SCADA software** | Supervisory control and data acquisition. Industrial-grade monitoring and control systems, usually tied to PLCs and purpose-built field networks. | Large operators with dedicated controls staff, pipeline operators, or complex gas-gathering systems. | | **Oilfield automation** | Pump-off controllers, wellsite automation, gas-lift optimization. Usually a hardware-plus-software stack attached to a well or lease. | Operators trying to reduce pumper labor cost, extend pump run-life, or optimize artificial lift. | Two categories sit near the center of most independent operations: **production software** and **production accounting software**. Almost everything else is either a specialized layer on top of these or a different discipline entirely. ## Which Categories Do Independent Operators Actually Need? The honest answer depends on two things: how many wells you operate, and whether you have outside partners and royalty owners. That's it. Those two variables determine 80% of what software you need. ### If you operate fewer than 25 wells with no outside partners You need **production software** first and foremost. For books, QuickBooks plus a CPA who knows oil and gas is a stopgap at this size, and it stops being enough the minute outside working interest partners, JIB, royalty owners, or multi-state tax enter the picture. At that point purpose-built O&G accounting (mid-range: OGsys, Wolfpak, Bolo, SSI, Pac Energy) is the expected companion. Your leases can live in a binder or a spreadsheet without anyone getting hurt. That is the honest floor. Allocation is where the "you do not need it" advice breaks down. If every well flows to its own dedicated stock tank, you are right (the tank reading is the well production and there is nothing to split). But most leases are not built that way. Two or three wells feeding a common tank battery is the norm on old-field leases, and even when you own 100% of every barrel, you still want to know which well is making the oil. That is how you catch the well that has been loafing for the last three months while the good wells carried the battery. For a small operation, a monthly well test pushed into a clean spreadsheet gets you 90% of the benefit. The point is not "you never need allocation." It is "you may not need allocation software yet." The mistake most small operators make is buying software for the company they wish they were running, not the company they actually run. A 12-well operator does not need an enterprise platform. They need to know what their wells produced yesterday, which ones are down, which ones are underperforming on a shared battery, and what the trends look like over the last 90 days. ### If you operate 25 to 250 wells, some with outside partners You need **production software**, **production accounting software**, and probably **production allocation software**. You may also benefit from **production data management software** if you are making acquisition decisions, running decline curves, or presenting reserve estimates to lenders. Monitoring and SCADA become a question of geography, not well count. If your leases are spread across three counties and your pumpers are driving two hours to gauge a tank, monitoring hardware pays for itself quickly. If your wells are clustered, you probably do not need it. ### If you operate 250+ wells or run a gas-gathering operation You are operating at enterprise scale whether you think of yourself that way or not. You likely need most of the categories on the list, and you may need industrial SCADA systems that are outside the scope of this guide entirely. At this size, the question is not "which category?" but "which vendor within the category, and how do they integrate?" ## Production Software: The Foundation If you buy one piece of oil and gas software, buy production software. Every other category assumes you already have clean, timely production data. Without that, allocation is wrong, accounting is wrong, reserve reports are wrong, and decisions made against any of those numbers are wrong. The core job of production software is simple: get oil, gas, and water volumes out of the field and into a system that the back office can trust. Every category of production software approaches this differently. - **Mobile-first production apps** (like GreaseBook) have pumpers enter data on a phone or tablet at the lease, sync over cellular, and push to a cloud dashboard in minutes. This is the dominant pattern for independent operators in North America today. - **Desktop-based production systems** (older platforms) rely on pumpers writing on paper gauge sheets, driving to an office, and re-entering data into a Windows application. Still used in shops that have not modernized their field workflow. - **SCADA-derived production** pulls data from tank level sensors and flow computers automatically. Technically capable but operationally fragile. Sensors drift, cellular goes down, and somebody still has to reconcile the numbers. The deeper question for independent operators is not which platform, but how much friction you are willing to put on your pumpers. A pumper in west Texas who has to write on paper, drive 40 miles to the office, and re-key data has roughly 30 extra minutes of admin per day. Across an army of five pumpers over a year, that's 750 hours of windshield time and keystrokes, and it is not free. Read more: [the complete guide to oil and gas production software](/blog/oil-and-gas-production-software/). ## Production Allocation vs. Production Accounting These two categories get confused constantly. They are not the same thing. **Production allocation** takes a commingled volume (say, 180 barrels of oil came out of a tank this month fed by four wells on three leases with two different working interest groups) and splits it into per-well, per-lease, and per-owner volumes using allocation factors (test results, meter readings, decline curves). The output is a clean per-well, per-interest volume that accounting can then run revenue against. **Production accounting** takes the allocated volumes and handles the money: joint interest billing (JIB) to partners, revenue distribution to royalty owners, severance taxes, 1099 reporting, AFE tracking. This is a full accounting function, and it is usually handled by a production accountant using purpose-built software. If you have commingled wells or multiple owners, you need both. If every one of your wells flows to its own dedicated stock tank (one well, one tank) you do not need allocation software (the tank reading is the well). But two or more wells feeding a shared tank battery is the norm on old-field leases, and even when you own 100% of every barrel you still want to allocate so you know which well is pulling its weight and which one is quietly loafing. For simple cases, a spreadsheet built around your monthly well tests handles it. Allocation software earns its keep when the number of wells, the number of tank batteries, or the number of owners makes that spreadsheet fragile. Read more: [oil and gas production allocation software](/blog/oil-and-gas-production-allocation-software/) and [oil and gas accounting software: when you actually need it](/blog/oil-and-gas-accounting-software/). ## Data Management, Monitoring, and Automation The last three categories are layers on top of production, not replacements for it. **Production data management software** is built for one job: turn historical production data into forecasts. Decline curve analysis, type curves, reserve reports, acquisition modeling. Tools in this category include OFM (the long-time standard), newer cloud platforms, and custom solutions. You need it if you are presenting reserves to a lender, evaluating an acquisition, or running a forecasting function for more than 50 wells. **Oilfield monitoring software** is about real-time or near-real-time field visibility. Tank levels, compressor runtime, pump status, H2S alarms, intrusion detection. This category sits between simple production capture (once a day) and full SCADA (continuous supervisory control). Most independent operators who adopt monitoring do it for one of three reasons: reduce pumper windshield time, catch tank overflow or theft before it matters, or monitor a handful of remote wells without hiring another pumper. **Oilfield automation** is hardware with software bolted on. Pump-off controllers (POCs) that cycle a rod pump based on fluid level, gas-lift optimization systems, wellsite automation platforms that integrate multiple pieces of equipment. The ROI is usually labor and run-life, not production lift. If your operation is dominated by rod-lifted stripper wells and your pumpers are visiting each well daily, automation can cut that cadence in half. Read more: [oilfield monitoring software](/blog/oilfield-monitoring-software/) and [oil and gas automation: a field guide](/blog/oilfield-automation/). ## The Adjacent Categories Most Independents Skip Two categories get listed in every "oil and gas software" article but rarely apply to independent operators. **Land management software** (platforms like Quorum Land, Land Manager, and several others) is built for active leasing programs, large acreage portfolios, and landman-heavy operations. If you acquired your leases a decade ago and are holding them by production, you do not need this software. A spreadsheet and a filing cabinet will do the job indefinitely. **Enterprise ERP systems** (SAP is ludicrous-tier for almost any producer; next-tier P2, Quorum, and W Energy are built for operators in the 1,000 to 10,000 well range with dedicated IT) are financial planning and operations suites built for majors and large independents. If you are running a purpose-built mid-range O&G accounting platform (OGsys, Wolfpak, Bolo, SSI, or Pac Energy) alongside a production app, you are better served than most shops that bought next-tier ERP and use 12% of it. Read more: [oil and gas land management software vs production software: what the difference actually is](/blog/oil-and-gas-land-management-software/). ## What to Buy First If you are starting from scratch, the order is simple. 1. **Production software**: this is the foundation. Nothing else works without clean production data. 2. **Production accounting software**: only if you have outside partners, royalty owners, or multi-state tax exposure. Otherwise, QuickBooks plus a good CPA is enough. 3. **Production allocation software**: valuable any time multiple wells feed a common tank battery, both for revenue splitting (when there are partners or multiple leases) and for knowing which well is actually pulling its weight. A spreadsheet handles simple cases. Dedicated software earns its keep when the combinatorics get ugly: multiple batteries, varying ownership, and monthly well tests you need to trust. 4. **Production data management software**: only if you are making forecasting or acquisition decisions regularly. 5. **Monitoring, SCADA, and automation**: only when the labor math or the theft math or the reliability math actually supports the investment. Do not buy hardware because it is cool. Buy it because a spreadsheet says it will pay for itself inside 24 months. ## Amateur vs Pro: How Operators Buy Oil and Gas Software | The amateur... | The pro... | |----------------|------------| | Buys a single all-in-one platform because one vendor sold him "the whole stack" | Picks the best-fit tool in each category and integrates them (production app + purpose-built accounting + allocation) | | Treats the accounting vendor's bolt-on production module as the production system | Runs a dedicated production app and feeds clean data into whatever accounting platform the back office already pays for | | Signs a 3-year contract after a 45-minute demo | Runs a 30-day pumper trial on real wells before signing anything past 12 months | | Buys monitoring hardware because it looked slick at NAPE | Buys monitoring hardware only when the labor, theft, or reliability math says it pays back inside 24 months | | Keeps QuickBooks running after working-interest partners and JIB show up | Moves to purpose-built O&G accounting the minute complexity arrives, and never looks back | The best operators we see do not win by owning the fanciest stack. They win by picking the right layer for the right job, then integrating them properly. ## What To Avoid Before You Sign Anything - **Don't fall into the Bolt-On Trap.** Treating an accounting vendor's production module (whatever mid-range platform your back office runs: OGsys, Wolfpak, Bolo, SSI, Pac Energy) as a substitute for a purpose-built production system is how clean field data dies. Those modules are built for the accounting workflow, not for a pumper in a truck at 5 a.m. - **Don't rely on the QuickBooks Stopgap past its fit.** QuickBooks plus a CPA works below the complexity line. The minute working-interest partners, JIB, royalty owners, or multi-state tax show up, you need real oil and gas accounting software. Pretending otherwise is how audits and missed JIB entries happen. - **Don't let the Paper Lag decide your next move.** If your production data is 2 to 3 weeks late because pumpers are still writing on paper, the answer is not "better reports from the accounting suite." The answer is getting the capture layer off paper first. - **Don't buy for the company you wish you were running.** A 40-well operator does not need an enterprise land management suite. A 400-well operator does not need an SAP implementation (SAP is ludicrous-tier for almost any producer). Size the software to the operation you actually run. - **Don't skip the pumper trial.** Any vendor that won't let your pumpers beat on the product for 30 days on real wells is hiding something. That goes double for a three-year contract. ## Who This Guide Is Not For If you are a reservoir engineer at a major running petrophysical models on 3D seismic, this guide is not for you. If you are a pipeline operator with hundreds of miles of gathering lines and custody transfer meters, SCADA is your world and this guide barely touches it. If you are a consulting firm selling implementations, you already know all of this. This guide is for small and mid-size independent operators running a handful of wells up to 2,000+, trying to make honest software decisions without being sold a platform that does not fit their operation. If that describes you, the rest of this site is written the same way.

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

Two minutes. No sales call, no pushy follow-up. If GreaseBook lands and the fit turns out wrong inside year one, the 200% money-back guarantee refunds you twice the contract price. That is how confident we are in the pumper-adoption bar. **P.S.** This page is not for a supermajor or an enterprise operator shopping for SAP IS-Oil. No hard feelings. If you are still deciding, the quiz gives you a straight answer in the time it takes to refill your coffee. ## Background reading: how this shop talks about the operator's job Software is downstream of how you think about running wells. If you want to know why GreaseBook is designed the way it is, these are the old-but-still-true pieces that explain the philosophy. - [The bill of rights for oil production software](/blog/bill-or-rights-oil-production-software/): what an operator should demand - [How to make a dime go a hundred in the oilfield](/blog/how-to-make-a-dime-go-one-hundred-in-the-oilfield/): where capital actually earns its return - [The rule of 3 and 10 for production optimization](/blog/rule-of-3-and-10-oil-production-optimization/): a heuristic pumpers still use - [The war against production reporting software that sucks](/blog/war-against-oil-production-reporting-software-that-sucks/): why the category needed a rewrite - [What a wellhead pumper actually makes](/blog/wellhead-pumper-salary/): the economics of the person your software depends on - [The secret to more wells per pumper](/blog/oil-field-pumper-jobs-secret-to-more-wells/): where the operational leverage hides ## Frequently Asked Questions **What is the best oil and gas software for small operators?** For operators running a handful of wells up to 2,000+, the combination that works for most is a mobile production capture app (GreaseBook or equivalent) plus a purpose-built O&G accounting platform sized to the operation (mid-range: OGsys, Wolfpak, Bolo, SSI, Pac Energy). QuickBooks plus a CPA is a stopgap only at the smallest end before working interest partners, JIB, royalty owners, or multi-state tax show up. Anything more than that tends to create more operational overhead than it saves. **Is there free oil and gas software?** Free tools exist for specific jobs (spreadsheet templates for production tracking, open-source decline curve libraries, free trials of most commercial platforms) but the production category has no serious free option for a real operation. The reason is field support and data integrity. Free software does not come with someone who answers the phone when a pumper cannot sync. **Do I need production software, accounting software, or both?** Both, if you have outside partners or royalty owners. Just production, if you are a solo operator with simple ownership structures. Production software captures what came out of the ground. Accounting software handles the money that resulted. They solve different problems. **What's the difference between SCADA and monitoring software?** SCADA (supervisory control and data acquisition) is an industrial-grade system that both monitors and controls field equipment, typically through dedicated hardware and purpose-built networks. Monitoring software is usually a lighter layer. It sees what is happening but does not automatically control equipment. Most independent operators need monitoring, not full SCADA. ===================================================================== # Oil and Gas Production Software: What Independent Operators Actually Need (2026) > Oil and gas production software explained for operators with 5 to 500 wells. What it does, what it costs, how it compares to spreadsheets and enterprise tools, and the honest answer on who needs what. Source: https://www.greasebook.com/blog/oil-and-gas-production-software/ Published: 2026-04-18 --- Your pumper scribbled gauges on a greasy sheet Tuesday. It got mailed in Friday. Admin re-keyed it Monday. By the time you look at the numbers, the well that died last week has been dead for nine days. That gap (two to three weeks behind reality, on a business where the revenue check is the score) is the problem oil and gas production software is supposed to solve, and most of the products sold into this market make it worse before they make it better. Oil and gas production software captures daily well production volumes from the field, turns those volumes into reports, and feeds every downstream system (allocation, accounting, regulatory filings) that depends on accurate numbers. For independents (a handful of wells up to 2,000+), it is the foundational layer. If it breaks, everything else breaks with it. **This post is for you if:** - Your production data is running more than 48 hours behind reality and you want to know what it costs to close that gap. - You run anywhere from 15 wells to 2,000+ and you are stuck between "Excel is held together with tape" and "the enterprise suite wants $300k." - Your back office is re-keying paper gauge sheets into spreadsheets at 9 p.m. and you are tired of paying for that twice. - You want the honest read on mobile capture tools, spreadsheets, and enterprise suites before you sit through another 45-minute demo. If you want a sales pitch, close the tab. If you want the straight version from people who talk to independent operators for a living, keep reading.

## What Oil and Gas Production Software Does Production software sits between three groups of people who rarely talk to each other in plain English: pumpers in the field, admin in the office, and engineers or owners looking at the numbers. The job of the software is to make those three groups agree on what happened yesterday and let each of them see the piece they need. The core workflow looks the same across every real product in this category. 1. A pumper visits a well or battery and records production volumes (oil, water, gas), tank gauges, run tickets, injection volumes, chokes, pressures, downtime, and any notes worth keeping. 2. That data moves from the field to a central system. In a modern tool this is a phone or tablet syncing over cellular. In a legacy setup it is paper gauge sheets faxed, mailed, or hand-delivered to the office. 3. Admin or the office reconciles the field data against run tickets, tank strappings, and sales nominations. 4. The software emits whatever the business needs next: daily production reports, monthly state filings (TX RRC PR, OK OCC 300R, and similar), allocation splits, revenue decks, decline curves, engineering dashboards. Anything a production software vendor sells you that is not part of that loop is either a feature for a different category (accounting, SCADA, data management) or a nice-to-have. Evaluate based on the core loop first, then decide if the extras matter. For a full map of how production software relates to adjacent categories like accounting and allocation, see the [oil and gas software]({{ site.baseurl }}/blog/oil-and-gas-software/) overview. ## The Three Real Categories Operators End Up Choosing Between The market has hundreds of products. The honest picture is that they fall into three camps. You will end up in one of these regardless of what the sales rep calls it. ### Category 1: Spreadsheets (and paper) Most small operators start here and many stay longer than they should. Pumpers call or text in numbers, a relative of the owner types them into Excel, someone prints the monthly and signs the state form by hand. **It works when:** you run 1 to 10 wells, you know every pumper by their truck, your reporting obligations are simple, and nothing gets lost because only a handful of people touch the file. **It breaks when:** you grow past roughly 15 to 25 wells, hire a second or third pumper, start taking on non-operated interests, need to split production across owners, or miss a state filing because someone was on vacation. The failure is never one catastrophic event. It is a slow erosion where errors compound until you realize the numbers you trusted for three years were wrong by several hundred barrels a month. ### Category 2: Mobile production software (field-data-capture tools) This is the category where GreaseBook lives. A pumper opens an app on their phone or tablet, records well data as they gauge, and the office sees it within minutes. The data flows into reports, allocation, and state filings without being re-typed. **It works when:** you run roughly 5 to 1,000 wells, you have at least one pumper (contract or employee), your wells are conventional (rod pump, ESP, plunger, gas lift, injection), and you want the office to see production in near-real-time without building your own data pipeline. **It breaks when:** your wells are predominantly high-volume horizontals with real-time SCADA already in place, your company runs on enterprise ERP suites that demand native integration (SAP, Oracle Oil and Gas, Quorum), or your pumpers refuse to touch a phone. The last one is less common every year, but it is still real. ### Category 3: Enterprise production suites Pak Energy (formerly WolfePak), Peloton, Enertia, Quorum, and a handful of others sit at the top of the market. These are platforms that bundle production, accounting, land, and sometimes reserves and regulatory into one stack. They are serious tools built for serious budgets. **It works when:** you have 1,000+ wells, a dedicated IT department, a controller who wants one vendor to call for everything, and six figures a year of budget earmarked for software plus implementation plus training. **It breaks when:** you are a small or mid-size independent (anywhere from a handful of wells to a few hundred) who was sold the enterprise dream by a good salesperson. The implementation takes 9 to 18 months, the annual cost is a meaningful percentage of your revenue, and 80 percent of the features sit unused because your operation does not have the people or the scale to use them. Every year the upper-mid independent market reads the same story: company buys the big suite, company eventually migrates back down to a tool that fits. For a deeper look at how operators actually rank the tools in category 2 and 3, see our [best oil and gas production software]({{ site.baseurl }}/blog/best-oil-and-gas-production-software/) breakdown. If budget is the blocker and you want to know what free or low-cost options actually exist, read [oil and gas production software free]({{ site.baseurl }}/blog/oil-and-gas-production-software-free/). ## What Production Software Actually Costs Pricing in this category is genuinely opaque because most vendors refuse to publish numbers. Here is the honest range based on what operators report. | Tier | Typical cost | What you get | |---|---|---| | Spreadsheets | $0 plus your time | Excel, paper, a shared drive, and the assumption that nothing important breaks | | Mobile production software | $15 to $40 per well per month, all in | Pumper app, office dashboard, core reports, state filing prep, basic allocation, support that actually answers the phone | | Mid-market suites | $50 to $200 per well per month, plus $10k to $50k implementation | Production plus allocation plus accounting plus land, custom integrations, user training included | | Enterprise suites | $200+ per well per month, plus $100k to $500k+ implementation | Everything above plus custom workflows, dedicated account team, multi-year contracts | A mid-size independent (say 50 wells) paying $25 per well per month for mobile production software spends $15,000 a year. The same operator looking at an enterprise suite is quoted $300,000 to $600,000 all-in for the first three years. The math decides the category for most independents before any feature comparison happens.

## What to Look For If You Are Buying Most of the evaluation checklists floating around the internet were written by vendors to win RFPs. The operator-side checklist is shorter and more honest. **1. Can a pumper who has never used your software before be productive in under 10 minutes?** If the answer is "we have a great 3-day training program," that is a red flag. Real pumpers have three wells to get to and no patience for software that fights them. The tools that win in the field are the ones that work like a phone, not like a SAP module. **2. What happens when cell service drops?** Any honest vendor will tell you the app has to work offline, queue the data locally, and sync the second signal comes back. If the demo only runs in a boardroom with wi-fi, ask how it behaves at a battery with no bars. You will spend half your field time in dead zones and you cannot afford to lose numbers. **3. How fast does the office see field data?** The whole point of mobile production software is that office and field stop being on a two-day lag. If the data shows up in the office the next morning instead of in real time, you bought something that is closer to a paper replacement than a production system. That may still be fine, but price it accordingly. **4. Who do you call when something breaks at 6:30 AM on a Tuesday?** Production software is operational infrastructure. If the vendor's support is email-only or routes through three tiers before a human answers, that is a problem when a pumper cannot log in at shift change. Ask for the actual phone number of the support line and call it during the demo. **5. What does it cost to leave?** Ask explicitly: if I decide to migrate in 18 months, what does my data look like on the way out? Operators who cannot answer this question discover at the wrong moment that their three years of production history is locked inside a proprietary format. ## Amateur vs Pro: How Operators Buy Production Software | The amateur... | The pro... | |----------------|------------| | Picks the platform the sales rep pushed hardest in the boardroom demo | Runs a 30-day pumper trial on real wells, in real cell dead zones, before signing anything | | Treats the accounting vendor's production module as the production system | Runs a dedicated production app and integrates it with whatever accounting platform the back office already pays for | | Signs a 3-year contract to get the "best price" | Won't sign past 12 months without a field-tested track record | | Stays on spreadsheets three years past the breaking point because "we'll migrate later" | Migrates the week the second pumper is hired and the error rate starts climbing | | Assumes SCADA on the best wells means the rest of the wells are covered | Plugs SCADA-sourced data and pumper-entered data into one production layer so office and field see the same numbers | The best operators we see do not win by owning the fanciest platform. They win by picking a tool that pumpers will actually open on the second Tuesday of March, then integrating it cleanly with the accounting suite. ## What To Avoid Before You Buy - **Don't fall into the Bolt-On Trap.** Whatever accounting platform your back office runs (OGsys, Wolfpak, Bolo, SSI, Pac Energy on the mid-range tier, or P2, Quorum, W Energy at the next level up), the production module bolted on to it is jack of all trades, master of none. It was built for the accounting workflow, not for a pumper in a truck at 5 a.m. Run a dedicated production app and feed clean data into the accounting suite you already run. - **Don't let the Paper Lag decide your pricing.** A vendor quoting enterprise prices to replace paper gauge sheets is selling overhead, not a solution. The math for mobile production software on an independent operation lands in the $15 to $40 per well per month range. Anyone much higher than that is selling the wrong tier. - **Don't pick on price alone.** A production app that loses two run tickets a month costs more than the one twice the price that doesn't. Cheap that fails in a cell dead zone is the most expensive kind of cheap. - **Don't skip offline mode.** Any vendor whose demo only runs on boardroom wi-fi is hiding what happens at a battery with no bars. Offline capture with auto-sync is a requirement, not a feature. - **Don't buy for the company you wish you were.** A 50-well independent does not need the platform built for 5,000-well majors. Size the software to the operation you actually run. ## Who This Guide Is Not For This page is written for independent and mid-sized operators running conventional wells. It is not the right guide for everyone. **Pure data-engineering shops** whose bottleneck is already wrangling historian data from thousands of continuous SCADA tags should be looking at [production data management software]({{ site.baseurl }}/blog/oil-and-gas-production-data-management-software/) and historian tools as their primary investment, with mobile production software layered on top to catch the human-verified side (run tickets, tank gauges, downtime notes) that SCADA cannot see. Horizontal shops that run SCADA on their top producers still plug GreaseBook in as the centralized production layer. That combination is common. **Heavy SCADA environments** where automation and remote monitoring already cover your top producing wells should evaluate this category as a complement to SCADA, not a replacement. Mobile production software captures the human-verified side of operations (run tickets, tank gauges, maintenance notes) that SCADA still cannot see. **Enterprise ERP shops** already standardized on SAP, Oracle, or Quorum should evaluate production tools inside that ecosystem first. The integration cost of bolting on a non-native tool usually outweighs the feature gap. **Pure royalty owners and non-operators** do not need production software. You need allocation reports from your operator and a way to read them, which is closer to [production allocation software]({{ site.baseurl }}/blog/oil-and-gas-production-allocation-software/). ## How Production Software Fits Into the Rest of the Stack Production software is the front door to every other data-driven decision in your operation. What it feeds: - **Allocation**: daily per-well volumes are the input to commingled allocation and revenue splits. See [production allocation software]({{ site.baseurl }}/blog/oil-and-gas-production-allocation-software/) for the downstream piece. - **Accounting**: volumes times prices equals revenue. Bad volumes equal bad revenue. Accounting software is only as honest as the production numbers feeding it. - **Regulatory filings**: monthly state forms (TX RRC PR, OK OCC Form 300R, ND NDIC Form 5, and similar) are built directly from production volumes. See [oil and gas regulatory production reports]({{ site.baseurl }}/blog/oil-and-gas-regulatory-production-reports/) for the state-by-state map. - **Engineering**: decline curves, type curves, and forecasting all start from a clean production history. Garbage in, garbage out. - **Data management**: if you run enough wells, you eventually want a historian or a warehouse. See [production data management software]({{ site.baseurl }}/blog/oil-and-gas-production-data-management-software/) for what that looks like. The pattern: production software is the layer everything else reads from. Get it right first, then worry about the rest. ## Field-side guides that teach the numbers your software captures Production software is only as honest as the data the pumper writes into it. These guides cover what that data actually describes at the tank battery. - [Gauging equipment every pumper should know](/blog/gauging-equipment/): strap tapes, thief hatches, and what the numbers actually mean - [Operating and servicing pumping units](/blog/operating-servicing-pumping-units/): the conventional beam unit from a pumper's seat - [Lease pumper's basic guide to plunger lifts](/blog/lease-pumpers-basic-guide-plunger-lifts/): when and how plungers go in - [Separators, heater-treaters, and pressure](/blog/separators-heater-treaters-pressure/): what is happening inside the vessels your production runs through - [Servicing an oil and gas production well](/blog/servicing-oil-gas-production-well/): workover basics, from a pumper's vantage - [Tubing string basics and maintenance](/blog/tubing-string-basics-maintenance/): the string that carries everything up - [Manually starting an old Arrow C96 pumping unit](/blog/greener-pastures-and-manually-starting-an-old-arrow-c96-pumping-unit/): the honest field story nobody else publishes - [The boiler-house method of pumper production reporting](/blog/pumper-production-reporting-boiler-house-method/): why fabricated numbers happen and how to stop rewarding them - [The lease pumper handbook](/blog/lease-pumper-handbook/): the full reference for the job your software depends on - [11 important things for oil field lease maintenance](/blog/11-important-things-oil-field-lease-maintenance/): what earns the right to be on the daily route ## Frequently Asked Questions ### Is Excel still a legitimate option for production tracking? Yes, for roughly 1 to 15 wells with a single pumper and a tolerant regulatory environment. The failure points are growth, turnover, and the month you hire your second pumper. Most operators stay in Excel three years longer than they should, then spend a painful quarter migrating out of it. ### How long does it take to roll out mobile production software? Honest range: 1 to 3 days for a small crew (a few pumpers, a few dozen to a couple hundred wells) with good cell coverage. Longer if you have complex allocation, multiple partners, or a pumper crew that rotates frequently. Any vendor quoting a 6-month implementation for a small operation is selling you enterprise overhead you do not need. ### Do I have to change how my pumpers work? The right mobile tool maps to how a pumper already works. Gauge the tank, note the run ticket, record the pressures, move to the next well. The change is replacing paper with a phone, not redesigning the field workflow. If your pumpers push back hard on a tool, it is usually the tool's fault, not the pumper's. ### What happens to my 10 years of Excel history when I switch? Real production vendors import historical volumes during onboarding. Ask for the import process in writing before signing anything. If the vendor cannot describe how your historical data arrives inside their system, that is a signal they expect you to type three years of history manually. ### Will production software file my state reports for me? It prepares the data in the format the state wants and often exports directly to the regulator's portal. The actual filing is still your responsibility, because regulators require an operator-of-record signature. The software eliminates the data wrangling, not the regulatory relationship.

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

## The Short Answer If you are running more than 15 wells and still on spreadsheets, you are paying in errors, re-work, and late reports what the software would cost you in dollars. If you are running fewer than 15 and the current system works, there is no urgency. If you are a small or mid-size independent looking at enterprise suites, stop, and look at mobile production software first. GreaseBook sits in category 2 and is designed for small and mid-size independents (anywhere from a handful of wells to 2,000+). It is not the right tool for a 10,000-well major or a company that has already standardized on an enterprise suite. For everyone else, it is worth a 10-minute look.

## What Allocation Software Actually Does The reason allocation exists is that meters and tanks do not care about lease lines or ownership structures. Five wells on the same lease can sell into a single tank battery. Three leases on different sections can share a gas sales meter. A non-op partner who owns 25 percent of two of those five wells still wants their 25 percent every month, to the barrel, with a clean audit trail. Allocation software handles that math. The core job breaks into three steps. **1. Capture the commingled total.** A run ticket, sales meter, or tank strap tells you the total volume that moved in a day or month. This number is the truth at the sales point. **2. Capture the per-well inputs.** Each well's individual production is measured upstream of the commingling point, usually by a pumper gauging a test separator, reading a well test, or (in more automated setups) pulling continuous SCADA data. **3. Back-allocate.** The software takes the commingled sales total and distributes it back to each well proportionally to that well's measured contribution. Then it applies ownership percentages to the per-well volumes and produces revenue-ready splits. That is the whole loop. Everything else is a feature layered on top: BS&W corrections, temperature adjustments, gas shrinkage factors, multi-product allocation (oil, gas, NGL, water), non-consent accounting, and the audit trail that lets a partner confirm the math. For a broader map of how allocation sits inside the overall software stack, see the [oil and gas software]({{ site.baseurl }}/blog/oil-and-gas-software/) overview. For the layer upstream of allocation, see [oil and gas production software]({{ site.baseurl }}/blog/oil-and-gas-production-software/). ## The Three Real Approaches Operators Use Allocation happens one of three ways in practice. The right choice depends on ownership complexity, commingling structure, and how often owners look over your shoulder. ### Approach 1: The spreadsheet allocation workbook A single Excel file with tabs for each lease, formulas that do the back-allocation, and one human (usually a controller or office manager) who understands the logic. Updated monthly. Printed, signed, filed. **It works when:** you have a handful of wells, simple ownership, no non-op partners, and the same person has been maintaining the file for years. **It breaks when:** that person leaves. Or you take on a non-op partner who wants the audit trail. Or you realize the BS&W correction on one lease has been wrong since 2019 and you owe a royalty owner four years of back payments. The spreadsheet approach fails quietly, which is what makes it dangerous. ### Approach 2: Allocation inside your production software Modern mobile production tools (GreaseBook and some of its peers) include allocation as a built-in module. Pumpers enter per-well volumes in the field, the software pulls in run ticket and sales data, and the allocation math happens without a separate workbook. Reports export directly to revenue decks and state filings. **It works when:** your allocation structure is common (commingled tanks with per-well gauging, standard working interest percentages, normal non-op partners) and your operation runs under 1,000 wells. The vast majority of independents fit here. **It breaks when:** you have genuinely complex allocation: multi-phase allocation with SCADA-driven continuous measurement, offshore or unit-ized fields, complex non-consent accounting, or a joint venture structure with nested ownership. Built-in allocation is right-sized for typical onshore independents, not for the edge cases. ### Approach 3: Dedicated allocation and revenue suites Pak Energy, Quorum, P2 Energy Solutions (now Enverus), and a few others sell standalone allocation and revenue platforms. These are serious tools with serious pricing. **It works when:** you have 1,000+ wells, complex allocation structures, a dedicated accounting team, and the budget to pay $50k to $500k+ for implementation plus six-figure annual licensing. **It breaks when:** a 75-well independent gets sold the enterprise dream, the implementation stalls for a year, and the controller quits because the system is so complex nobody on the team can actually run it. If you are reading this page, you are almost certainly not the target customer for this tier. For operators weighing the options head-to-head, see [best oil and gas production allocation software]({{ site.baseurl }}/blog/best-oil-and-gas-production-allocation-software/). For the downstream step (how allocation feeds revenue distribution), see [production allocation and revenue distribution]({{ site.baseurl }}/blog/production-allocation-and-revenue-distribution/). ## What Goes Wrong With Allocation (And Why Partners Ask) Allocation sits quietly in the background until something makes a partner, a royalty owner, or a state auditor start asking questions. When they do, the problems tend to cluster in the same places. **Well test cadence drift.** Most allocation math assumes recent well tests. If tests happen quarterly instead of monthly, or if a high-performing well has not been tested in six months, the allocation factor is wrong and everyone downstream gets paid the wrong amount. Nobody notices until the well is retested and the new factor swings hard. **BS&W and temperature corrections applied inconsistently.** Different wells on the same lease may have different water cuts. Different tanks may have different temperature correction factors. A spreadsheet that uses a single factor across the lease is quietly misallocating every month. **Gas shrinkage and NGL stripping.** Gas from the field becomes sales gas plus NGLs plus fuel plus flare. Operators who allocate based on wellhead gas volumes without the shrinkage math are either over-paying or under-paying their partners on the gas side, often both at once. **Non-consent and back-in accounting.** When a partner elects not to participate in a recompletion, the math for recovering their penalty (often 200 to 500 percent of their share of costs) before their interest revests is one of the most common places allocation breaks in practice. **Changes in ownership.** An owner sells their 12.5 percent interest mid-month. The allocation system has to split the month on the transaction date and pay the old owner for days 1 to 17 and the new owner for days 18 to 30. Spreadsheets fumble this constantly. A serious allocation tool handles all of these as features, not edge cases. A spreadsheet handles them if the human maintaining it remembers. ### Amateur vs Pro: How Operators Run Allocation | The amateur... | The pro... | |----------------|------------| | Lets one person's spreadsheet be the whole allocation system | Treats allocation as a process that survives the person who maintains it | | Uses last year's well test to set this year's allocation factors | Tests wells on a cadence and refreshes factors when production changes | | Applies one BS&W or temperature factor across every well on the lease | Applies per-well corrections that match what the tank strapper actually measured | | Treats the accounting vendor's bolt-on production module as the allocation tool | Runs a purpose-built production system and hands clean volumes to the accounting platform | | Manually "tunes" the numbers at month-end to make the totals tie | Reviews the audit trail at month-end and fixes the source, not the output | The best operators do not win by buying the fanciest allocation engine. They win by building a disciplined process on top of clean production data, then letting the software enforce the discipline. ## What To Avoid - **Don't treat the accounting vendor's production module as your allocation system (the Bolt-On Trap).** OGsys, Wolfpak, Bolo, SSI, P2, and Quorum are strong accounting platforms. Their production modules exist to feed the accounting side, not to run field-first allocation. Integrate with them; don't ask them to do a job they were not built for. - **Don't let one person own the whole allocation workbook.** A spreadsheet with one keeper is a succession risk disguised as a process. If the keeper wins the lottery Monday, your partners still get paid on Friday. Make sure the tool survives the person. - **Don't skip the well-test cadence.** Allocation factors that have not changed in 18 months usually mean the tests stopped getting run. Every month your per-well splits drift further from reality. - **Don't tune the numbers to tie.** If you have ever manually adjusted a monthly allocation "to make it balance," the source data is wrong. Fix the source, not the output. The audit trail is what defends you when a partner asks. - **Don't buy an enterprise revenue suite for a shop that does not need one.** If a rep is quoting $150k to $500k of implementation on a 75-well operation, they are selling you overhead. Match the tool to the scale. ## What Allocation Software Actually Costs | Tier | Typical cost | What you get | |---|---|---| | Spreadsheet | $0 plus one person's time | Excel, prayer, and a binder | | Allocation inside production software | Included in $15 to $40 per well per month production pricing | Multi-well back-allocation, ownership splits, basic audit trail, export to state filings and revenue decks | | Mid-market revenue suites | $50 to $150 per well per month plus $25k to $75k implementation | Full revenue cycle, JIB, royalty checks, complex ownership structures | | Enterprise revenue platforms | $150+ per well per month plus $100k to $500k+ implementation | Everything above plus dedicated support, custom workflows, multi-entity accounting | The pricing pattern matches production software. An operator running anywhere from 15 to 500 wells paying $25 per well per month gets allocation, production capture, and state filing prep for a manageable annual number (a 50-well shop is around $15k a year, a 200-well shop is closer to $60k). The same operator looking at a dedicated revenue suite is quoted $150k to $300k+ for the first three years.

## The Scout FDC Question One of the most common allocation searches in 2026 is for Scout FDC alternatives. Scout is a well-known product and some operators are looking for a different fit, whether because of pricing, support, or feature gaps. For that specific comparison, see [Scout FDC alternative]({{ site.baseurl }}/blog/scout-fdc-alternative/). The general principle: allocation is core to your operation, so switching costs are real. A migration involves exporting historical allocation factors, rebuilding ownership structures, and re-running 6 to 12 months of comparison runs to confirm the numbers tie. Any vendor who tells you migration is a one-week project is selling you optimism. ## Who This Guide Is Not For This page is written for independent operators with onshore conventional production, commingled tanks or sales meters, and typical working interest structures. It is not the right guide for: **Offshore operators.** Offshore allocation runs on unit-ization agreements, continuous SCADA measurement, and specialized software that is not in the categories above. Talk to a consultant who specializes in the basin. **Midstream and gathering companies.** You are doing allocation for a different reason (gathering fees, processing splits) and the tools are different. This guide covers upstream allocation. **Pure royalty owners.** You are the audience receiving allocated volumes, not the audience producing them. Your ask is different: you want a tool that reads the operator's allocation statements and flags errors. That is a different category. **Unit-ized and pressure-maintained fields.** Your allocation is governed by a unit operating agreement with specialized methodology (often tract participation factors) and off-the-shelf software rarely covers it cleanly. ## How Allocation Fits With Everything Else Allocation is the hinge between production capture and revenue. What flows in: - Per-well volumes from [oil and gas production software]({{ site.baseurl }}/blog/oil-and-gas-production-software/) - Sales and run ticket totals from field data or midstream statements - Ownership structures, division of interest, and working interest percentages from your land system What flows out: - State regulatory filings (per-well volumes for TX RRC PR, OK OCC 300R, ND NDIC Form 5, and similar). See [oil and gas regulatory production reports]({{ site.baseurl }}/blog/oil-and-gas-regulatory-production-reports/). - Revenue distribution to working interest partners (JIB statements) - Royalty checks to mineral owners - Engineering and reserves analysis (per-well historical production) Bad allocation means bad every-one-of-those-things. The pattern operators miss: allocation errors are invisible until someone audits. When the audit happens, it is almost always a non-op partner, a royalty owner, or the state. Fixing errors retroactively is expensive. Fixing them before they happen is cheap. ## Frequently Asked Questions ### Is allocation the same as revenue distribution? No. Allocation answers "how much oil and gas came out of each well?" Revenue distribution answers "who gets paid what for that production?" They run sequentially: you allocate first, then distribute revenue. Some tools bundle both, some separate them. ### Can I just pay my accountant to do this manually? For 1 to 10 wells with simple ownership, yes, and many small operators do. Past about 20 wells or when non-op partners show up, manual allocation becomes too error-prone to defend in an audit. The question is not whether manual works today. The question is whether you could reconstruct last year's allocations from scratch if a partner asked. ### What about multi-product allocation (oil, gas, water, NGL)? Any serious allocation tool handles all four products with their own rules. Oil is usually allocated on BS&W-corrected barrels. Gas allocation runs on wellhead volume with shrinkage to sales volume. NGL allocation requires plant recovery factors. Water allocation matters for disposal and injection. If a vendor only shows you oil allocation in the demo, ask for the other three before committing. ### How do I know if my current allocation is wrong? Three signs: partner or royalty owners ask clarifying questions and you cannot answer without pulling out three spreadsheets; the factor you use for well X has not changed in two years even though the well's production has; or you have ever manually adjusted a monthly allocation "to make the numbers tie." Any of those mean it is time for a real review. ### Will allocation software eliminate the need for a controller? No. It eliminates the hand-math and the late-night Excel debugging. The controller still owns the judgment: choosing allocation methods, reviewing partner statements, handling the exceptions that no software can automate. The tool saves time, it does not replace the controller.

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

## The Short Answer The best operators we see treat allocation as a process, not a spreadsheet. Clean field data upstream. A tool that handles the common cases as features. An audit trail any working-interest partner can read without a translator. That is what holds up when the questions start. If your allocation lives in one person's spreadsheet, you have a succession risk and probably a hidden error problem. If your allocation lives in your production software (GreaseBook or a peer), you are in the right category for a typical independent operation running anywhere from 15 to 2,000+ wells. If someone is selling you an enterprise revenue suite for a shop that size, they are trying to sell you overhead. GreaseBook's allocation module handles the common cases: commingled tanks, multi-well leases, non-op partners, standard working interest. It is not the right tool for offshore operators or complex unit-ized fields. For everyone else, it is built into the platform and worth a look.

**P.S.** The allocation category is quietly dominated by three or four vendors. If you are being sold on a newer entrant, ask specifically how they handle gas lift, cyclic steam, and unitized wells. Those are the edge cases that break lighter tools.

===================================================================== # Oil and Gas Production Data Management Software: A Plain-English Guide > Production data management covers historians, OFM, CMMS, and the pipelines that turn raw field data into decisions. Here's what each one does, who needs it, and when a mobile production tool is enough. Source: https://www.greasebook.com/blog/oil-and-gas-production-data-management-software/ Published: 2026-04-18 --- Four vendor pitches this month. One sells you a historian. One sells you a data warehouse. One sells you a "unified data platform." One sells you an ERP that "does production data management natively." All four have a seven-figure implementation. None of the pitchers has asked you a single question about whether you actually need any of it. Oil and gas production data management software is the umbrella term covering those four tools (historians, decline curve and forecasting packages, CMMS systems, and data warehouses or lakes) plus the integration pipelines between them. For independent operators under 1,000 wells with typical SCADA density, most of the "data management" problem is solved by picking production capture software that exports cleanly and being disciplined about what goes into that capture. Historian and warehouse software is a real category and a legitimate spend above that threshold. Below it, it is a six-figure answer to a question most operators have not earned yet. This guide explains what each of those four tools actually does, who needs which one, how they relate to field data capture, and the honest answer on when a mid-sized independent needs to invest in this category versus when it is overkill. Written for the 100-to-1,000-well independent getting pitched by all four vendors at once. If you run 10,000 wells and already have an internal data team, this page will bore you. **This post is for you if:** - You run anywhere from 100 to 1,000+ wells and you have production data scattered across a field app, SCADA historians, an accounting system, and a pile of spreadsheets. - You cannot reconcile the four sources without manual cleanup and every analysis takes two days. - You have been pitched historians, OFM, CMMS, or a data warehouse and want the honest read on which ones earn their keep at your scale. - You integrate with SCADA on your better wells (horizontal or high-volume conventional) and need the production layer to sit cleanly alongside it. If none of that fits, the [oil and gas software]({{ site.baseurl }}/blog/oil-and-gas-software/) overview is the broader category map and the [what software do oil and gas companies use]({{ site.baseurl }}/blog/what-software-do-oil-and-gas-companies-use/) page sorts answers by operator size.

## The Four Tools Inside "Production Data Management" Vendors use the phrase "production data management" loosely. In practice it refers to one or more of the following. ### 1. Historians A historian is a time-series database purpose-built for industrial data. OSIsoft PI (now AVEVA PI System) is the dominant player. Historians ingest continuous SCADA signals (pressures, temperatures, flow rates, tank levels) at high frequency, compress them, and make years of data queryable in milliseconds. **What it solves:** real-time operations dashboards, engineering analysis of high-frequency data, root cause for abnormal events, feed for digital twins and advanced analytics. **When you need one:** your operation has dense SCADA coverage (most wells instrumented, real-time signals flowing), your engineers run time-series analysis routinely, and you generate more data than a general-purpose database can handle. Typical threshold is 500 to 1,000+ instrumented wells or a handful of high-value assets with deep instrumentation. **When it is overkill:** you gauge wells by hand daily, your "historical data" is daily volumes not second-by-second signals, and nobody on your team runs time-series queries. For that operator, a historian is a six-figure answer to a question you are not asking. ### 2. OFM and forecasting packages OFM (Oil Field Manager, originally Schlumberger, now SLB) and its peers (IHS Harmony, Petrel, ComboCurve, Aries) are engineering-focused tools. They ingest production history, plot decline curves, forecast EUR, run type curve analysis, and feed reserves reports. **What it solves:** decline curve analysis, reserves evaluation, forecasting, type curve generation, and engineering documentation for SEC or regulatory filings. **When you need one:** you have an in-house engineer running reserves reports, you file SEC documentation, you evaluate acquisitions or divestitures based on forecasted production, or you manage a portfolio where decline curve analysis drives capital allocation. **When it is overkill:** your "engineering" function is an external consultant who does reserves once a year. In that case, the consultant's tool (they already own one) is all you need. Rolling it in-house before you have the volume to justify it is backward. See [OFM software]({{ site.baseurl }}/blog/ofm-software/) for a deeper look at this category specifically. ### 3. CMMS (Computerized Maintenance Management Systems) CMMS tools track equipment, maintenance schedules, work orders, and failure history. The oilfield versions (IBM Maximo, SAP PM, Infor EAM, ShieldHub) extend the general-industry playbook with oilfield-specific workflow. **What it solves:** preventive maintenance schedules for rod pumps, ESPs, compressors, and separators; work order management; spare parts inventory; vendor tracking. **When you need one:** your operation has meaningful artificial lift or surface equipment (pumping units, ESPs, compressors), you have dedicated maintenance staff or contract a lift company, and you want to reduce downtime through scheduled interventions rather than failure-driven response. **When it is overkill:** you run stripper wells on rod pumps, your pumper handles minor maintenance in the field, and your workover vendor is on a handshake basis. Formal CMMS is infrastructure for operations that have already grown past informal management. See [CMMS oil and gas]({{ site.baseurl }}/blog/cmms-oil-and-gas/) for the operator-focused view of this category. ### 4. Data warehouses and lakes A data warehouse (Snowflake, BigQuery, Redshift, Azure Synapse) or lake (Databricks, S3 + Spark) centralizes data from every upstream system: production capture, SCADA historian, accounting, land, HR, vendor spend. Engineers, analysts, and executives then query a single source of truth instead of reconciling four systems. **What it solves:** cross-system analytics, custom dashboards, ML and predictive modeling, executive reporting that spans production, financials, and operations. **When you need one:** you have a data team (even a team of one), you have already outgrown vendor-specific reporting, and your analysts keep hitting limits because the data they need sits in three different systems that do not talk. **When it is overkill:** your "analytics" is an Excel export from your production software once a month. Rolling out a warehouse before you have the use cases and the people to run it is how companies end up with $200k of cloud spend and nothing to show for it. ## How Production Data Management Relates to Field Data Capture The relationship trips operators up because vendors blur it on purpose. Here is the honest picture. Field data capture (production software like GreaseBook) is the front door. It records what pumpers observe at each well: volumes, tank gauges, run tickets, pressures, downtime, notes. It runs on phones and tablets. It operates at the frequency of human observation (daily to hourly). Historians are the side door for continuous SCADA signals. They run at the frequency of the sensor (seconds to minutes). The data they capture is different: pressure waveforms, flow rates, motor current, not pumper-gauged volumes. OFM, CMMS, and data warehouses are downstream consumers. They read from the front door, the side door, or both. For a typical independent with some SCADA and some manual gauging, the right stack is: mobile production software for human-captured data, basic SCADA integration for automated wells, and exports into either a vendor's reporting or a simple warehouse if the analysis team exists. For a broader map of how all these categories sit together, see the [oil and gas software]({{ site.baseurl }}/blog/oil-and-gas-software/) overview. For the production capture layer specifically, see [oil and gas production software]({{ site.baseurl }}/blog/oil-and-gas-production-software/). ## Competitive Landscape: Pak Energy, Wenergy, and the Enterprise Tier Two names come up repeatedly when operators research production data management. **Pak Energy** (the rebrand of WolfePak, now combined with other acquisitions) positions itself as an integrated platform covering production, accounting, and land for upstream oil and gas. It is a real tool, serious software, and a legitimate option for upper-mid to large independents who want one vendor across production and accounting. Pricing is enterprise-tier and so is the implementation. For a head-to-head look at when Pak Energy is the right call versus lighter-weight alternatives, see [Pak Energy comparison]({{ site.baseurl }}/blog/pak-energy-comparison/). **Wenergy** (W Energy Software) is a cloud-based ERP for upstream and midstream operators. It covers revenue, JIB, land, and production in a single platform. Modern architecture, modern UI, enterprise pricing. The target customer is mid-market to large operators who want cloud-native ERP rather than on-premise legacy. For when Wenergy fits versus when it does not, see [Wenergy comparison]({{ site.baseurl }}/blog/wenergy-comparison/). The honest framing: both Pak Energy and Wenergy are credible options for operators in the 500 to 5,000+ well range. Below that, they are usually overbuilt. GreaseBook and similar mobile-first tools live in the 5 to 1,000 well range where simpler, cheaper, and faster-to-deploy is the right answer.

## What Production Data Management Actually Costs | Tier | Tools included | Typical cost | |---|---|---| | Mobile production only | Field data capture, basic allocation, state filing prep | $15 to $40 per well per month | | Production + basic integration | Above plus data exports to warehouse or accounting | $20 to $50 per well per month | | OFM or forecasting package | Engineering-focused decline curve and reserves tool | $5k to $40k per year per user (ComboCurve), or enterprise licensing for SLB tools | | Historian deployment | PI System or peer, with engineering services | $100k to $1M+ upfront plus annual maintenance | | CMMS | Maintenance management, typically per-technician or per-asset | $30 to $150 per user per month, plus implementation | | Mid-market ERP (Pak Energy, Wenergy) | Production + accounting + land integrated | $50 to $200 per well per month plus $50k to $500k implementation | | Full data warehouse build | Cloud infrastructure plus ETL plus analyst team | $50k to $500k year one, scaling with data volume | An independent running anywhere from 50 to 2,000 wells typically spends $25 to $50 per well per month on a complete production stack (mobile capture plus light integration) and scales up from there if engineering and analytics needs justify it. The operators who over-spend are almost always the ones who bought enterprise before they had the use cases to justify it. ## What Operators Actually Ask About This Category The question "what software do oil and gas companies use?" (addressed in detail at [what software do oil and gas companies use]({{ site.baseurl }}/blog/what-software-do-oil-and-gas-companies-use/)) gets asked constantly because the answer genuinely depends on company size. **1 to 10 wells:** spreadsheets, paper gauge sheets, a CPA who handles accounting. No PDM at all. **10 to 100 wells:** mobile production software (GreaseBook or peer), a mid-range O&G accounting platform (OGsys, Wolfpak, Bolo, SSI, Pac Energy) once working interest partners or multi-state tax are in play (QuickBooks plus a CPA stretches only for solo ownership at the narrowest end), no historian, no CMMS, maybe a consulting engineer who runs OFM externally. **100 to 1,000 wells:** mobile production software plus a mid-range O&G accounting suite (OGsys, Wolfpak, Bolo, SSI, Pac Energy), beginning of CMMS if equipment portfolio warrants it, OFM or ComboCurve in-house. Next-tier ERP (P2, Quorum, W Energy) starts to make sense toward the upper end of this range. **1,000 to 10,000 wells:** integrated ERP (Pak Energy, Wenergy, Quorum, or equivalent), real historian, CMMS, in-house engineering and data team, likely a data warehouse. **10,000+ wells (majors and large independents):** all of the above plus custom-built integration layer, significant in-house software, probably multiple redundant systems. A 75-well operator shopping for historian and warehouse technology is being sold up-market. A 5,000-well operator running allocation in spreadsheets is being held back by infrastructure they outgrew years ago. ## Amateur vs Pro: How Operators Buy This Stack | The amateur... | The pro... | |----------------|------------| | Buys a historian because a vendor said "you need one" | Counts actual instrumented wells and query volume before writing a check | | Treats the accounting vendor's built-in production module as data management | Runs a purpose-built production system and integrates with the accounting platform | | Orders OFM for a 40-well shop that already pays a consultant for annual reserves | Uses the consultant's existing tool until in-house volume actually justifies bringing it home | | Implements a cloud warehouse before hiring anyone to query it | Waits until the analytics use cases and the people to run them both exist | | Lets SCADA data live in its own silo separate from field-entered data and exec dashboards | Pipes SCADA, field entries, and exec dashboards into one screen so the team works off the same source of truth | The best operators build the layer underneath before buying the layer on top. Clean capture. Clean integration. Then (and only then) historians, warehouses, or in-house OFM. ## What To Avoid - **Don't buy into the Bolt-On Trap.** Accounting suites (OGsys, Wolfpak, Bolo, SSI, P2, Quorum) ship production modules because they have to. Those modules were built to feed accounting, not to manage production data. Integrate with the accounting platform; don't ask it to be your production system. - **Don't let SCADA data live in its own silo (the SCADA Silo).** If your SCADA dashboard, your field app, and your exec dashboards each show different numbers, you don't have data management. You have three disconnected data sources. Pick a production layer that pulls SCADA and field entries into one pane. - **Don't buy a historian before you have the use cases to justify one.** Historians solve millions-of-sensor-readings-per-day problems. If your "historical data" is daily pumper-gauged volumes, a historian is a $500k answer to a question you are not asking. - **Don't let the Paper Lag hide inside a "data platform."** A cloud warehouse that ingests stale production data from paper gauge sheets is still serving 2-to-3-week-old numbers. Fix the capture layer first. The warehouse cannot outrun the input. - **Don't roll OFM or a CMMS in-house before your team can actually run it.** License cost is the easy part. The learning curve, the configuration, the ongoing care are where operators lose the investment. Start with the consultant or the spreadsheet. Move in-house when the volume actually demands it. ## Who This Guide Is Not For **Pure royalty owners and non-operators.** You do not manage production data. You receive statements. This is not your category. **Service companies.** Completion, workover, and stimulation companies have their own data management tools (DIMS, WellView, peer products). Different category, different vendors. **Midstream operators.** Gathering, processing, and transportation have their own PDM landscape. Not covered here. **Operators who already have an integrated ERP working well.** If you are on Pak Energy, Wenergy, Quorum, or similar and the system works, there is no reason to read this guide. Your stack is already a decision that has been made. ## Frequently Asked Questions ### Do I need a historian for my operation? Probably not unless you have dense SCADA (most wells instrumented with continuous signals) and an engineering team that runs time-series analysis routinely. Historians solve the problem of millions of sensor readings per day. If your data volume is daily pumper-gauged numbers, a historian is the wrong tool. ### Is OFM still the industry standard for decline curves? OFM (now part of SLB) is still widely used but newer tools like ComboCurve and IHS Harmony have gained significant market share, especially among independents. The right question is what your reserves auditor and your bank are comfortable with. ### How do I know when I have outgrown my production software? Three signs: your engineer exports to Excel for every analysis because the native tool cannot answer their questions, you have meaningful SCADA data that is not flowing into any analysis, or your accounting team is re-entering production volumes by hand every month. Any of those means the integration is the bottleneck, not the production tool itself. ### Can GreaseBook replace Pak Energy? For operations in the 5 to 1,000 well range with typical onshore production, usually yes on the production and allocation side. For the accounting side, GreaseBook integrates with your accounting package rather than replacing it. The honest framing: Pak Energy bundles everything into one ecosystem at enterprise price. GreaseBook does production and allocation well and partners for the rest. ### What about SCADA integration? Mobile production tools (GreaseBook included) integrate with common SCADA systems to pull automated well data into the same reporting pipeline as pumper-entered data. The integration is usually straightforward for onshore conventional wells. Exotic setups (offshore, unit-ized, complex multi-phase) need a specialist.

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

## The Short Answer Production data management is a big umbrella. For independents under 1,000 wells, most of the problem is solved by picking production software that exports cleanly plus a thoughtful approach to the adjacent tools you actually need. For operators above that threshold or with dense SCADA, real PDM tools (historians, OFM, CMMS, warehouses) become legitimate line items. GreaseBook is in the field data capture category. It is not a historian, not a CMMS, not an OFM replacement. What it does is give smaller operators clean production data that downstream tools (your accountant's software, your engineer's OFM package, your partner's allocation demands) can actually consume. For a 50- to 500-well operation, that is usually the right starting point.

## What Regulatory Production Reporting Actually Requires Every state wants the same core information, structured differently. - **Operator identity.** Operator number, lease or well identifier, reporting period. - **Volumes.** Oil produced, gas produced (often split by sales, vented, flared, fuel), water produced (often split by disposal method), injection volumes, disposal volumes. - **Status codes.** Which wells were active, shut-in, plugged, or temporarily abandoned during the period. - **Dispositions.** Where the oil and gas went: tank to pipeline, sales, stock change, lease use. - **Attestation.** A signature from a responsible party certifying that the data is true. Every state takes those five buckets and wraps them in its own schema. Texas wants form PR with well API numbers and lease numbers. Oklahoma wants Form 300R with a specific worksheet structure. North Dakota wants Form 5 monthly. California wants the CalGEM (formerly DOGGR) OG filing. The underlying data is the same. The packaging is what changes. Software helps with two parts of this job: capturing the raw data correctly (pumper-gauged volumes, run tickets, allocation splits) and formatting it for the specific form the state wants. The actual filing (uploading to the portal, signing the attestation, paying any fees) stays with the operator of record. No software replaces the operator's signature on the regulator's form. For the upstream production capture that feeds these filings, see [oil and gas production software]({{ site.baseurl }}/blog/oil-and-gas-production-software/). For the allocation math that produces per-well volumes when you have commingled tanks, see [oil and gas production allocation software]({{ site.baseurl }}/blog/oil-and-gas-production-allocation-software/). ## Which Report Do You Owe This Month? Before you drill into the state-by-state detail, this decision table maps operator situation to the form that matters. | If you operate wells in... | Then you file... | Cadence | |---------------------------|------------------|---------| | Texas | RRC Form PR | Monthly, last day of following month | | Oklahoma | OCC Form 300R (via OTC) | Monthly, 25th of second month after production | | North Dakota | NDIC Form 5 (oil), Form 5B (gas) | Monthly, last day of following month | | California | CalGEM monthly (via WellSTAR) | Monthly, last day of following month | | New Mexico | OCD Form C-115 | Monthly, 15th of second month after production | | Louisiana | DM-1-R (via SONRIS) | Monthly, last day of second month after production | | Colorado | ECMC Form 7 (formerly COGCC) | Monthly, roughly 45 days after production | | Pennsylvania | DEP production report (via eFACTS) | Semi-annual, Aug 15 and Feb 15 | | West Virginia | WR-39 (via OGWIS) | Annual, by March 31 | | Wyoming | WOGCC Form 2 | Monthly, last day of second month after production | | Kansas | KCC production (via KOLAR, often called OGOR) | Monthly, last day of second month after production | | Any federal or tribal lease | ONRR OGOR + royalty report (via eCommerce) | Monthly, last day of following month | The best operators file before the due date, not on it. Every filing where the field data closes in the first week of the next month buys back the last week of scramble. ## The 12 Jurisdictions That Matter ### Texas: RRC Form PR The Texas Railroad Commission Form PR (Monthly Production Report) is filed monthly for every lease producing oil or gas in Texas. It runs through the RRC Online System. Operators report per-well volumes, dispositions, and stock changes. Due around the last day of the month following the production month. Late filings trigger a reminder, then penalties if the pattern continues. For the full filing walkthrough including portal access, common errors, and the specific data fields RRC requires, see [Texas RRC PR form]({{ site.baseurl }}/blog/texas-rrc-pr-form/). ### Oklahoma: OCC Form 300R The Oklahoma Corporation Commission Form 300R (Monthly Production Report) is filed monthly. Oklahoma uses a slightly different lease and well numbering structure than Texas and the reporting workbook has its own quirks. See [Oklahoma OCC Form 300R]({{ site.baseurl }}/blog/oklahoma-occ-form-300r/) for the detailed walkthrough. ### North Dakota: NDIC Form 5 The North Dakota Industrial Commission Department of Mineral Resources collects Form 5 monthly. Williston Basin operators deal with NDIC along with federal ONRR for wells on the reservation. See [North Dakota NDIC Form 5]({{ site.baseurl }}/blog/north-dakota-ndic-form-5/) for the full state-specific guide. ### California: CalGEM (formerly DOGGR) California's Geologic Energy Management Division (CalGEM, which replaced DOGGR in 2020) handles upstream regulation. Production reporting in California has unique requirements around steam injection reporting for heavy oil fields and stringent idle well rules. See [California DOGGR reporting]({{ site.baseurl }}/blog/california-doggr-reporting/) for the current CalGEM-era requirements. ### New Mexico: OCD Form C-115 The New Mexico Oil Conservation Division Form C-115 is the monthly operator's report. Permian-side operators often run Texas and New Mexico leases in parallel and have to file both forms every month with overlapping but non-identical data. See [New Mexico OCD Form C-115]({{ site.baseurl }}/blog/new-mexico-ocd-form-c115/). ### Louisiana: SONRIS DM-1R Louisiana's Department of Natural Resources runs the SONRIS system. DM-1R is the monthly production reporting form. See [Louisiana SONRIS DM-1R]({{ site.baseurl }}/blog/louisiana-sonris-dm1r/). ### Colorado: COGCC (now ECMC) Form 7 Colorado's Oil and Gas Conservation Commission was renamed the Energy and Carbon Management Commission (ECMC) in 2024. Form 7 is the monthly production report. ECMC has strict environmental reporting rules layered on top of production, particularly around venting and flaring. See [Colorado COGCC Form 7]({{ site.baseurl }}/blog/colorado-cogcc-form-7/). ### Pennsylvania: DEP Production Reporting Pennsylvania's Department of Environmental Protection collects production reports semi-annually rather than monthly, which trips up operators used to the monthly cadence in other states. Marcellus and Utica operators file on the DEP's schedule. See [Pennsylvania DEP production reporting]({{ site.baseurl }}/blog/pennsylvania-dep-production-reporting/). ### West Virginia: WR-39 West Virginia's Department of Environmental Protection Office of Oil and Gas collects the WR-39 monthly production report. Appalachian operators filing in West Virginia alongside Pennsylvania and Ohio run into a three-state filing cadence that varies by state. See [West Virginia WR-39]({{ site.baseurl }}/blog/west-virginia-wr39/). ### Wyoming: Form 2 The Wyoming Oil and Gas Conservation Commission collects Form 2 (Monthly Oil and Gas Production Report). Wyoming operators frequently run both state and federal reporting in parallel because much of the production is on BLM or tribal land. See [Wyoming Form 2]({{ site.baseurl }}/blog/wyoming-form-2/). ### Kansas: KCC OGOR The Kansas Corporation Commission collects the Oil and Gas Operator Report (OGOR) monthly. Kansas has a large tail of low-volume wells and its reporting workflow reflects that. See [Kansas OGOR]({{ site.baseurl }}/blog/kansas-ogor/). ### Federal: ONRR (Office of Natural Resources Revenue) ONRR is the federal counterpart for production on BLM, offshore, and tribal lands. Wyoming, Utah, New Mexico, Louisiana offshore, and many other jurisdictions involve federal leases where ONRR filings run parallel to state filings. See [ONRR federal reporting]({{ site.baseurl }}/blog/onrr-federal-reporting/) for the federal-lease workflow.

## The Common Filing Mistakes (Every State) State forms differ but the failure patterns are universal. These come up across every regulator. **1. Per-well allocation errors on commingled leases.** If five wells sell into a single tank battery, the state wants to see per-well volumes, not lease totals. Operators who use a fixed allocation factor from two years ago get flagged when the state runs a back-check against severance tax receipts. Keep allocation factors current and document how they are calculated. **2. Status code mismatches.** A well that went shut-in on March 14 but is still coded as active on the March filing creates a discrepancy that auditors find easily. Update status codes in the same cadence as the field observations that trigger them. **3. Disposition coding.** Gas vented versus gas flared versus gas used for fuel have different regulatory treatment in almost every state. Miscoding them is one of the fastest ways to draw an environmental complaint, particularly in Colorado, California, New Mexico, and Wyoming where venting and flaring rules are actively enforced. **4. Late filings on PA and other non-monthly states.** Operators used to the monthly cadence in Texas and Oklahoma miss the Pennsylvania semi-annual cadence because it does not trigger a monthly habit. Same pattern happens with federal ONRR on some filings. Track cadence per jurisdiction, not per operator. **5. Stock change errors.** The volume in tanks at month-end is part of the reconciliation. Operators who report lifted volumes without stock-adjusting produce reports that the regulator's back-check will flag within a quarter. **6. Signature and attestation failures.** Some states (Texas and Oklahoma among them) have strict requirements about who can sign the operator attestation. An office manager signing a form the state expects to be signed by the operator of record is a procedural violation even if the data is correct. ## Phrases to Eliminate in Regulator Correspondence The language operators use when something goes wrong changes the regulator's response. Blame language invites audit scrutiny. Measurement language closes findings. Self-disclosure usually costs less than silence. | Instead of... | Say... | Why | |---------------|--------|-----| | "Our site was down last week" | "We had three days of non-production on lease Y, documented in the daily gauge log" | Regulators audit against measurable non-production periods, not vague "down" language | | "Our pumper messed up the gauges" | "Field data captured readings outside the validation range on two wells on [date]" | Blame language attracts scrutiny. Measurement language closes the finding. | | "We missed the deadline" | "We filed 3 business days after the due date and self-reported the variance with the amendment" | Self-disclosure carries more weight than silence. Regulators forgive errors they find corrected faster than errors they discover themselves. | | "We estimated the flare volume" | "We applied the documented calculation method [cite method] for flare volumes during [period]" | "Estimated" without a method is an audit trigger in CO, NM, WY, and CA. A documented method passes. | | "The pumper forgot to log that day" | "That day's gauge is reconstructed from the adjacent-day readings and the run ticket on file" | Never tell a regulator a record is missing if you can reconcile it. Show the reconstruction math. | ## Identity Framing: What the Best Operators Do The best operators close the month in the first week, not the last. They file the amendment the day they find the error, not the day the regulator asks. They document the calculation method for flare volumes before the state writes a rule requiring it. Regulatory filing is not a fire drill at the end of the month. It is a rhythm, built into the daily data chain, so the form drops out of the system instead of getting reconstructed from memory. ## How Production Software Helps (and Where It Stops) A modern production tool captures field data, maintains allocation factors, applies correct BS&W and temperature corrections, and exports the data in the format the state wants. What it does not do: file the form for you, pay the fees, or replace the operator-of-record signature. Here is the honest break: **Software handles:** - Daily and monthly production capture (per-well volumes, dispositions, statuses) - Allocation math for commingled tanks - BS&W and temperature corrections - State-specific export formats (CSV, XML, or direct portal submission formats) - Historical filings archive (you should keep copies indefinitely; many operators do not, and live to regret it) **Operator handles:** - Portal login and submission - Attestation signature - Fee payment - Any regulator correspondence that follows - Amendments when errors surface If a vendor tells you their software "automatically files" state reports, ask what that means precisely. In some cases it means the software uploads data through a state API and the operator still has to log in and sign. In other cases the vendor has a service where they submit on behalf of operators with power of attorney. Know which one you are buying. ## Who This Guide Is Not For **Service companies.** Your reporting obligations are different (SWD operators report disposal, completion companies report fluids and chemicals). This guide covers upstream production reporting by operators of record. **Pure non-op partners.** You do not file production reports. The operator of record does. Your job is to read the operator's statements and reconcile them against your interest. **Midstream and gathering companies.** Your reporting obligations run through different systems (pipeline tariffs, FERC, gathering agreements). Not covered here. **Automated state report support.** GreaseBook automates state production report prep for operators filing in Texas, Mississippi, Alabama, Wyoming, and Michigan. For the other jurisdictions mapped above (Oklahoma, North Dakota, California, New Mexico, Louisiana, Colorado, Pennsylvania, West Virginia, Kansas, and federal ONRR), we publish the pillar walkthrough and expect to expand automated filing support over time. Ohio, Alaska, and other producing states have their own forms not currently covered here: the principles in this guide still apply, but contact the state regulator directly for specifics. ## The Workflow a Well-Run Operator Actually Uses For operators running in two to four states, the monthly filing workflow that works is a consistent sequence. **Day 1 to 3 after month close:** pumpers finalize field data for the prior month. Any pending run tickets, tank strappings, or stock adjustments get closed out. **Day 4 to 6:** office reviews allocation for commingled leases, runs BS&W and temperature corrections, and produces internal exception reports for any volumes that look off. **Day 7 to 10:** generate state-specific exports from the production software, review the pre-filing reports, and walk through any exceptions with the field team before filing. **Day 11 to 15:** file in each state on its schedule. Texas PR and Oklahoma 300R typically go first because of the late-month deadline pattern. Pennsylvania and other semi-annual filings slot in on their own cadence. **Day 16+:** archive filings, update the master filing log, and close the month. Operators who try to run this workflow off pumper paper and an office spreadsheet can do it, but only at small scale and only with one very disciplined person driving the process. Past roughly 30 wells or across more than two states, the workflow breaks without purpose-built software supporting it. ## What To Avoid: The Mistakes That Trigger Regulator Scrutiny - **Don't let the attestation signature drift.** States expect the operator of record to sign. An office assistant signing on behalf of the operator is a procedural violation even when the volumes are correct. - **Don't explain late filings with "we were busy."** Regulators read that as "low operator discipline." Self-report the variance, cite the corrective action, and move on. - **Don't amend quietly six months later.** Amendments filed well after the discovery window look like you were hoping nobody noticed. File the amendment as soon as the error surfaces. - **Don't estimate flare or vent volumes without a method.** "About 50 MCF" is the fastest way to draw an environmental letter in CO, NM, WY, or CA. Document the calculation method and cite it. - **Don't reuse an allocation factor from two years ago.** Stale allocation is the easiest finding in a back-check against severance tax receipts. Refresh allocation factors when well tests change. - **Don't skip the zero-production filing for a shut-in well.** A missing monthly line looks like non-compliance. A zero line with a documented status closes the record. - **Don't file the wrong form for a federal lease.** C-115 instead of C-115B, or a state filing without the paired ONRR OGOR, creates reconciliation gaps that compound quarter over quarter. ## Frequently Asked Questions ### Does production software actually file my state reports? It prepares the data and exports it in the format the state accepts. Most operators still log into the state portal, review the submission, and sign. A few vendors offer a filing service where they submit on behalf of the operator. Ask explicitly which one the vendor provides before assuming. ### What happens if I miss a filing deadline? Each state has its own penalty structure. Texas sends a reminder, then escalates. Oklahoma has a progressive penalty schedule. California can refer persistent non-filers for enforcement. The common thread: first-time misses are forgiven if corrected promptly; repeat patterns get attention. Chronic non-filing can jeopardize operator certification. ### Do I need different software for each state? No. Most modern production tools cover the major producing states. What changes is the export format and the specific data fields required per state. A tool that only supports Texas and Oklahoma is limited. A tool that covers the 12 jurisdictions in this guide plus ONRR is sufficient for most independents. ### How long should I keep filed reports? Indefinitely. Many regulators have look-back periods of 3 to 7 years for audits. Tax authorities have their own look-back windows. Partners have claims that can surface years later. Storage is cheap. Regret is not. ### What about amended filings? Every state allows amendments. The process varies: Texas has a specific amendment workflow through the RRC portal, Oklahoma handles it through 300R amendments, and so on. File the amendment as soon as the error is identified. Regulators are generally forgiving of errors that are self-corrected; they are much less forgiving of errors discovered by the regulator.

About the author: Greg Archbald is the founder of GreaseBook. He built the product from inside the oil patch and has spent 15+ years on the operator side of oil and gas technology, most of it hearing operators describe state-filing week as the worst week of the month.

## The Short Answer State production reporting is a recurring tax on operator attention. The best operators treat it as a monthly drill, built around a clean production capture and allocation workflow. The worst treat it as a fire drill at the end of every month, which is expensive in both staff time and penalty risk. GreaseBook captures the data, maintains allocation factors, and exports to the 12 jurisdictions covered in this guide plus federal ONRR. It does not replace the operator's role in the filing itself, but it eliminates the data-wrangling step that takes most of the month-end time. For state-specific details, follow the links above to each state's deep dive.

Two minutes. No sales call, no pushy follow-up. If GreaseBook lands and the fit turns out wrong inside year one, the 200% money-back guarantee refunds you twice the contract price. That is how confident we are in the pumper-adoption bar. If the data capture doesn't collapse the filing-prep half of your month, you are owed your money back plus 100%. **P.S.** This page is not for a non-op partner or a compliance firm filing on behalf of an operator. No hard feelings. If you are still deciding, the quiz gives you a straight answer in the time it takes to refill your coffee. ===================================================================== # Oilfield Monitoring: The Honest Guide to Tools, Tradeoffs, and What Operators Actually Use > Oilfield monitoring covers tank levels, runtime, pressures, and alarms across wells and facilities. Here is what the tools actually do, where they break down, and which operators fit which stack. Source: https://www.greasebook.com/blog/oilfield-monitoring/ Published: 2026-04-18 --- 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](/blog/oil-and-gas-scada/) is the next step up in instrumentation and the [oilfield automation guide](/blog/oil-and-gas-automation/) 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.

Not sure which monitoring stack fits your operation?

Take the 2-minute quiz. We'll tell you whether a phone-first tool, SCADA, or something in between matches your well count, budget, and team.

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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](https://www.greasebook.com) sits in this category for producers who want structured field data capture flowing into allocations, state reports, and an executive dashboard. [TinyPumper](https://tinypumper.com) 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](/blog/oil-and-gas-scada/) 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](/blog/oilfield-monitoring-app/) for the phone-first side and [oilfield monitoring software](/blog/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](/blog/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. ## Related Guides - [Oilfield monitoring app](/blog/oilfield-monitoring-app/): the phone-first side of monitoring - [Oilfield monitoring software](/blog/oilfield-monitoring-software/): the broader software category - [Oilfield monitoring system](/blog/oilfield-monitoring-system/): how the hardware, telemetry, and software layers fit together - [Oil and gas SCADA](/blog/oil-and-gas-scada/): the next step up in instrumentation (TP-2 pillar) - [Oil and gas automation](/blog/oil-and-gas-automation/): when monitoring becomes control (TP-3 pillar) - [Oilfield IoT](/blog/oilfield-iot/): the sensor and telemetry layer (TP-4 pillar) - [Oil and gas software](/blog/oil-and-gas-software/): the full software landscape (GB-1 pillar) ### 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. - [Troubleshooting problems in oil and gas production](/blog/troubleshooting-problems/): what to check, in what order, when a well looks wrong - [Unusual operations in oil and gas production](/blog/unusual-operations/): the situations the manuals skip - [Lease pumper emergencies](/blog/lease-pumper-emergencies/): what actually constitutes an emergency, and what can wait - [What constitutes a pumper emergency](/blog/oilfield-pumpers-constitutes-emergency/): a companion piece, written from the operator seat - [Filtering alarms in oil, gas, and water production](/blog/filtering-oil-gas-water-production-alarms/): how to stop drowning your team in noise - [Injection well monitoring: volumes, pressure, and the rules](/blog/injection-well-rules-monitoring-volumes-pressure/): SWD and EOR specifics - [7 things to know before lighting a heater-treater](/blog/7-things-you-must-know-to-safely-light-a-heater-treater/): the one that can get someone hurt

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.

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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 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. ===================================================================== # Oil and Gas SCADA: How It Works, What It Costs, and When Operators Actually Need It > SCADA (Supervisory Control and Data Acquisition) is how oil and gas operators monitor and control wells, tanks, and facilities remotely. Here is how the stack works, what it costs, and the honest call on when to deploy it. Source: https://www.greasebook.com/blog/oil-and-gas-scada/ Published: 2026-04-18 --- Written for the producer about to sign a SCADA purchase order, not for the sales engineer writing the quote. If you're the one who has to defend the capex, keep the integrator honest, and explain to the CFO why the per-site math works, keep reading. Picture the SCADA integrator call. Two hours on a Tuesday. The deck has 47 slides. By the end, the scope has grown from tank levels at 20 sites to a full host system, a historian, an HMI operator station, and an 18-month rollout plan. Eighteen months later the hardware is installed and the alarm console is muted because nobody has time to tune it. The HMI in the office is still bookmarked by the controls engineer who left last spring. Nobody watches the screen. That is the failure mode this guide is built to prevent. SCADA stands for Supervisory Control and Data Acquisition. In oil and gas, it is the stack that pulls data from sensors at the wellhead, tank battery, compressor station, or disposal well, sends it over cell, radio, or satellite to a server, and gives the office a live view of what is happening. The same stack can send commands back to start a pump, close a valve, or shut in a well. This guide walks through how the layers fit together, what the real costs look like, which vendors show up most often, and the honest call on when SCADA earns its keep versus when a simpler [monitoring approach](/blog/oilfield-monitoring/) is the better fit. The short version: SCADA is powerful and expensive. For unconventional pads, central compression, gas plants, and large facilities where downtime is measured in dollars per hour, it is table stakes. For conventional wells where the per-site math never penciled, or legacy SCADA that is breaking down and not worth the cost to babysit, it is almost always overkill. Well count is not the right axis here (a 50-well operator and a 5,000-well operator can both run conventional wells where SCADA does not pay back). Facility complexity and per-site economics are. Nobody else in this space will tell you the second half of that sentence, which is exactly why we're starting there. **This post is for you if:** - You're scoping a SCADA rollout and want the honest read on where it pays back versus where a lighter monitoring stack wins. - You have legacy SCADA on conventional sites and the maintenance load is eating the return. - You run anywhere from 50 to 5,000 wells and the per-site economics question is already on your desk. - You want to know what real rollouts cost, which vendors matter, and which mistakes kill SCADA programs inside year one. If none of that fits, the [oilfield monitoring pillar](/blog/oilfield-monitoring/) covers the broader monitoring category and [oilfield IoT](/blog/oilfield-iot/) covers the cloud-first sensor-first side. ## What SCADA Actually Is The term gets thrown around loosely. In practice, SCADA has four distinct layers. **1. Field devices.** Sensors, transmitters, and final control elements at the site. A radar tank level sensor, a pressure transmitter on a flowline, a motor valve on a dump line, a flow meter on a separator. These are the things doing the physical measurement or control. **2. PLCs and RTUs.** Programmable logic controllers and remote terminal units sit in a cabinet at the site, take the signals from the sensors, run basic logic (close this valve when that pressure hits a threshold), and hand the data off to the communication layer. RTUs are more common at remote wellheads; PLCs are more common at facilities with more instrumentation. **3. Communications.** Cellular (AT&T, Verizon, FirstNet), licensed radio, unlicensed radio, satellite (Iridium, Starlink), or wired. This layer is the thing that most often fails and most often drives monthly cost. The pumper does not care whether it is polled or report-by-exception; they care whether the data shows up. **4. The host system.** Software on a server (on-prem or cloud) that receives the data, stores it in a historian, displays it on screens (HMIs), triggers alarms, and lets operators issue commands back to the field. Ignition, Cygnet, eLynx, and Canary are common names here. All four have to work for SCADA to work. A gap in any one layer (a failed sensor, a broken comms radio, a host system that crashed overnight) takes the whole thing down. ## What SCADA Does in an Oil and Gas Operation Strip the marketing away and SCADA does four jobs. **Continuous data collection.** Unlike a pumper doing a daily round, SCADA is polling every few seconds to every few minutes. For production volumes that matters less. For pressures, runtime, and trip events it matters a lot. **Alarming.** High tank, low suction, ESD, gas detection, compressor trip. The alarms fire to a console, to a phone, or to a pumper on call. Good SCADA alarm philosophy is harder than it sounds; most systems over-alarm out of the gate. **Remote control.** Starting and stopping pumps. Opening and closing valves. Adjusting setpoints. Resetting compressors. All of it has safety constraints, role-based permissions, and an audit trail. **Historical trending.** A year of tubing pressure history at one-minute resolution is a different conversation than spot readings from the pumper. Engineers rely on this for optimization, failure diagnosis, and type curve work. ### Which One Do You Actually Need? Forget the vendor deck. Here is the honest read on SCADA versus the alternatives, by situation. | If you... | Then... | Because | |-----------|---------|---------| | Run a compressor station, gas plant, or disposal well where downtime is dollars per hour | Full SCADA is table stakes | Supervisory control and alarm logic is the job SCADA was built for | | Have high-rate horizontal pads where per-site revenue dwarfs per-site capex | Full SCADA pencils easily | The ROI math works at any scale (50 horizontal pads or 500) | | Run legacy SCADA that is breaking down on conventional wells | A drop-in monitoring alternative like TinyPumper is the honest fix | The maintenance drag eats the return; replacement is cheaper than babysitting | | Have conventional wells and tank batteries where SCADA never penciled | Phone-first field app plus flat-rate per-site monitoring | Roughly 99% of the upside without the wiring, the electrician, or the IT burden | | Have a mix of unconventional facilities and conventional long-tail wells | Run both stacks | SCADA where the economics earn it, TinyPumper on the rest |

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## The Real Categories of SCADA in Oil and Gas There are a few distinct flavors in the market, and the vendor conversations go sideways when the categories get mixed up. ### 1. Full-stack enterprise SCADA Systems like Ignition, Canary, and OsiSoft PI do the host, historian, HMI, and reporting all together. Built for operators running hundreds to thousands of sites, with a dedicated controls team. Licensing is significant, install takes months, and the result is a deep, flexible platform. See [Ignition SCADA alternatives](/blog/ignition-scada-alternative/) for context on the smaller-operator lift. ### 2. Hosted oil and gas SCADA Vendors like Cygnet (Weatherford), eLynx, Zedi (Emerson), and TelVent (Schneider) host the SCADA stack in their cloud and sell it as a service. The operator rents the host, the historian, and the HMI on a per-site monthly basis. Lower capex, higher opex, faster rollout. Common for unconventional operators who don't want to run their own controls team. See [oil and gas SCADA companies](/blog/oil-and-gas-scada-companies/) for the landscape. ### 3. Purpose-built upstream SCADA software Narrower systems designed specifically for upstream production. [Oil and gas SCADA software](/blog/oil-and-gas-scada-software/) tends to be simpler than the enterprise platforms but more opinionated for oilfield use cases. Good middle ground for mid-sized operators. ### 4. Open-source or hobbyist stacks Ignition (actually commercial but flexible), Node-RED, OpenHAB-adjacent setups. Useful for producers with strong in-house automation expertise. Not common in production oilfield environments but worth mentioning because engineers sometimes ask. ## What SCADA Costs in Oil and Gas Real numbers. Ranges are wide because every project has a different starting point. | Item | Low end | High end | Notes | |---|---|---|---| | Per-site hardware (RTU, sensors, cabinet, install) | $3,000 | $25,000 | Depends on how much is already there and what's being metered | | Per-site monthly comms + hosting | $50 | $250 | Cellular plans, hosted SCADA fees, alarm services | | Host platform software (enterprise) | $50,000 | $500,000+ | One-time license; annual support is 20 percent of that | | Host platform software (hosted SaaS) | $0 up front | Rolled into per-site fee | Opex play | | Integrator labor (initial rollout) | $500 / site | $5,000 / site | Wild variance by region, scope, and whether the operator's team does any of the work | | Ongoing controls support | $80K / year for a tech | $250K / year for an engineer | Someone has to keep the system alive | A 100-site SCADA rollout with hosted software, moderate instrumentation, and a good integrator tends to land somewhere between $500K and $1.5M up front plus $100K to $300K per year operating. That is a real number, not a vendor's happy-path estimate. ## When SCADA Earns Its Keep Forget well count. The axes that actually matter are facility complexity and per-site economics. **Central facilities that have to stay up.** Compressor stations, saltwater disposal, gas plants, inlet separation. Unplanned downtime at a facility costs real money per hour. That is where SCADA pays back fastest. **Safety-critical operations.** H2S gas detection, fire and gas, ESD systems. The alarm and shutdown logic has to be instrumented. Paper won't do it. **Optimization-driven operations.** Plunger lift, gas lift, ESPs, rod pump optimization. The control loop runs on SCADA data. Without it, the optimization is guesswork. **Regulatory or midstream interface requirements.** Custody transfer, air permit continuous monitoring, midstream allocation that needs flow data every hour. Some contracts and permits require the instrumentation. **Unconventional pads with enough per-site value.** High-rate horizontals, enhanced recovery, and mixed production/injection pads where the per-site spend is a small fraction of the per-site revenue. SCADA earns its keep here at any scale (a producer running 50 horizontal pads and a producer running 500 both sign off on the same ROI math). If none of those apply (meaning this is a conventional well where SCADA never penciled, or legacy SCADA that has turned into a maintenance drag), a phone-based field data capture tool plus remote monitoring that drops in without a trench or an integrator is probably the honest answer. See [oilfield monitoring](/blog/oilfield-monitoring/) for the stack options. ## Where SCADA Breaks Down Three recurring failure modes. **Over-alarming.** The system goes live, every deadband is wrong, and within a week the pumpers and engineers have muted the alarm channel. Rebuilding trust in the alarm list is harder than the original setup. Good SCADA programs spend time on alarm philosophy up front, even though it is unglamorous work. **The SCADA Silo.** The host system is beautiful on the office wall. The pumper has no idea what it says, gets no alarms, and still runs the same paper route. SCADA without a mobile layer for the field team is half a system. The pairing pattern here is SCADA at facilities plus a phone tool like [Greasebook](https://www.greasebook.com) or [TinyPumper](https://tinypumper.com) for the wellheads and the route. **No budget for ongoing support.** The initial rollout gets funded. The full-time tech or engineer to keep the system alive does not. Within 18 months the historian is full, the alarms haven't been tuned since go-live, and half the RTUs are offline. ### Amateur vs Pro: How Operators Spec a SCADA Rollout | The amateur... | The pro... | |----------------|------------| | Lets the integrator scope from the host platform down to the sensors | Scopes from the site economics up; only buys the layers that earn their keep | | Signs a fixed-facility rollout and hopes the alarms tune themselves | Budgets for alarm philosophy work before go-live and a tech to keep it tuned after | | Treats SCADA as the monitoring answer for every well in the portfolio | Runs SCADA where the per-site math pencils and a lighter stack on the conventional long tail | | Lets each vendor ship its own dashboard until five logins later nobody opens any of them | Picks the consolidation layer (historian + field app) before vendor number two is added | | Leaves the pumper out of the rollout plan | Designs the alert path backward from the pumper's phone | The best operators we see do not get fancier SCADA. They get disciplined SCADA. Alarm philosophy funded up front. Ongoing controls support budgeted alongside the hardware. Facility SCADA paired with a phone-first tool for the field team. The SCADA Silo closed before it has a chance to open.

SCADA at the facility, phone app in the field

Most operators end up here. TinyPumper is the phone-first layer for the route. See how it fits with your SCADA stack.

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## The Main SCADA Vendors Operators Encounter Not a ranking. Just the names that show up most often in operator conversations and a one-line honest read on each. - **Ignition (Inductive Automation).** Flexible, scriptable, unlimited tags. Requires real in-house expertise. Popular with operators running their own controls teams. - **Cygnet (Weatherford).** Upstream-specialized, hosted or on-prem. Common in unconventional. Honest workhorse. - **eLynx.** Hosted SCADA, oilfield-focused, strong alarm and integration tooling. Mid-sized operators. - **Zedi (Emerson).** Hosted SCADA with strong well-test and gas flow measurement. Canadian operators and well measurement use cases. - **Canary Labs.** Historian-first, often paired with Ignition or other HMIs. - **OsiSoft PI.** Enterprise historian, common in large operators and midstream. Heavy. - **Wellaware, Novatel, Freewave, SignalFire, FreeWave.** Telemetry hardware vendors, often selling alongside a host SCADA. See [oil and gas SCADA companies](/blog/oil-and-gas-scada-companies/) and [oil and gas SCADA software](/blog/oil-and-gas-scada-software/) for a deeper read on the landscape. ## What Is SCADA Actually? The Plain-English Version If an operator is still wrapping their head around the concept, [what is SCADA](/blog/what-is-scada/) walks through the fundamentals without vendor framing. Useful for a new engineer, a new controller, or an operator evaluating whether to bring SCADA in for the first time. ## SCADA vs. Automation vs. IoT These terms get used interchangeably. They are not the same. - **SCADA** is the historical term for the stack that monitors and supervises distributed field equipment. It implies PLCs/RTUs, a host system, and an HMI. - **Oil and gas automation** is the broader idea of using logic and controls to make the field run without constant human intervention. SCADA is one tool inside automation. See [oil and gas automation](/blog/oil-and-gas-automation/) for the TP-3 pillar. - **IoT** (Internet of Things) is a newer framing where sensors connect directly to the cloud, often over cellular or LPWAN, often without a traditional PLC layer. See [oilfield IoT](/blog/oilfield-iot/) for the TP-4 pillar. In practice, modern oilfield monitoring stacks mix all three. A SCADA host pulls data from traditional RTUs and from cellular IoT sensors and from cloud-connected flow meters, and the distinction between *automation* and *SCADA* blurs. ## What To Avoid Before You Sign the PO - **Don't let the integrator scope down from the host platform.** The SCADA Silo starts with the deck that begins at the historian. Scope from the site economics up. Buy only the layers that earn their keep. - **Don't skip the alarm philosophy work.** An untuned alarm list is a muted alarm list inside a week. If alarm philosophy is not on the scope of work, the rollout is going to look live and be deaf. - **Don't deploy SCADA without a field layer.** The office HMI is half a system. The pumper needs alerts on a phone. Pair SCADA with a phone-first tool for the route before day one, not after the silo has formed. - **Don't buy SCADA to avoid a monitoring decision.** For conventional wells where the math never penciled, SCADA is the wrong answer no matter how good the demo looks. A flat-rate per-site monitoring layer like TinyPumper is the honest fit on those sites at any scale (50 wells or 5,000). - **Don't fund the rollout without funding the support.** A SCADA program without an ongoing controls tech or engineer budget is a program that will be dead in two years. If the ongoing cost can't be funded, the initial cost shouldn't be either. ## Who SCADA Is Not For **Producers running conventional wells where SCADA never penciled.** The per-site capex, wiring, IT load, and ongoing maintenance never hit an ROI the operator could defend. A phone app for the pumper plus drop-in remote monitoring (TinyPumper) is the honest answer at any well count (50 wells or 5,000). **Producers with aging SCADA that is breaking down.** The cost to maintain (sensor replacements, servicing, paying someone to babysit the stack) is no longer justified by the upside. Swapping it out for a drop-in remote monitor costs a fraction and kills the maintenance drag. **Producers wanting one vendor for everything.** SCADA vendors are good at SCADA. They are not typically good at paper replacement, production software, regulatory reporting, or full ERP. Trying to force one system to do all of that is how expensive rollouts fail. **Producers without ongoing controls support.** A SCADA rollout without a budget line for the person maintaining it is a rollout that will be dead in two years. If the ongoing cost can't be funded, the initial cost shouldn't be either. ## Related Guides - [What is SCADA](/blog/what-is-scada/): plain-English fundamentals - [Oil and gas SCADA companies](/blog/oil-and-gas-scada-companies/): the vendor landscape - [Oil and gas SCADA software](/blog/oil-and-gas-scada-software/): the software-only side - [Ignition SCADA alternative](/blog/ignition-scada-alternative/): for operators too small for full Ignition - [Oilfield monitoring](/blog/oilfield-monitoring/): the broader monitoring category (TP-1 pillar) - [Oil and gas automation](/blog/oil-and-gas-automation/): when monitoring becomes control (TP-3 pillar) - [Oilfield IoT](/blog/oilfield-iot/): sensor and telemetry layer (TP-4 pillar) - [Oil and gas software](/blog/oil-and-gas-software/): the full software landscape (GB-1 pillar)

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## Frequently Asked Questions **What does SCADA stand for in oil and gas?** Supervisory Control and Data Acquisition. In oil and gas it refers to the combined hardware and software stack that monitors wells, tanks, and facilities, triggers alarms, and lets the office start, stop, or adjust equipment remotely. **Is SCADA the same thing as a DCS?** No. A distributed control system (DCS) is a tighter, lower-latency control system typical of refineries and continuous-process plants. SCADA is built for geographically distributed, slower-update-cycle operations like upstream production. They overlap, but the use cases and the price tags are different. **How much does an oil and gas SCADA rollout cost?** For a 100-site rollout with hosted software and moderate instrumentation, plan on $500K to $1.5M up front and $100K to $300K per year operating. Per-site costs range from $3K for a simple cellular telemetry install up to $25K+ for a fully instrumented facility. **Can I run SCADA and a phone-based field data app at the same time?** Yes, and most operators do. SCADA handles the facilities and instrumented wellheads; the phone app handles the manual gauge, the daily pumper round, and the wellheads that don't have RTUs. They cover different parts of the operation. **Do I need SCADA for state regulatory reporting?** Not for most upstream production reporting. State regulators care about monthly or daily volumes, not second-by-second data. SCADA helps with the data capture and reduces pumper rounding errors, but the reporting happens at the production software layer. See [oil and gas regulatory production reports](/blog/oil-and-gas-regulatory-production-reports/) for the reporting side. ===================================================================== # Oil and Gas Automation: What It Covers, What It Costs, and Where Operators Get the Most Payback > Oil and gas automation covers everything from a plunger timer to a fully autonomous tank battery. Here is what automation actually does, the honest ROI ranges, and where to start if you are deploying it for the first time. Source: https://www.greasebook.com/blog/oil-and-gas-automation/ Published: 2026-04-18 --- The automation sales pitch goes like this. Glossy deck. Slide three shows a lease running itself. Slide seven has a number where you fire the pumper. Slide twelve is a five-year ROI curve climbing up and to the right. None of slides three, seven, or twelve survive contact with a freezing valve on a Tuesday morning in February. Oil and gas automation is the broad idea of using logic, sensors, and control equipment to make production run with less constant human intervention. In practice it ranges from a plunger lift timer on a single well up to a fully instrumented tank battery that runs, measures, and ships barrels without anyone onsite. This guide is the honest version of the automation conversation we have with independent operators all the time. It walks through the real layers of automation, what each one does, the cost ranges that hold up in the field, where the ROI shows up, and how automation fits with [SCADA](/blog/oil-and-gas-scada/), [monitoring](/blog/oilfield-monitoring/), and [IoT](/blog/oilfield-iot/). The short version: the biggest wins in oilfield automation come from the boring parts (tank battery dump valves, plunger optimization, chemical injection, compressor controls), not from the flashy ones. And no amount of automation replaces the need for a pumper who can judge what is actually happening on the ground. If you want a vendor brochure, close the tab. If you want the straight version, keep reading. **This post is for you if:** - You run anywhere from 15 to 2,000+ wells and you've been pitched automation as the fix for everything from timing to labor. - You want a clear read on which automation layers pay back and which ones turn into a science project. - You need to separate the real wins (plunger optimization, dump valves, chemical injection, compressor controls) from the expensive noise. - You've heard "you can fire your pumpers" and you don't believe it, but you want the honest numbers before you push back. If that doesn't describe you, the [SCADA pillar](/blog/oil-and-gas-scada/) covers supervisory control and the [monitoring pillar](/blog/oilfield-monitoring/) covers the measurement layer underneath it. ## What Oil and Gas Automation Actually Covers *Automation* gets used for at least five distinct things, which is why vendor conversations fall apart so quickly. **1. Well-level automation.** Plunger lift controllers, gas lift controls, rod pump off/on controllers, ESP VFD control, chemical injection pumps. Each one is a small control loop at a single well that makes a decision based on pressure, time, or flow. See [pump-off controller](/blog/pump-off-controller/) for the most common well-level case. **2. Facility automation.** Tank battery dump valves, separator level control, LACT unit custody transfer, compressor controls, saltwater disposal injection rate control. These run continuously with minimal intervention. **3. Route-level automation.** Pumper routing optimization, drive-by data collection, automated gauge replacement with radar level sensors. Less about controls and more about reducing the time and miles per round. **4. Analytics-driven automation.** Systems that take SCADA data, run machine learning or rule-based logic, and either send recommendations to an engineer or (occasionally) adjust setpoints directly. Still emerging in most operator stacks. **5. Full wellsite automation.** The idea of a lease that runs itself: automated startup, automated shutdown, automated optimization, remote alarm and response, only visited for mechanical repairs. See [wellsite automation](/blog/wellsite-automation/) for the honest take on where this sits today. Not every operator needs all of these. A smaller conventional operator (say 15 to 50 wells) might benefit from plunger controllers on the tight-gas wells and nothing else. A larger unconventional operator running hundreds to 2,000+ wells with automated LACT and central facilities is doing most of what is possible without becoming a science project.

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## The Real Layers Operators Actually Deploy ### 1. Timers and simple controllers The entry-level automation. A plunger lift timer. A rod pump on/off controller with a pump-off detector. A chemical pump on a clock. No SCADA, no cellular, no phone app. One device, one job, set by the pumper and the engineer. Costs: a few hundred dollars up to a few thousand per well depending on the device. Payback is fast if the well has the right problem (underutilized plunger, over-pumping rod pump, wasted chemical). Still the highest-ROI automation most operators can deploy. ### 2. Site-level PLCs with basic control A programmable logic controller (or RTU) at the tank battery runs dump valve logic, pump controls, maybe separator level. No remote access beyond an occasional serial connection. The logic is local. The pumper still does rounds. Costs: $5K to $25K per site for the hardware and local instrumentation. Useful for sites that need consistent valve behavior independent of the pumper's timing. ### 3. SCADA-connected automation Same PLCs, but now they report to a central [SCADA](/blog/oil-and-gas-scada/) host and can be tuned or commanded from the office. Alarms go to on-call. Setpoints get adjusted from a desk. This is where the economics start scaling: more sites under one team. Costs: the site hardware plus the full SCADA stack (host, historian, comms, integrator). Typical cost for a new SCADA-connected rollout is $10K to $35K per site plus the host platform and ongoing hosting/support. ### 4. Analytics-driven or ML-driven optimization On top of SCADA-connected automation, an analytics layer runs trends, detects anomalies, and either recommends or adjusts setpoints. Plunger lift optimization algorithms, artificial lift optimization, production forecasting. Vendors like Ambyint, ChampionX, Weatherford ForeSite, and operator-built custom stacks fit here. Costs: add $10 to $50+ per well per month for the analytics platform on top of the underlying SCADA. Payback depends entirely on whether the operator changes actual behavior based on the output. ### 5. Fully automated wellsites The aspiration: automated startup, automated shutdown, automated production optimization, automated measurement, remote response. In reality, most "automated" sites still need the pumper for physical things (valve failures, hauling, wax, repairs, seasonal freezes). See [wellsite automation](/blog/wellsite-automation/) for the honest read. ## How the Automation Categories Compare | Category | Typical scope | Per-site cost | Payback timeframe | What it frees up | |---|---|---|---|---| | Timers and simple controllers | One well, one job | $200 to $3,000 | Weeks to months | Pumper's attention; reduces over/under pumping | | Site-level PLCs | Tank battery, facility | $5K to $25K | 6 to 24 months | Consistent valve and pump behavior | | SCADA-connected automation | Fleet-wide | $10K to $35K + host | 1 to 3 years | Office visibility, remote tuning, alarm response | | Analytics / ML optimization | Production optimization layer | $10 to $50+/well/mo | Varies widely | Engineering time; better production decisions | | Full wellsite automation | Entire lease | $50K+ per site | Uncertain | Aspirational; rarely fully achieved | Ranges are real. They move with well count, facility complexity, existing infrastructure, and how much the operator's team does versus an integrator. ### Where to Start If You're Starting Today | If your pain is... | Start with... | Expected payback | |--------------------|---------------|------------------| | Tight-gas wells loading up or unloading erratically | Plunger lift controllers (well-level) | Months | | Rod pumps failing faster than they should, power bill creeping | Pump-off controllers with fluid-level detection | Months, plus fewer rod jobs | | Chemical truck showing up on a schedule, not on flow | Chemical injection pumps tied to flow measurement | 3 to 9 months | | Dump valves leaking or flying open on the wrong triggers | Tank battery dump valve automation at the highest-volume facility | 6 to 18 months | | Compressor nuisance trips and recycles | Compressor control setpoint tuning | 3 to 12 months | | "Our pumper can't keep up with 120 wells" | Don't start with automation. Start with a modern field app and route optimization. Then automate. | Immediate, before a dime of controls spend | ## Where the Real ROI Is Three places consistently earn their keep. **Plunger lift optimization.** Tight-gas wells with plungers benefit enormously from controllers that adjust cycle time based on actual well performance rather than a fixed clock. Payback in months for most cases. **Rod pump off/on control.** A rod pump running when the fluid level is pumped off wears parts faster and wastes power. A [pump-off controller](/blog/pump-off-controller/) detects the condition and rests the pump. Payback in electricity savings and failure reduction. **Chemical injection pumps on SCADA.** Chemical that gets injected based on actual flow (rather than set-and-forget) cuts chemical spend significantly and reduces corrosion and paraffin episodes. **Tank battery automation.** Dump valves that run on level rather than timers, LACT units that don't need a pumper physically present to ticket the barrels. Straightforward, proven, high ROI for any site with meaningful production. **Compressor controls.** Facility compressors that respond to downstream pressure changes without someone adjusting the setpoint. Reduces nuisance trips and recycles. What consistently does *not* pay back for most operators: bespoke ML optimization on every well, replacing pumpers entirely with automation, and buying a full automation stack before building the monitoring foundation underneath it.

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Solar-powered gateway, radar tank sensor, pressure sensor. Installs in 10 minutes. Roughly 99% of SCADA's upside without the capex or the IT burden. Scales from 50 wells to 5,000.

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## Amateur vs Pro: How Operators Deploy Automation | The amateur... | The pro... | |----------------|------------| | Buys automation to fix a troubled site | Fixes the mechanical or reservoir issue first, then automates the stabilized site | | Installs a full SCADA-connected controls stack on day one | Deploys timers and pump-off controllers first, proves ROI, then moves up the stack | | Trusts the vendor's ROI deck | Runs a 90-day pilot on three wells before any fleet-wide purchase | | Plans to "fire the pumper" once automation is in | Redesigns the pumper's route and exception workload around the automation | | Buys an ML optimization platform without clean SCADA data underneath | Gets the measurement layer honest first, then asks algorithms to find signal | The best operators we see don't win by having the fanciest stack. They win by building the layer underneath before buying the layer on top. ## What To Avoid: Named Traps That Kill Automation Programs - **The Automation-Before-Stabilization Trap.** Operators try to automate a troubled site instead of fixing the underlying mechanical or reservoir issues. Automation codifies the problem instead of solving it. Fix the well. Then automate the well. - **The Orphaned-RTU Problem.** Automation gets installed and works for 90 days. Then an RTU fails, nobody fixes it, and the site reverts to manual with more complexity than before. If the ops team can't support it on day 91, don't buy it on day 1. - **The Vendor-Brochure Pitch.** "You can fire your pumpers." You can't. No amount of current-generation automation gets rid of the field hand. Tanks still have to be hauled, valves still fail, freezing still happens, and someone has to show up when the sensor lies. Automation reduces the *frequency* of visits, not the need. - **The Analytics-Before-Data Mistake.** A predictive maintenance algorithm on bad sensor data is a very expensive way to generate noise. Get the measurement layer right first. Then add the analytics. ## Oil and Gas Automation Companies Worth Knowing Not exhaustive, just the names that show up in operator conversations. See [oil and gas automation companies](/blog/oil-and-gas-automation-companies/) for more detail. - **Emerson (Roxar, AMS, Zedi).** Broad automation portfolio; common in mid to large operators. - **ChampionX / Theta / LOOKOUT.** Artificial lift optimization, rod pump controls, plunger optimization. - **Ambyint.** Machine learning-driven artificial lift optimization. - **Weatherford (ForeSite, CygNet).** Production optimization plus SCADA. - **Schneider Electric.** Industrial automation, some oilfield-specific. - **Rockwell Automation.** Industrial controls, more common at facilities. - **Inductive Automation (Ignition).** Host platform often at the center of automation stacks. - **Smaller oilfield specialists.** Dozens of regional and niche players for specific control applications (gas lift, plunger, chemical, SWD). ## Automation vs. SCADA vs. Monitoring vs. IoT Quick clarifier. - **[Monitoring](/blog/oilfield-monitoring/)** is knowing what is happening. No control. - **[SCADA](/blog/oil-and-gas-scada/)** is monitoring plus supervisory control over distributed sites, typically with PLCs and a host system. - **Automation** is the broader category of making the field run with less intervention. SCADA is one tool inside automation. So are standalone controllers, analytics platforms, and anything else that lets machines make decisions. - **[IoT](/blog/oilfield-iot/)** is the sensor-and-cloud framing, often newer cellular or LPWAN sensors connecting directly to a cloud platform. In practice, modern stacks mix all four, and the labels blur. The question operators should ask isn't "do we have SCADA" or "do we have IoT," it is "what is the job we need done, and which layer is the right tool for that job." ## Industry-Level View A broader read on [automation in the oil and gas industry](/blog/automation-in-oil-and-gas-industry/) covers the trends (edge computing, wireless sensors, AI-assisted optimization, labor shortage pressure) driving investment. Useful context when the CFO asks where the industry is heading. See also the field-level perspective at [oilfield automation](/blog/oilfield-automation/). ## Who This Is Not For **Operators expecting automation to replace the pumper.** It won't. Even fully automated facilities still need someone on the ground for physical problems. Plan the ops model with a pumper in it. **Single-well stripper operators without any existing infrastructure.** Automating one well costs more per barrel than the barrel is worth. If the math doesn't work, the math doesn't work. **Anyone thinking of automation as a one-time project.** Automation is a program, not a project. It requires ongoing calibration, alarm tuning, sensor replacement, and controller updates. Budget accordingly. ## Related Guides - [Oilfield automation](/blog/oilfield-automation/): the field-level view - [Wellsite automation](/blog/wellsite-automation/): the fully-automated-site aspiration in context - [Automation in oil and gas industry](/blog/automation-in-oil-and-gas-industry/): the industry-level read - [Oil and gas automation companies](/blog/oil-and-gas-automation-companies/): the vendor landscape - [Pump-off controller](/blog/pump-off-controller/): the most common well-level automation - [Oilfield monitoring](/blog/oilfield-monitoring/): the broader monitoring category (TP-1 pillar) - [Oil and gas SCADA](/blog/oil-and-gas-scada/): supervisory control stacks (TP-2 pillar) - [Oilfield IoT](/blog/oilfield-iot/): sensor and telemetry layer (TP-4 pillar) - [Oil and gas software](/blog/oil-and-gas-software/): the full software landscape (GB-1 pillar)

The SCADA alternative for conventional wells

TinyPumper pushes tank levels, pressures, and runtime to the cloud from a matchbox-sized gateway. 10-minute install. Flat rate per site. Pairs with any automation stack and works on 50 wells or 5,000.

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## Frequently Asked Questions **What is the difference between oilfield automation and SCADA?** SCADA is one specific category of automation: a supervisory stack with PLCs/RTUs, central host, and an HMI. Automation is broader and includes standalone controllers, analytics platforms, and anything that makes production run with less human intervention. All SCADA is automation. Not all automation is SCADA. **Where does oil and gas automation give the fastest payback?** Plunger lift optimization, rod pump off/on control, chemical injection on flow, and tank battery dump valve control consistently earn their keep fastest. These are boring, proven, and usually pay back in months rather than years. **Can I automate a single well without SCADA?** Yes. Many of the highest-ROI automation options (plunger controllers, pump-off controllers, chemical pumps on timers) run locally without any SCADA connection. SCADA becomes valuable when you are managing many wells from a central office. **Will automation replace my pumpers?** No. It reduces the frequency of routine visits and shifts the pumper's time from gauging and reporting to exception handling, mechanical work, and field judgment. Operators who plan for pumper-free leases and fire their field staff almost always rehire. **How do I pick the right starting point for automation?** Start where the pain is biggest and the fix is cleanest. That usually means plunger lift on tight-gas wells, rod pump control on high-failure rod pumps, or tank battery automation at the highest-volume central facilities. Avoid starting with wellsite-level full automation on a brand new lease as the first project. ===================================================================== # Oilfield IoT: What It Actually Is, What It Costs, and Where It Pays Back > Oilfield IoT covers wireless sensors, cellular telemetry, cloud platforms, and the edge computing in between. Here is what the stack actually does, how it differs from SCADA, and the honest read on where it pays back for oil and gas operators. Source: https://www.greasebook.com/blog/oilfield-iot/ Published: 2026-04-18 --- Written for the operator or engineer about to spec sensors on a lease, not for the analyst writing a market report or the MBA trying to name an IoT strategy. If you're the person who actually has to make this work in the field, keep reading. Picture the aftermath of most IoT pilots. Eighteen months in, the sensors are still transmitting. Nobody is watching. The cloud dashboard is bookmarked by the engineer who left last quarter. The pumper never saw the data because it never made it to his phone. That's the failure mode we're going to spend as much time on as the sensor catalog, because that's where the money actually goes missing. Oilfield IoT (Internet of Things) is the stack of wireless sensors, cellular or LPWAN telemetry, edge compute, and cloud platforms that collects data from oil and gas equipment and routes it to applications and people who can act on it. In practice it overlaps heavily with [SCADA](/blog/oil-and-gas-scada/), [automation](/blog/oil-and-gas-automation/), and [monitoring](/blog/oilfield-monitoring/). The terminology gets used interchangeably, which makes vendor conversations harder than they should be. This guide walks through what IoT actually means in an oil and gas context, how it compares to SCADA, which use cases pay back, and which ones don't. The short version: IoT earns its keep when you need a cellular sensor at a site that doesn't justify a full SCADA install, or when a cloud-first platform fits the operator's team better than an on-prem host. It is not a free replacement for SCADA, and it is not a shortcut around the fundamentals of instrumentation, comms, and power. **This post is for you if:** - You're evaluating cellular or LPWAN sensors (meaning low-power wide-area network sensors that sip data) for tanks, pressures, flow, or equipment health. - You've been told IoT will replace your SCADA and you want the honest read before you cut the purchase order. - You run anywhere from 50 to 5,000 wells and the fragmented vendor clouds question is already on your desk. - You want to know where IoT pays back, where it flops, and which mistakes kill pilots inside year one. If none of that fits, the [oilfield monitoring pillar](/blog/oilfield-monitoring/) is the broader category primer and the [SCADA guide](/blog/oil-and-gas-scada/) covers the supervisory-control side. ## What Oilfield IoT Actually Is IoT as applied to oil and gas tends to mean one of a few things, depending on who is talking. **1. Cellular or LPWAN sensors.** Battery-powered or solar-powered sensors (tank level, pressure, temperature, flow) that connect directly to a cellular network or an LPWAN (LoRaWAN, NB-IoT, LTE-M). No local RTU, no gateway, no radio network. The sensor reports directly to a cloud platform. **2. Cloud-first data platforms.** Services that ingest telemetry from sensors or from existing SCADA, store it in the cloud, and offer dashboards, alarms, and APIs. AWS IoT, Azure IoT, Google Cloud IoT, plus oilfield-specific platforms. **3. Edge computing.** Small compute devices (Raspberry Pi-class up to ruggedized industrial gateways) that sit at the wellsite, handle local logic, and decide what data to send upstream and what to handle locally. The edge layer is what makes IoT more flexible than pure cloud architectures. **4. Digital oilfield / digital twin framings.** Broader concepts where IoT is one input into a simulated or modeled version of the physical asset. See [digital oilfield](/blog/digital-oilfield/) for that framing. **5. Embedded sensors in equipment.** Pumps, compressors, and motors sold by OEMs with sensors already built in. The IoT layer is the vendor's cloud platform reporting equipment health back to the operator. Most oilfield IoT deployments mix at least two of these. A solar cellular tank level sensor reporting to a cloud platform that alerts the pumper on a phone is IoT. So is an edge gateway pulling from a PLC and forwarding selected tags to a cloud analytics tool. ## How IoT Differs from SCADA in Oil and Gas This is where most vendor conversations go wrong. SCADA and IoT overlap, but they have different defaults. | Dimension | SCADA default | IoT default | |---|---|---| | Central data store | On-prem server + historian | Cloud platform | | Field device | PLC or RTU | Cellular / LPWAN sensor or edge gateway | | Communications | Cellular, radio, satellite (often proprietary) | Cellular, LPWAN, WiFi | | Install time | Weeks to months per site | Hours to days per sensor | | Capex per site | $3K to $25K | $200 to $2,000 per sensor | | Ongoing cost per site | $50 to $250/month | $5 to $50/month per sensor | | Typical use | Supervisory control of facility | Discrete measurements, often single-purpose | | Vendor lock-in | High (historian, HMI, host) | Variable (cloud API dependent) | | Control capability | Yes | Limited; more telemetry than control | Neither is strictly better. SCADA is the honest fit when you need tight control over a facility with multiple instruments and a team managing it. IoT is the honest fit for point measurements at remote sites, for operators moving away from on-prem infrastructure, and for use cases where the economics of a full PLC install don't work. ### Which One Do You Actually Need? | If you... | Then... | Because | |-----------|---------|---------| | Need supervisory control of a compressor station, gas plant, or disposal well | SCADA is still the right tool | Control loops and HMI operator stations are not an IoT strength | | Need tank level at 80 stock tanks scattered across three counties | IoT cellular sensors are the honest fit | A full RTU per tank never penciled | | Have an aging SCADA system that's costing more to maintain than it's worth | IoT plus a purpose-built field app is often the cleanest replacement | Modern cellular + mobile phone apps get data to the pumper without the on-prem burden | | Run a mix of conventional and unconventional wells | You'll end up with both | IoT does discrete measurement; SCADA does facility control; pretend otherwise and vendor sprawl wins |

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## The Real Use Cases Where Oilfield IoT Earns Its Keep Not every IoT pitch survives contact with a working lease. Here are the patterns that actually show up. ### 1. Remote tank level A battery-powered or solar-powered radar or pressure-based level sensor on a stock tank or saltwater tank. Reports back every 15 minutes over cellular. Triggers a haul call at a threshold. Straightforward, proven, and common for operators with tank batteries at sites that don't justify a full SCADA RTU. See [IoT in oil and gas](/blog/iot-in-oil-and-gas/) for the broader use-case landscape. ### 2. Cellular flow and pressure monitoring Sensors on flowlines, gas meters, or separators that report continuous or periodic data without a local PLC. Useful for measurement points where operators don't want to run wire or install a full RTU cabinet. ### 3. Facility monitoring with cloud dashboards Pump motor amps, compressor runtime, air quality sensors at facilities, reporting to a cloud platform rather than an on-prem historian. Useful when the operator's team is cloud-native and doesn't want to manage an on-prem SCADA host. ### 4. Equipment-embedded sensors ESPs, rod pumps, and compressors shipped with sensors and a vendor cloud platform. The operator gets equipment health without deploying anything themselves. Payback is vendor-specific and varies with how well the vendor platform integrates with the rest of the stack. ### 5. LPWAN sensor meshes Low-power wide-area networks (LoRaWAN, NB-IoT) where a gateway at a facility picks up data from many low-power sensors across a pad. Useful for dense sensor deployments at larger sites where cellular per-sensor economics don't work. See [IoT oil and gas products](/blog/iot-oil-and-gas-products/) for a landscape of the actual products operators evaluate. ## Where Oilfield IoT Runs Into Trouble **Comms coverage that isn't actually there.** "Cellular everywhere" is a sales assumption. Check the actual signal at the actual site before ordering 100 sensors. LPWAN coverage depends on gateway placement and line of sight. Satellite adds a per-sensor monthly cost that makes the economics different. **Power assumptions.** Solar-plus-battery works for most low-report-rate sensors in sunny regions. It struggles with winter in North Dakota, dense brush, or sensors that report every few seconds. Verify the power budget against actual site conditions. **The Paper Lag repackaged.** A cellular tank level sensor reporting to a cloud dashboard nobody opens is no better than a manual gauge. The production data is still 48 hours late by the time anyone looks at it. The value is in getting the signal to a person who acts. If the alert doesn't text the pumper or show up in his phone app, the IoT investment is wasted. **The SCADA Silo (now in the cloud).** Each vendor ships their own cloud platform. Soon the operator has five different dashboards across five different vendors and no consolidated view. The usual fix is an integration layer (a cloud data platform, sometimes operator-built) that pulls from each vendor and consolidates. That integration layer is its own cost center. **Assuming IoT replaces SCADA.** It doesn't, for operators who need actual supervisory control of facilities. IoT is additive to SCADA at scale, not a replacement for it. ### Amateur vs Pro: How Operators Spec an IoT Rollout | The amateur... | The pro... | |----------------|------------| | Orders 100 cellular sensors before checking signal at the lease | Does a site survey with an actual device before the purchase order | | Picks the vendor whose marketing deck looked best | Runs a 30-day pilot at three sites across three comms environments | | Lets each vendor's cloud dashboard stack up until five logins later nobody opens any of them | Locks down one consolidation layer (field app + integration) before adding vendor number two | | Buys an edge gateway because the sales engineer recommended one | Buys an edge gateway because they already have PLC tags worth forwarding | | Treats the pumper as the last mile afterthought | Designs the alert path backward from the pumper's phone | The best operators we see don't get fancier IoT stacks. They get disciplined ones. One field app on the pumper's phone, alerts routed to the person who can act, integration work scoped before the second vendor is added.

On conventional wells where SCADA doesn't pencil, there's a drop-in alternative

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## Common IoT Platform Architectures Three patterns show up most often. ### A. Single-vendor cloud platform An operator buys sensors and the cloud platform from the same vendor. Quick deployment, tight integration, single invoice. Trade-off: lock-in to that vendor's ecosystem and their pricing. ### B. Hyperscaler cloud + sensor mix The operator runs AWS IoT, Azure IoT, or Google Cloud IoT as the central data plane and buys sensors from multiple vendors. More flexibility, more integration work, more internal engineering expertise required. ### C. Edge gateway + cloud An edge gateway at each site pulls from local sensors (and sometimes from an existing PLC), decides what to send upstream, and forwards it to the cloud. Good for sites with many sensors or with existing PLCs that don't natively cloud-connect. Most mid-sized operators end up with a hybrid: one vendor's cloud for the sensors they bought from that vendor, another layer for the existing SCADA integration, and a third for custom analytics. Messy but realistic. ## Cost Ranges That Hold Up in Practice | Component | Typical cost | Notes | |---|---|---| | Cellular tank level sensor (solar) | $500 to $2,500 per unit | Wide range on accuracy and ruggedness | | LPWAN gateway | $1,500 to $5,000 per gateway | Covers many sensors per gateway | | Per-sensor cellular data plan | $5 to $25/month | Bulk plans available | | Cloud platform (per-asset) | $2 to $50/month | Depends on vendor and data volume | | Edge gateway (industrial) | $1,000 to $4,000 | Includes install and integration | | Integration to existing SCADA | $10K to $100K+ project | Custom work | A 100-site IoT deployment (tank level + one pressure + cloud) typically lands at $60K to $250K up front plus $15K to $60K per year operating. Meaningfully cheaper than equivalent SCADA for discrete measurements. Meaningfully less capable where actual control loops are needed. ## IoT in Oil and Gas Industry Trends A few patterns worth noting. **Cellular displacing proprietary radio.** 4G/5G coverage has reached most producing basins. Licensed radio networks used to be the default; cellular is increasingly the pragmatic choice. **Edge computing getting cheaper and more rugged.** Industrial edge gateways are a fraction of what they cost five years ago. Wellsite-grade hardware is increasingly accessible to mid-sized operators. **Consolidation among IoT cloud vendors.** Some of the dozens of oilfield IoT startups from the 2017-2022 era have been acquired, shut down, or absorbed by larger platforms. Evaluate vendor longevity. **Integration with existing SCADA is the real bottleneck.** The hardest part of most IoT rollouts isn't deploying new sensors; it's connecting the IoT platform to the existing SCADA so the operator has one pane of glass instead of four. **Cybersecurity.** Cloud-connected sensors introduce attack surfaces that pure SCADA on closed radio networks did not. This is an increasing focus for operators doing serious IoT rollouts. ## What To Avoid Before You Cut the Purchase Order - **Don't buy sensors before the site survey.** "Cellular everywhere" is a sales assumption, not a field reading. Check actual signal with an actual device at the actual site. - **Don't skip the power budget.** Solar-plus-battery in the Bakken in January is a different animal than solar-plus-battery in the Permian in July. Spec against worst-case conditions, not average. - **Don't add vendor number two before the consolidation layer is real.** The SCADA Silo doesn't go away in the cloud. It multiplies. Pick the consolidation layer first or accept you're building the problem. - **Don't let the data die in a dashboard.** If the pumper can't see the alert on his phone in under 30 seconds, the sensor money is wasted. - **Don't buy IoT to avoid a SCADA decision.** For supervisory control of a compressor station or gas plant, SCADA is still the right tool. IoT does not fix that conversation. ## Who This Is Not For **Operators expecting IoT to replace a serious SCADA investment.** It won't. For facility control, SCADA remains the right tool. IoT complements; it doesn't replace. **Operators deploying without addressing comms and power.** Site conditions drive success. Don't skip the site survey. **Operators without a clear "where does the signal go" plan.** If there's no plan for who gets notified, what they do with it, and how it integrates with the field team's existing tools, the sensors will stop getting read within months. ## Related Guides - [IoT in oil and gas](/blog/iot-in-oil-and-gas/): broader industry context - [IoT oil and gas products](/blog/iot-oil-and-gas-products/): the product landscape - [Digital oilfield](/blog/digital-oilfield/): the broader transformation framing - [Oilfield monitoring](/blog/oilfield-monitoring/): the monitoring category (TP-1 pillar) - [Oil and gas SCADA](/blog/oil-and-gas-scada/): supervisory control stacks (TP-2 pillar) - [Oil and gas automation](/blog/oil-and-gas-automation/): the automation category (TP-3 pillar) - [Oil and gas software](/blog/oil-and-gas-software/): the full software landscape (GB-1 pillar)

About the author: Greg Archbald is the founder of GreaseBook and TinyPumper. He built both products from inside the oil patch after watching operators spend 7-figure budgets on IoT deployments that never made it into the pumper's daily workflow. 15+ years on the operator side of oil and gas technology.

IoT is one piece. TinyPumper is the piece that replaces the SCADA install that never penciled.

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Two minutes. No sales call, no pushy follow-up. **P.S.** This page is not for a major running a corporate digital-oilfield program, or for a reservoir engineer shopping for simulation-grade telemetry. No hard feelings. If you're a producer looking at conventional wells where SCADA is either breaking down or never penciled in the first place, the quiz takes a minute and tells you honestly whether TinyPumper fits. ## Frequently Asked Questions **What is oilfield IoT in simple terms?** It is the combination of wireless sensors, cellular or LPWAN telemetry, and cloud platforms that collect data from oil and gas equipment and make it available to people and applications. In practice it overlaps with SCADA and automation; the word "IoT" emphasizes the cloud-first and sensor-first architecture. **Is IoT cheaper than SCADA?** For point measurements at remote sites, yes. A cellular tank level sensor can be deployed for a fraction of the cost of a full RTU-based SCADA install. For facility-wide instrumentation and control, SCADA is still usually the better economics once you have more than a handful of measurement or control points. **Can IoT replace SCADA?** On conventional wells where the math on SCADA never worked (or where aging SCADA is breaking down and costing more to maintain than it's worth), IoT is often the honest fit. On facilities that genuinely need real supervisory control (compressor stations, disposal wells, gas plants), no. IoT is complementary to SCADA at scale, not a replacement for it. **What are the biggest IoT deployment mistakes?** Underestimating comms coverage and power at remote sites, deploying sensors without a plan for who sees the data, and ending up with five different vendor cloud dashboards instead of one unified view. All three are preventable with upfront planning. **How does IoT data get to the pumper?** In the best setups, IoT alerts and dashboards integrate with the pumper's existing phone app (or with a text or push notification). Raw cloud dashboards that the pumper never opens are a sign that the integration with the field team got skipped. Mobile-first field data tools like [Greasebook](https://www.greasebook.com) and [TinyPumper](https://tinypumper.com) are common landing points for IoT signal to reach the person on the ground.

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TinyPumper is the SCADA alternative for conventional wells

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IoT is one piece. TinyPumper is the piece that replaces the SCADA install that never penciled.