# Greasebook — Full Content Dump Generated: 2026-10-27T19:43:37Z 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 Honest List of Companies and What Operators Use (2026) > Oil and gas software sorted by category and by operator size: which companies fit independents, what the enterprise names really do, and what to buy first. Source: https://www.greasebook.com/blog/what-software-do-oil-and-gas-companies-use/ Published: 2026-04-18 --- Published April 18, 2026 · Updated October 17, 2026 A Quorum rep left a voicemail this morning. A P2 rep left one right behind it. Your pumper still calls gauges in by phone, and nobody is selling a fix for that. **Short version:** the oil and gas software a company needs depends on its size. Majors run enterprise ERP and industrial SCADA. Independent producers, from a handful of wells to 2,000+, usually need three things: a production app that gets daily gauges off paper, purpose-built oil and gas accounting once partners show up, and a reserves tool when the bank asks. Most of a 200-vendor list is for a different company or a later purchase.

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## What is the best software for the oil and gas industry? It depends on your size and your problem. If your pumpers still report on paper or Excel, the best first buy is a production app like Greasebook. If you have partners and royalty owners, add an oil and gas accounting platform such as OGsys, PakEnergy, Bolo or SSI. If you run 1,000 to 10,000 wells, look at P2, Quorum or W Energy. If your real problem is not knowing what tanks do between pumper visits, TinyPumper is the better pick. If you are a major, SAP IS-Oil and industrial SCADA fit. ## What is oil and gas software? **Oil and gas software is any program a producing company uses to capture, report, account for, or act on what its wells do.** That covers eight categories, from the app a pumper uses at the lease to the ERP system a major runs in its headquarters. It is not one product. A tool that is great at one category is usually average at the next one, no matter what the sales deck says. | Category | What it does | Who needs it | |---|---|---| | **Production software** | Captures daily oil, gas and water volumes from the field and turns them into reports and trends. | Every producer. This is the foundation. | | **Production allocation** | Splits shared tank battery volumes back to each well, lease and owner. | Anyone with two or more wells on one battery, even at 100% ownership, plus anyone with partners. | | **Oil and gas accounting** | Joint interest billing (JIB), revenue distribution, severance tax, 1099s. | Any operator with outside working interest partners, royalty owners or multi-state tax. | | **Land management** | Leases, mineral rights, rentals, held-by-production tracking. | Operators with an active leasing program or a big acreage portfolio. | | **Production data management and reserves** | Decline curves, forecasts, reserve reports. | Engineers, lenders, anyone buying or selling wells. | | **Oilfield monitoring** | Sensor readings from tanks, pressures and equipment between pumper visits. | Remote leases, long drives, theft or spill exposure. | | **SCADA** | Industrial monitoring and control, tied to field networks. | Large operators with controls staff, gathering systems, high-volume wells. | | **ERP** | One suite tying finance, land, procurement and operations together. | Majors and large independents with dedicated IT. | Most independents need two or three of these. Very few need all eight. ## What software do oil and gas companies use? The software used in oil and gas industry operations depends on how big the company is. For field operations, most producers run a phone-based field data capture app their pumpers carry, and larger ones also pull readings from SCADA. Here is what we actually see sitting next to our software in back offices across the country. ### Majors and supermajors - **ERP:** SAP IS-Oil or Oracle JD Edwards. - **Reservoir and engineering:** SLB Petrel, Eclipse, CMG. - **SCADA and automation:** Emerson, Honeywell, ABB, AVEVA. - **Field capture:** usually pulled from SCADA or built in-house. License costs run in the millions and rollouts take years. This is a different world from an independent operation, and the software reflects it. ### Large independents (roughly 1,000 to 10,000 wells) - **Accounting and ERP:** P2, Quorum, W Energy or Enertia. - **Reserves:** OFM, Val Nav, ComboCurve. - **Production capture:** a mix. Some run Greasebook, some run a capture module inside their ERP, some built their own. - **SCADA:** on the high-volume wells, often skipped on the marginal ones. These are sophisticated buyers who chose tools for real complexity. They still need a field-first production layer, because ERP capture modules were not built for a pumper at the well. For the rest of what this group runs, see our guide to [upstream oil and gas software](/blog/upstream-oil-and-gas-software/). ### Small and mid-size independents (a handful of wells to about 1,000) - **Accounting:** a mid-range oil and gas platform such as OGsys, PakEnergy (formerly WolfePak), Bolo or SSI. SSI is an alternative to PakEnergy that operators have had a lot of success with, and its Well History reporting tracks per-well profit trends over a rolling twelve months in a way no other oil and gas accounting system matches. - **Production capture:** Greasebook, Scout FDC, or still paper and Excel. - **Allocation:** inside the production app, inside the accounting platform, or a spreadsheet built around monthly well tests. - **Reserves:** ComboCurve, PHDwin or Excel decline templates. - **Land:** usually a spreadsheet and a filing cabinet. - **Monitoring:** sensors on the tanks and wells that are hardest to reach, or nothing yet. QuickBooks plus a CPA shows up at the very smallest, solo-owner end. It is a stopgap. The minute working interest partners, JIB, royalty owners or multi-state tax enter the picture, purpose-built oil and gas accounting is table stakes. Our page on [oil and gas software for small business](/blog/oil-and-gas-software-for-small-business/) walks through that stack in more detail. ## Which oil and gas software companies fit independent producers? Search "oil software companies" and the top results are enterprise vendors and directories listing 400 names with no filter. Most oil industry software lists are built that way. The shortlist that matters for an independent operation is much smaller. | Job | Companies independents actually evaluate | Fits best | |---|---|---| | **Production capture and reporting** | Greasebook, Scout FDC, IHS FieldDirect, Productioneer | Producers with pumpers in the field, any well count | | **Oil and gas accounting** | OGsys, PakEnergy, Bolo, SSI | Operators with partners, royalty owners or multi-state tax, up to about 1,000 wells | | **Accounting at larger scale** | P2, Quorum, W Energy, Enertia | Operators from about 1,000 to 10,000 wells | | **Production allocation** | PakEnergy Allocate, Greasebook, Avocet | Shared tank batteries and split ownership | | **Reserves and decline curves** | OFM, ComboCurve, PHDwin, Val Nav | Engineers, lenders, acquisitions | | **Remote monitoring** | TinyPumper, plus legacy SCADA vendors like eLynx and ZDSCADA | Wells and tanks between pumper visits | Every other name on a generic "top 50" roundup either serves a different buyer (majors, midstream, refiners) or is a directory re-ranking the same handful of companies. For a ranked look by job, see [the best oil and gas software for independent producers](/blog/best-oil-and-gas-software/). ### What do the enterprise names actually do? - **Quorum.** Accounting, land and asset management for operators with hundreds to thousands of wells and a full back office. - **Enverus (which now owns P2).** Data, analytics, land and production accounting. Strong for acquisitions and larger independents. - **AVEVA, Emerson, Honeywell.** Industrial automation and SCADA for refineries, pipelines and high-volume upstream assets. - **SAP IS-Oil.** ERP for majors. For an independent producer it is overkill by a wide margin. None of these are bad products. They are built for a different buyer. If one of them calls, take the call. Just know you would use a slice of what you pay for. ## What is on most software lists that independents can skip? Three categories fill up every "oil and gas software list" and almost never apply to a producing company running conventional or horizontal wells it already owns: - **Seismic interpretation** (Petrel, Kingdom). For exploration teams. - **Reservoir simulation** (CMG, Eclipse). For reservoir engineers at large operators. - **Drilling, engineering and design software** (well planning, piping and facility design tools). For drilling programs and engineering firms. If those are not your job, skip those sections on every list you read. ## What are the best oilfield software alternatives? Most operators searching for an alternative already left paper. They run a legacy desktop system, older [E&P software built for the office instead of the lease](/blog/ep-software-greasebook-ep-software/), or the production module inside their accounting suite, and they fight it twice: once to get data in, once to get answers out. The real objection to switching is never the upside. It is the lift. What the switch should look like: - **You hand over a login.** Our petroleum engineers build out your wells and surface equipment first. Once your pumpers give feedback on their routes and your supervisor signs off, we scrub, clean and backfill your history. You do not re-key anything. - **Your old contract is not a reason to stay.** Greasebook buys out the months left on it, in exchange for a one-year term plus the bought-out months. - **It is done in about a week.** Most operators are fully rolled out within a week, and 98% of operator trials succeed. Pumpers use the phones they already carry. Comparing a specific system? See the [Scout FDC](/blog/scout-fdc-alternative/), [PakEnergy pumper app](/blog/pak-energy-comparison/) and [W Energy](/blog/wenergy-comparison/) pages. ## Which categories does your operation actually need? Two questions decide most of it: do you have outside partners and royalty owners, and do several wells feed the same tank battery? **No partners, simple ownership.** You need production software first. Your leases can live in a spreadsheet. Allocation still matters if wells share a battery, because the tank reading only tells you the battery total. A monthly well test in a clean spreadsheet covers that until the number of batteries gets ugly. **Partners, royalty owners, several batteries.** You need production software, purpose-built oil and gas accounting, and real allocation. Add a reserves tool when you are buying wells or reporting to a lender. If your leasing program is active, [oil and gas land management software](/blog/oil-and-gas-land-management-software/) explains when a spreadsheet stops being enough. **Remote or spread-out leases.** Monitoring becomes a question of geography, not well count. If your pumpers drive an hour between tanks, sensors on the hardest-to-reach sites pay for themselves fast. ## What should you buy first? 1. **Production software.** Nothing downstream works without clean, same-day production data. Allocation, accounting, state reports and reserves all run off it. Start with [what independents actually need from oil and gas production software](/blog/oil-and-gas-production-software/). 2. **Oil and gas accounting software,** once partners, JIB or royalty owners exist. 3. **Allocation,** when shared batteries and split ownership outgrow the spreadsheet. 4. **Reserves and data management,** when you forecast, borrow, buy or sell. 5. **Monitoring, SCADA or automation,** when the drive time, theft or reliability math pays it back. ## What features should software for oil and gas companies have? Whatever the category, five things separate software that gets used from software that gets shelved: 1. **It works where the work happens.** Offline on a phone at the lease, then syncs when it finds signal. 2. **It catches bad numbers early.** Alerts when a reading is out of line, not a surprise at month end. 3. **It talks to your other systems.** Clean exports or integrations to the accounting platform and reserves tool you already run. 4. **Someone else does the setup.** Ask who builds your wells into it, and how long that takes. 5. **The vendor stands behind it.** A trial on real wells, or a guarantee, beats a slide deck. ## Is there free oil and gas software? Honestly, not for the job that matters most. Free spreadsheet templates, open-source engineering tools and free trials exist. There is no serious free option for daily production capture on a real operation, because someone has to answer the phone when a pumper cannot sync and someone has to keep the data clean. Greasebook is not free either. Our page on [free oil and gas software](/blog/oil-and-gas-software-free/) covers what free tools can and cannot do. ## Where does oil and gas software overshoot? - **Oil and gas ERP software below about 1,000 wells.** The workflow an ERP replaces (many disconnected systems tied together by hand) rarely exists at that size. A production app plus a mid-range accounting platform does the job for less. - **All-in-one suites.** Accounting platforms ship production modules. ERPs ship capture modules. Each one is a jack of all trades and a master of none outside its home category. Integrate the best tool for each job instead. - **SCADA on every well.** It earns its keep on high-volume wells. On marginal wells, the hardware and upkeep often cost more than what it saves. ## How do the best operators build a software stack? | The amateur... | The pro... | |---|---| | Copies a supermajor's stack at a fraction of the size | Copies operators at their own size and well mix | | Treats the accounting suite's production module as the production system | Runs a field-first production app and feeds the accounting platform clean data | | Reads a vendor list top to bottom and books five demos in a week | Starts with the workflow that hurts most and only reads that section | | Signs a three-year contract after a 45-minute demo | Lets the pumpers use the product on real wells before signing past a year | | Keeps QuickBooks after partners and JIB show up | Moves to purpose-built oil and gas accounting the day complexity arrives | ## What should you avoid before you call vendors? - **The Bolt-On Trap.** The production module inside an accounting suite was built for the back office, not for a pumper in a truck at 5 a.m. Use it for accounting. Use a production app for production. - **The Paper Lag.** If your numbers run two to three weeks behind because pumpers mail in tickets, the fix is not a fancier report. It is getting capture off paper. The same goes for legacy desktop systems like FieldDirect that make the pumper key data from home at night instead of at the well. - **Buying on logo.** A vendor that sells to majors is not automatically a better fit. Ask for references at your size. - **Buying for the company you wish you ran.** Size the software to the operation you actually have. Operators tell us the same things on almost every first call: "Managing Excel sheets is overwhelming." "Our pumpers mail in tickets, and we are at the mercy of the mail system." "We need a centralized system for production reporting, taxes, and reconciliations." All three are capture problems first. ## Where does Greasebook fit? Greasebook is the production layer. Pumpers log gauges, pressures, run tickets and photos on the phone they already carry, offline if they have to, and the office sees it the same day. Allocation by well and lease, downtime tracking and state production reports for any oil and gas producing state, prepared and ready for you to submit, come out of the same data. If your state's form is not built yet, we build it at no cost. If you are looking for an oil and gas collaboration tool, this is usually what you mean: one place where the pumper, the office and the owner see the same numbers, with comments and photos attached to the well. Greasebook also sits comfortably next to [the complementary oilfield apps independent operators already run](/blog/oilfield-apps-greasebook-complementary-oilfield-apps-independent-operator/). **Greasebook facts, as of October 2026:** 600+ production companies trust us with their data. Greasebook has 10,000+ pumpers in the field. Greasebook has 15 years in the oil patch. Greasebook has 220 million+ barrels tracked. Greasebook serves 22 oil-producing states across the union. The average pumper learning curve is 8 minutes. Operators see a 6% pump-to-net improvement in 6 weeks. Greasebook carries a 200% money-back guarantee: doesn't work, we pay you double. Our petroleum engineers build your company out for you. TinyPumper is Greasebook's sister product. Greasebook does not do accounting. It integrates with every major oil and gas accounting platform and with PHDwin, so clean production data flows straight into the system your back office already runs. **Sister product:** if your real problem is not knowing what tanks, pressures and equipment are doing between pumper visits, that is [TinyPumper](https://www.tinypumper.com/). It is self-installed remote monitoring hardware, the SCADA alternative for conventional wells. Many producers run both: TinyPumper watches the wells, Greasebook holds the production record. Going deeper on one category: - [Oil and gas production software: what independents actually need](/blog/oil-and-gas-production-software/) - [Production data management software](/blog/oil-and-gas-production-data-management-software/) and [OFM software](/blog/ofm-software/) - [Production allocation software](/blog/best-oil-and-gas-production-allocation-software/) - [Oil and gas production accounting software](/blog/oil-and-gas-accounting-software/) - [Oil and gas software for small business](/blog/oil-and-gas-software-for-small-business/) and [free oil and gas software](/blog/oil-and-gas-software-free/) - [Upstream oil and gas software](/blog/upstream-oil-and-gas-software/) and [land management software](/blog/oil-and-gas-land-management-software/) - [State production reports](/blog/oil-and-gas-regulatory-production-reports/) - Monitoring and control: [oilfield monitoring](/blog/oilfield-monitoring/) and [oil and gas SCADA](/blog/oil-and-gas-scada/) ## Who this page is not for This page is not for midstream, pipeline or refining operators. It is not for reservoir or drilling engineers shopping simulation, seismic or design software. It is not for IT teams at majors comparing enterprise ERP. It is for producing companies, from a handful of wells to 2,000+, trying to figure out what the rest of the industry runs and what to add next. ## Frequently Asked Questions **What software do oil and gas companies use?** It depends on size. Majors run ERP such as SAP IS-Oil, reservoir tools like Petrel, and industrial SCADA from Emerson or Honeywell. Larger independents run P2, Quorum, W Energy or Enertia. Small and mid-size independents run a production app like Greasebook or Scout FDC next to a mid-range accounting platform such as OGsys, PakEnergy, Bolo or SSI, plus a reserves tool when they need one. **What is the best ERP software for the oil and gas industry?** For majors, SAP IS-Oil and Oracle JD Edwards are the usual picks. For large independents running roughly 1,000 to 10,000 wells, P2, Quorum, W Energy and Enertia cover accounting, land and operations. Below that size most producers do not need an ERP at all. A field-first production app plus a mid-range oil and gas accounting platform does the same work with far less overhead. **What are the top oil and gas software companies?** For independent producers: Greasebook and Scout FDC for production capture; OGsys, PakEnergy, Bolo and SSI for accounting; OFM, ComboCurve and PHDwin for reserves; TinyPumper for remote monitoring. For majors and large operators the list shifts to Quorum, Enverus, AVEVA, Emerson and SAP. The two lists barely overlap, which is why generic rankings rarely help a producer. **Is there free oil and gas software?** Free spreadsheet templates and open-source engineering tools exist, and most commercial products offer a trial. There is no serious free option for daily production capture on a real operation, because someone has to answer the phone when a pumper cannot sync and someone has to keep the data clean. See our page on [free oil and gas software](/blog/oil-and-gas-software-free/) for what free tools can and cannot do. **What should I look for when comparing oil and gas software providers?** Start with the job that hurts most, then ask four questions. Will my pumpers actually use it in the field, offline? Does it integrate with the accounting platform we already run? Who sets it up, and how long does it take? What happens if it does not work? A vendor that will not let your pumpers try it on real wells, or will not stand behind it with a guarantee, is telling you something. **Does every oil and gas company use SCADA?** No. Majors and midstream companies run SCADA across most assets. Larger independents usually run it on high-volume wells and skip it on marginal ones. Many small and mid-size producers run none, relying on pumper capture plus lighter remote monitoring on the hardest-to-reach sites. SCADA pays off where well volumes and downtime or theft exposure justify the hardware and upkeep.

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.

## Ready to Find Out What Fits Your Operation? Take the quiz. It asks about your wells, your team and how your pumpers report today, and tells you whether Greasebook fits. If it does, 15 minutes with a real production engineer gets you your exact price. [Take the Greasebook quiz](https://quiz.greasebook.com/quiz). If it turns out to be the wrong fit, the 200% money-back guarantee pays you back double. ===================================================================== # Oil Production Software: Best Picks, Free Options and How It Works (2026) > The honest guide to oil production software for independent operators running 2 to 2,000 wells: the best picks, what free really gets you, and how it works on the lease. 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 is the problem oil production software is supposed to solve. **The short version:** oil production software (also called oil and gas production software) gets daily gauges, run tickets, pressures and downtime from the lease to the office the same day, then turns them into reports, allocation and state filings. For independent operators running anywhere from 2 to 2,000 wells, the best fit is a phone-based app your pumpers will actually open, that works with no cell signal, and that feeds the accounting system you already run. Greasebook is built for exactly that. Free options exist only at the edges (Excel templates, regulator forms, reservoir simulators), and none of them closes the daily capture loop. Enterprise suites work for majors, not for most independents. **This post is for you if:** - Your production data runs more than 48 hours behind the field and you want that gap closed. - You run anywhere from a handful of wells to 2,000+ and you are stuck between "Excel is held together with tape" and "the enterprise suite wants a year-long project." - Your back office re-keys paper gauge sheets into spreadsheets at 9 p.m. and you are tired of paying for that work twice. - You want the honest read on the best options, the free options and the real costs before you sit through another 45-minute demo. One operator put it to us this way on a discovery call: "Our pumpers mail in tickets, and we are at the mercy of the mail system." If that sounds like your week, keep reading.

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## What is oil production software? Oil production software is the system that captures daily oil, gas and water volumes from the field and turns them into the reports every other part of the business runs on. It is the front door for allocation, accounting, state filings and engineering. If it breaks, everything downstream breaks with it. People search for it under a lot of names: oil and gas production software, oil field production software, oil and gas production reporting software, oil production management software, oilfield daily log software, well production software. They all describe the same job. ## What does oil production software do on the lease? Production software sits between three groups who rarely talk in plain English: pumpers in the field, admin in the office, and the owner or engineer looking at the numbers. Its job is to make all three agree on what happened yesterday. Here is what a good day looks like when it works: 1. **Start of the route.** The pumper opens the app on his phone. The day's wells are already loaded. 2. **At each well.** He gauges the tank, records oil, water and gas, takes pressures, snaps a photo of the run ticket and codes any downtime. If there is signal, it syncs. If not, the app holds the data until signal comes back. 3. **End of the route.** Everything is synced. Nobody drives to the office to re-enter numbers. The office has the day's production by lunch. 4. **Back office.** Daily production, downtime and run ticket reconciliation are current. State reports build from the same numbers. Month-end close takes a day, not a week. Anything that makes the pumper drive to an office to re-enter data has the wrong design. Anything that needs steady cell signal has the wrong design. Anything that takes days of training per pumper has the wrong design. ## How does production software catch bad readings? A fat-fingered gauge is cheap to fix the day it happens and expensive to find in month three. Good production software checks at the source: - **Every reading carries proof.** A timestamp, the pumper's location and a run ticket photo. - **Geofencing.** It confirms the pumper stood on the lease. - **Alerts on the odd number.** Greasebook's alert engine flags a reading that falls out of line with the well's history, so the office asks about it while the pumper still remembers. ## How does production software track downtime and lost production? The pumper codes downtime at the well, with the reason, the moment he sees it. Greasebook's downtime tracker rolls those codes up by well and lease, so you can see which wells keep going down and how many barrels it cost. That is the list you fix first, and the data your engineer needs for forecasts in PHDwin. ## What are the main types of oil production software? There are hundreds of oil and gas software companies, and their production products all land in three camps, no matter what the sales rep calls them. (For the full map of vendors and categories, see [what software oil and gas companies use](/blog/what-software-do-oil-and-gas-companies-use/).) ### 1. Paper and Excel Most small operators start here and many stay longer than they should. Pumpers call or text in numbers, somebody types them into Excel, and someone signs the state form by hand. **It works when:** you run a few wells, you know every pumper by his truck, and only one or two people touch the file. **It breaks when:** you add a second or third pumper, take on partners, split production across owners, or miss a state filing because someone was on vacation. Excel is paper with a power cord. It feels like software (it is digital, it is backed up), so operators trust it long past its breaking point. The double entry never goes away, every route ends up with its own format, and a fat-fingered cell has nothing to catch it. ### 2. Phone-based production apps (field data capture) This is where Greasebook lives. The pumper records well data on his phone as he gauges, and the office sees it within minutes. The data flows into reports, allocation and state filings without being re-typed. **It works when:** you have pumpers in the field (company, contract or both), anywhere from a handful of wells to 2,000+, and you want the office to see production the same day without building your own data pipeline. Horizontal operators running SCADA on their best wells plug Greasebook in too: field-entered data and SCADA data land on one screen. **It breaks when:** your company is a major standardized on an enterprise ERP that demands native modules, or your pumpers truly refuse to touch a phone. That last one gets rarer every year. ### 3. Enterprise production suites PakEnergy (formerly WolfePak), Peloton, Enertia, Quorum and a few others sit at the top of the market. They bundle production with accounting, land and sometimes reserves into one stack. They are serious tools for serious budgets. **It works when:** you have a dedicated IT team, a controller who wants one vendor for everything, and the budget and patience for a long implementation and multi-year contract. **It breaks when:** a small or mid-size independent gets sold the enterprise dream. The rollout drags for months, most features sit unused, and the pumpers quietly go back to paper because the field app was an afterthought. ## What is the best oil production software? Review sites rank production software next to reservoir simulators, land tools and project-management apps, because "oil and gas" is one bucket on their side. That is scoring apples against wrenches. For an independent operator, the best oil production software comes down to five things: 1. **Pumper adoption.** If the pumpers on a route are not using it inside two weeks, the rollout failed. 2. **Lease-to-office speed.** Same day is the bar. 3. **Offline reliability.** If a sync error loses a reading, that is the whole relationship. 4. **Support.** When a pumper cannot sync at 6 p.m. on a Friday, someone has to answer. 5. **Three-year cost.** License plus setup plus training plus integration plus renewal, not just the sticker. Score that way and the shortlist for independents gets short: | Platform | Best fit | Pumper learning curve | Notes | |---|---|---|---| | **Greasebook** | Independents with pumpers in the field, 2 to 2,000+ wells | About 8 minutes | Works offline. Prepares state reports for any producing state. 200% money-back guarantee. | | **Scout FDC (PakEnergy)** | Operators already running other PakEnergy modules | Days to weeks | Heavier install. Fits shops on the PakEnergy stack. | | **FieldCap** | Mid-size operators who want production and allocation from one vendor | Weeks | One vendor covers both jobs. | | **WellEz** | Engineering-heavy operators | Weeks to months | Strong engineering features. More than most independents need. | | **IFS Production Operations** | Large independents on the IFS ERP | Months | Part of a broader ERP. Usually the wrong size for independents. | ### Why Greasebook leads the list for independents Production software has one failure that kills it no matter how good the demo looked: the pumpers will not use it. Greasebook is built to clear that bar. - **About 8 minutes to learn.** If he can text, he can use Greasebook. We have trained more than 3,000 pumpers, including 75-year-olds who had never owned a smartphone. - **Works offline.** It captures data with no bars and syncs when signal returns. - **Geofencing.** It confirms the pumper actually stood on the lease. Trust, but verify. - **Turnkey setup.** Our petroleum engineers build out your company. You send tank sizes, well names and pumper contacts. Most operators are fully rolled out within a week. - **Real lift, fast.** Operators moving onto Greasebook average a 6% pump-to-net improvement in 6 weeks. Half do better. ### When another platform makes more sense - **You already run several PakEnergy modules.** Scout FDC may plug in more simply. Look at both before you decide. - **You want production and allocation from one vendor and your allocation is unusual.** FieldCap is a fair pick. - **You have an in-house engineering team driving the purchase.** WellEz leans toward engineering workflow. ## What is the best oil production software for small business? Pick the tool your first pumper will use on day one, not the one built for the company you hope to be in ten years. A small operator or a new one needs three things right away: daily gauges and run tickets off paper, state reports ready on time, and a clean production history from the first barrel. A phone-based app does all three without a project. An enterprise suite turns a young company into an IT shop. Starting digital is also cheaper than migrating later. Several operators have told us some version of "we want to go digital from the start and simplify our production data management." That is the right call. Moving three years of messy spreadsheets later is the painful version. For the rest of the small-shop toolkit, see [oil and gas software for small business](/blog/oil-and-gas-software-for-small-business/). ## Is there free oil production software? Not for the daily capture job. The free results on Google fall into four buckets: 1. **Open-source reservoir simulators** (OPM, UTCHEM, BOAST). Free and useful for reservoir modeling. They do not capture field production. 2. **Spreadsheet templates.** Gauge sheet and monthly summary templates float around forums. Free license, expensive hours. 3. **Regulator forms.** State production report forms are free to download. Filling them out by hand is not free. 4. **Decline curve tools.** Arps decline templates in Excel and open-source Python libraries work for a small shop that plots decline once a quarter. None of those gets a gauge from the lease to the office the same day. That job needs offline sync, field support and someone keeping the app current as phones and state formats change. Nobody does that work for free. ### What "free" actually costs Here is the pattern we see when a shop tries to run production on free tools: - **Month one.** Paper gauge sheets, re-keyed into Excel. Looks fine because the load is light. - **Month three.** A transposed number. A missing run ticket. Close takes six days instead of three. - **Month six.** The accountant has built a reconciliation workbook only she understands. When she takes a vacation, close slips a week. - **Month twelve.** Somebody notices three leases trending below their decline and starts hunting for the lost barrels. Excel never sends an invoice. That is exactly why operators think it is free. The real bill is clerk hours keying the same numbers twice, downtime hiding in stale files, run tickets that will not reconcile and wells that slip while the truth sits in someone's inbox. It is the most expensive free software in the oil patch. ### The closest thing to free that still works Greasebook takes the risk off the table instead of pretending the work is free. Cold feet inside 30 days? Full refund, no questions asked. Run it for a full 6 weeks and do not see results? We do not just refund you. We pay you double what you paid. ## Can a spreadsheet replace production software? For a few wells and one pumper, yes, and plenty of operators do it. The day it stops working is usually the day you hire a second pumper, add a partner or miss a filing. One operator told us, "Managing Excel sheets is overwhelming." That is the sound of a spreadsheet past its breaking point. The fix is not a fancier spreadsheet. It is getting the number captured once, at the well, by the person standing in front of it. ## Why does pumper adoption decide whether production software works? The buyer is the producing company. The pumper is the user. If the user does not adopt it, the buyer's investment is dead on week two, no matter what the sales deck said. So the software has to respect how the field works: - **Muddy hands, bad light.** Big buttons, a screen that works in the cab at 5 a.m. - **A full route.** Twelve wells and a truck due back by noon. The app has to be faster than paper. - **No arguments with the office.** Every reading carries its own proof (see above), so the office stops second-guessing every gauge. Greasebook gives pumpers a feedback loop too. They see each well's history and past comments on their phone while they are standing in front of the well, the best possible time to notice something is off. Pumpers get shorter days and no mail-in tickets. The producer gets clean, same-day numbers. ## What does a real oilfield production software solution have to do? Strip the "solutions" branding off any vendor deck and three jobs are left. A tool that fails any one of them is not ready for an independent operation. **1. Capture at the lease, not the office.** The pumper records data at the well. A system that forces data entry back at the office (paper, or software that needs a laptop) has a hidden labor cost that eats the whole point. Everyone carries a phone now. There is no reason to key data from home. **2. Sync in real oilfield conditions.** Signal drops in the canyon and fades on lease roads everywhere oil and gas is produced. The app must keep capturing offline and sync cleanly when signal returns. Ask to see it run in airplane mode. **3. Feed clean data downstream.** Production volumes flow into allocation (splitting commingled volumes by well, and testing per-well productivity on shared tank batteries) and then into the accounting system. If the export needs two days of cleanup, the office is back to the work it was trying to stop. When Emerson, AVEVA, IFS or SAP sell an "oil and gas production solution," they mean an industrial platform tied to PLCs and their own asset stack. That is a real product for refineries, pipelines and high-volume assets with controls staff. It is not built for a producer whose pumper runs a 12-well route. ## How is oil production software priced? Most vendors do not publish prices, and the ones built for majors quote implementation projects. Here is how Greasebook prices, so the number never comes as a shock: - **The unit.** Per well or per pumper, per month. Per-pumper often fits gas-heavy and shallow, low-volume operations. Per-well fits most oil operations. We pick the right one after a few questions. - **Office users are always free.** Owners, engineers and admin never count. - **What moves the price.** How many wells you run, how many pumpers cover your routes, and what you need to track. - **The comparison.** It typically runs a fraction of one pumper-hour per well per month. The 60-second quiz tells you whether you are a fit. If you are, 15 minutes with one of our production engineers gets you your exact price.

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## What should you look for when buying production software? Most checklists online were written by vendors to win RFPs. The operator's checklist is shorter. 1. **Can a pumper who has never seen it be productive in minutes?** If the answer is "we have a great 3-day training program," that is a red flag. 2. **What happens when cell service drops?** It has to work offline, hold the data and sync when signal returns. 3. **How fast does the office see field data?** Next morning means you bought a paper replacement. Same day means you bought production software. 4. **Who answers when something breaks at 6:30 a.m.?** Ask for the support line and call it during the demo. Greasebook's help desk is staffed by petroleum engineers, completions experts and a geologist. 5. **What does it cost to leave?** Ask how your data comes out if you switch. Some operators find out too late that years of history are locked in a format nobody else reads. 6. **Will it work with the accounting system you already pay for?** Greasebook integrates with every major oil and gas accounting platform: PakEnergy, OGsys, Bolo, SSI, P2 and the rest of the majors you would expect, plus PHDwin for decline curves. Run something we did not name? If it is a major platform, we already talk to it. ## Amateur vs pro: how operators buy production software | The amateur... | The pro... | |----------------|------------| | Shortlists from a review-site ranking | Shortlists by pumper adoption, lease-to-office speed and how clean the data lands in accounting | | Picks the platform the rep pushed hardest in the boardroom demo | Puts the pumpers in the demo and tests the app in airplane mode | | Treats the accounting vendor's production module as the production system | Runs a dedicated production app and feeds the accounting system clean data | | Signs a three-year contract for the "best price" | Prices three-year total cost, including what it costs to leave | | Stays on Excel three years past the breaking point | Moves the week the second pumper is hired and the errors start climbing | | Assumes SCADA on the best wells covers the whole operation | Puts SCADA data and pumper-entered data on one screen so office and field see the same numbers | ## What oil production software is not Several categories show up on the same search results page. None of them does the daily capture job. - **SCADA and remote monitoring.** SCADA in oil and gas is the sensor and control network that pushes pressures, flows and tank levels from the field on its own. Great for what sensors can measure. It does not record run tickets, visual checks or the pumper's notes. Greasebook works alongside SCADA, and for conventional wells where SCADA never made sense, our sister product TinyPumper monitors tanks, pressures and runtime around the clock. - **Reservoir simulation and design software.** Petrel, CMG and Eclipse model the reservoir, and CAD tools design facilities. Different job, different buyer. - **Land management.** Lease rights and title tracking. No overlap. - **The accounting ledger.** Billing partners, cutting distributions and JIB belong in your oil and gas accounting system. Greasebook handles the production side (run ticket and purchaser reconciliation, allocation by well and lease, downtime, state reports, production reporting) and hands the accounting system clean numbers. Keep your accounting software. We make it better. ## What to avoid before you buy - **The Bolt-On Trap.** The production module inside your accounting platform was built for the accounting workflow, not a pumper in a truck at 5 a.m. It is a jack of all trades, master of none. Run a dedicated production app and feed the accounting system you already have. SSI users and PakEnergy users alike run Greasebook this way. - **The Paper Lag.** Two to three weeks between gauge and dashboard is not "how the field works." It is the gap production software exists to close. - **Buying on price alone.** An app that loses two run tickets a month costs more than one that does not. Cheap that fails in a dead zone is the most expensive kind. - **Skipping offline mode.** A demo that only runs on boardroom wi-fi is hiding what happens at a battery with no bars. - **Buying for the company you wish you were.** Size the software to the operation you actually run. - **The QuickBooks stopgap.** QuickBooks plus a homegrown spreadsheet breaks the minute working-interest partners, royalty owners or multi-state filings show up. Real complexity needs real oil and gas accounting software, fed by real production data. ## Who this guide is not for This page is for independent producers running conventional and horizontal wells. It is not the right guide for a supermajor, a refinery, a midstream or pipeline company, or a shop already standardized on SAP for production. It is not for reservoir engineers shopping simulation software or land teams shopping title tools. And if you own royalty interest but operate nothing, you need your operator's allocation reports, not production software. ## How production software fits the rest of the stack Production software is the layer everything else reads from. - **Allocation.** Daily per-well volumes drive commingled allocation and per-well testing. See our guide to [production allocation software](/blog/best-oil-and-gas-production-allocation-software/). - **Accounting.** Your accounting system is only as honest as the volumes feeding it. - **State reports.** Monthly forms like the [Texas RRC PR](/blog/texas-rrc-pr-form/) and [Oklahoma OCC Form 300R](/blog/oklahoma-occ-form-300r/) build straight from production volumes. Greasebook prepares state production reports for any oil and gas producing state, ready for you to submit, and if your state's form is not built yet, we build it at no cost. See the [state-by-state reporting guide](/blog/oil-and-gas-regulatory-production-reports/). - **Engineering.** Decline curves and forecasts start from a clean production history. Greasebook feeds PHDwin. - **Data management.** At scale you may want a historian or warehouse. See [production data management software](/blog/oil-and-gas-production-data-management-software/). For the wider map of tools producers run, see [what software oil and gas companies use](/blog/what-software-do-oil-and-gas-companies-use/), our [picks for best oil and gas software](/blog/best-oil-and-gas-software/), and [oil and gas software for small business](/blog/oil-and-gas-software-for-small-business/). ## The facts about Greasebook Greasebook (some operators search it as "grease book oil and gas") is oil production software used by more than 600 production companies and 10,000+ pumpers, built over 15 years in the oil patch, with more than 220 million barrels tracked. Pumpers learn it in about 8 minutes, and office users are about 99% proficient in 20 minutes. It prepares state production reports for any producing state and builds a missing form at no cost. It is backed by a 200% money-back guarantee and a 98% operator trial success rate. Its sister product, TinyPumper, adds 24/7 remote monitoring, and its data flows into the same Greasebook dashboard. ## Field-side guides that teach the numbers your software captures Production software is only as honest as the data the pumper puts into it. These guides cover what that data describes at the tank battery. - [Gauging equipment every pumper should know](/blog/gauging-equipment/) - [Operating and servicing pumping units](/blog/operating-servicing-pumping-units/) - [Lease pumper's basic guide to plunger lifts](/blog/lease-pumpers-basic-guide-plunger-lifts/) - [Separators, heater-treaters, and pressure](/blog/separators-heater-treaters-pressure/) - [Servicing an oil and gas production well](/blog/servicing-oil-gas-production-well/) - [Tubing string basics and maintenance](/blog/tubing-string-basics-maintenance/) - [Manually starting an old Arrow C96 pumping unit](/blog/greener-pastures-and-manually-starting-an-old-arrow-c96-pumping-unit/) - [The boiler-house method of pumper production reporting](/blog/pumper-production-reporting-boiler-house-method/) - [The lease pumper handbook](/blog/lease-pumper-handbook/) - [11 important things for oil field lease maintenance](/blog/11-important-things-oil-field-lease-maintenance/) ## Frequently asked questions ### What software do oil companies use? Independent producers most often run a phone-based production app such as Greasebook, Scout FDC or FieldCap for daily field capture, then feed an oil and gas accounting platform like PakEnergy, OGsys, Bolo or SSI. Larger operators sometimes run production inside an enterprise suite such as Enertia, Peloton or IFS. Majors use enterprise platforms tied to industrial SCADA. Many shops still run some or all of their production on paper and Excel. ### Who are the big 5 in oil? The big five, often called the supermajors, are ExxonMobil, Chevron, Shell, BP and TotalEnergies. They run enterprise production platforms tied to industrial SCADA and large in-house IT teams. Independent producers are a different business: smaller teams, conventional and horizontal wells, and no appetite for a year-long software project. This guide is written for the independents, the operators running anywhere from 2 to 2,000 wells. ### What is the best software for oil and gas production accounting? It depends on which half of the job you mean. For the production side (run ticket and purchaser reconciliation, allocation by well and lease, downtime and state reports), a dedicated production app like Greasebook does it without a bulky suite. For the ledger side (partner billing, distributions, JIB), you need real oil and gas accounting software such as PakEnergy, OGsys, Bolo or SSI. Most producers run both, with production data flowing straight in. ### What is the best design software for the oil and gas industry? It depends on what you are designing. Facility and plant engineers use CAD tools such as AutoCAD Plant 3D or AVEVA. Subsurface teams use Petrel or similar tools for geology and reservoir models. None of those captures daily production. Once a well is producing, the job changes to recording gauges, run tickets and downtime every day, which is where oil production software like Greasebook comes in. ### Is there free oil production software? Not for daily field capture. Free tools exist at the edges: Excel templates, state regulator forms, decline-curve spreadsheets and open-source reservoir simulators. None of them gets a gauge from the lease to the office the same day, because that takes offline sync, support and constant upkeep. The lowest-risk way to try real production software is a strong guarantee. Greasebook offers a 30-day full refund and a 200% money-back guarantee after six weeks. ### Can I use a spreadsheet instead of production software? You can, and many small operators do for a few wells and one pumper. It usually breaks when you add a second pumper, take on partners or miss a state filing. The hidden costs are double entry, version chaos between routes and errors nothing catches at the source. Excel never sends an invoice, which is why it feels free, but the clerk hours and missed downtime are the real bill. ### How long does it take to roll out production software? With Greasebook, most operators are fully rolled out within a week. Our petroleum engineers build your company from your tank sizes, well names and pumper contacts. Pumpers learn the app in about 8 minutes, and office users are about 99% proficient in 20 minutes. If a vendor quotes a months-long implementation for an independent operation, you are being sold enterprise overhead you do not need. ### Will production software file my state reports? It can do the hard part. Greasebook prepares state production reports for any oil and gas producing state, built straight from the numbers your pumpers already entered, so nobody re-keys data for the regulator. You review the report and submit it. If your state's form is not built yet, we build it at no cost, because if you need it, somebody else will too. That ends the month-end scramble. ### Does oil field production software work offline? The good ones do, and you should not buy one that does not. Leases sit in canyons and dead zones everywhere oil and gas is produced. Greasebook captures every reading with no signal and syncs automatically when the phone reconnects, so a pumper never has to remember a gauge or re-enter it later. Ask any vendor to demo their app in airplane mode before you sign anything. ### What is SCADA in oil and gas, and does production software work with it? SCADA is the sensor and control network that reports pressures, flows and tank levels from the field on its own. Horizontal operators often run it on their best wells. Greasebook puts that SCADA data on the same screen as what pumpers enter by hand, so the office reads one set of numbers. On conventional wells where SCADA never paid off, our sister product TinyPumper fills that gap. ### Does production software replace my pumpers? No. It replaces paper gauge sheets, mail-in tickets and re-keying in the office. The pumper still runs the route, gauges the tanks and checks the wells. What changes is that his numbers reach the office the same day instead of weeks later, and geofencing confirms every visit. Most pumpers end up with shorter days and their weekends back, because the paperwork is gone.

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.

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Run Greasebook for a full 6 weeks. If you do not see results, we do not just refund you. We pay you double what you paid. **P.S.** There is no single "best" oil production software, because operators have three problems under one label: pumper capture, allocation and state filing. The best tool is the one that solves the problem you actually have. If you are still deciding, the quiz tells you whether Greasebook fits in the time it takes to refill your coffee. ===================================================================== # Oil and Gas Production Allocation Software: How It Works and the Best Fit for Independents (2026) > Production allocation software splits commingled oil, gas, and water back to each well, lease, and owner. How it works, the three real options, the best fit by operation size, and what the allocation PDFs actually teach. Source: https://www.greasebook.com/blog/best-oil-and-gas-production-allocation-software/ Published: 2026-04-18 --- A working interest partner emails on Tuesday. She wants last year's volumes for Lease 14, well by well, month by month. Your controller opens the allocation workbook. Three formulas are broken, and the water cut on one well has been wrong since 2019. Production allocation software is what keeps that email from turning into a very long week. **The short version:** oil and gas production allocation software takes oil, gas, and water that flow together into a shared tank, separator, or sales meter and splits them back to each well, each lease, and each owner. For most independent operators, the best fit is allocation built into the production software your pumpers already use, so per-well numbers are captured the same day and the split runs without a separate workbook. A spreadsheet still works for a few wells on simple ownership. Dedicated revenue suites fit offshore, unitized, and very large operations. Pick by how messy your commingling is, not by the longest feature list. **This page is for you if:** - You run anywhere from 15 to 2,000+ wells and some of them share a tank battery, separator, or sales meter. - You have working interest partners, royalty owners, or a state regulator who could ask to see the per-well math. - You own 100% of your wells but still need to know which well on a shared battery is loafing. - You searched for an allocation software PDF and want the decision, not 80 pages of standards.

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## Which production allocation software is right for my operation? It depends on how messy your commingling is. A few wells on one battery with simple ownership: a spreadsheet built around monthly well tests still does the job. Onshore wells sharing tanks or sales meters, with partners, royalty owners, or a battery hiding a slipping well: allocation inside your production software, like Greasebook, runs on per-well numbers your pumpers capture the same day. Offshore, unitized, or very large operations with a full accounting team: a dedicated allocation and revenue suite like Quorum, W Energy, or Enertia is the better pick. ## What Is Oil and Gas Production Allocation Software? Production allocation software is a tool that splits commingled production (oil, gas, and water measured together from more than one well) back into per-well, per-lease, and per-owner volumes. Meters and tanks do not care about lease lines. Five wells can sell into one tank battery. Three leases can share one gas meter. Allocation is the math that puts each barrel back where it came from. It is not accounting software. Allocation answers "how much came out of each well?" The accounting system answers "who gets paid what?" They run in that order. It is also not reservoir software like OFM, which models decline and reserves. Allocation feeds both of those, which is why a mistake here shows up everywhere downstream. ## What Are the Two Jobs of Allocation? Most people think allocation only matters when you have partners. That is half the story. Allocation has two jobs: 1. **Splitting volumes between owners.** When you have working interest partners, multi-lease commingling, or royalty owners, allocation is how you defend the per-well, per-owner numbers your accounting system uses for partner statements and royalty checks. 2. **Per-well productivity testing.** Even if you own every barrel, two or more wells on a shared tank battery hide each other. The tank tells you the battery total. Allocation, run against regular well tests, tells you which rod pump is trending down while the good wells carry the battery. That is how you defend a workover and build decline curves that match reality. You may not need allocation *software* yet. With a handful of wells on one battery, a spreadsheet built around monthly well tests can do the productivity job. You still need allocation. ## How Does Production Allocation Work? The core loop has three steps: 1. **Capture the commingled total.** A run ticket, sales meter, or tank strap gives the total volume that left the battery. That number is the truth at the sales point. 2. **Capture each well's share.** Each well's production is measured upstream of the commingling point, usually by a pumper gauging a test separator, a periodic well test, or SCADA on the wells that have it. 3. **Back-allocate.** The software spreads the sales total back to each well in proportion to its measured share, then applies ownership percentages. **A worked example.** Four wells on three leases feed one tank battery. This month the purchaser took 620 barrels. Well tests say Well A makes 40% of the battery, Well B 30%, Well C 20%, and Well D 10%. Allocation assigns 248, 186, 124, and 62 barrels, rolls those up by lease, and applies each owner's interest. Change one well test and every number below it moves. That is why stale tests are the most common allocation error. Everything else is a feature on top of that loop: water cut (BS&W) and temperature corrections, gas shrinkage to sales volume, multi-product splits for oil, gas, NGL, and water, mid-month ownership changes, and an audit trail a partner can follow. ## Should Allocation Run Daily or Monthly? Monthly allocation is what partners, royalty owners and the state see. The purchaser settles on monthly run tickets, so the month-end split is the one that has to be right. Daily allocation is what the operator uses. Splitting each day's battery total back to the wells shows a slipping well this week, not after the month closes. When pumpers enter gauges on a phone the same day, the daily view comes free with the data, and the monthly number is just the days added up and trued to the run tickets. ## What Happens When a Number Gets Corrected? A purchaser revises a run ticket. A well test was keyed wrong. A good allocation tool lets you fix the reading at its source and re-run the period, and it keeps a record of who changed what and when. If your process is to adjust the allocated output until it ties, every correction makes the next audit harder. ## Which Software Handles Production Allocation Best? There are three real ways operators allocate. The best one depends on your commingling, your ownership, and how often someone looks over your shoulder. | Approach | Works when | Breaks when | |---|---|---| | **Spreadsheet allocation workbook** | A handful of wells, one battery, simple ownership, the same person has kept the file for years | That person leaves, a non-op partner wants an audit trail, or a correction factor has been wrong for years and nobody knew | | **Allocation inside your production software** | Common onshore setups: commingled tanks with per-well gauging, standard working interests, normal non-op partners. Most independents land here | Unitized or offshore fields, nested joint-venture ownership, or continuous multi-phase metering on every well | | **Dedicated allocation and revenue suites** (the Quorum, W Energy, and Enertia tier) | Very large operations with complex structures and a full accounting team to run them | A small or mid-size independent gets sold the enterprise version and the implementation stalls for a year | **Why allocation inside production software wins for most independents:** allocation cannot be cleaner than the per-well numbers going into it. When gauges come off paper sheets that get mailed in on Friday, the factors you run on Monday are already stale. When the pumper enters the gauge on a phone at the tank, the number is in the system that day, and the split runs on fresh data. You also skip the hand-off between two systems, which is where most errors hide. ### How to pick, in three questions **1. How messy is your commingling?** One battery per lease and one lease per battery: allocation is simple and a spreadsheet can carry it. Several wells with different ownership into one battery, or leases sharing a battery or a gas meter: the combinations get ugly fast and a real tool pays off. **2. What does your accounting stack look like?** If you have working interest partners, joint interest billing, multiple leases, or royalty owners, you need real oil and gas accounting software (OGsys, PakEnergy (formerly WolfePak), Bolo, or SSI are common for independents). Pick the allocation tool that hands that system clean volumes. QuickBooks is a stopgap that stops working the minute a non-op partner or royalty owner shows up. **3. How much allocation work runs through your office today?** If reconciling allocation takes more than a day a month, a tool pays for itself in hours. If it takes an hour a month and nobody asks questions, do not buy a platform yet. ### 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 factors | Tests wells on a schedule and refreshes factors when production changes | | Applies one water cut or temperature factor across the whole lease | Applies per-well corrections that match what was actually measured | | Thinks allocation only matters with outside partners | Uses allocation at 100% ownership to find the well that is loafing | | Tweaks the month-end numbers until the totals tie | Reads the audit trail and fixes the source, not the output | | Buys the enterprise suite "because we might grow into it" | Matches the tool to the operation running today | ### Is it hard to switch off a legacy allocation system? The work is in moving your wells, batteries and history, not in learning the new tool. With Greasebook, you hand over a login to the old system and our petroleum engineers convert the wells, surface equipment and records. Greasebook also buys out the months left on your old contract, in exchange for a one-year term plus those months. Most operators are fully rolled out within a week. ## What Goes Wrong With Allocation? Allocation sits quietly until a partner, a royalty owner, or a state auditor starts asking questions. When they do, the problems cluster in the same places: - **Well test drift.** The math assumes recent tests. When tests slip from monthly to quarterly, or a strong well has not been tested in six months, the factor is wrong and every number downstream is wrong with it. Nobody notices until the retest swings the split hard. - **Corrections applied unevenly.** Wells on the same lease can have very different water cuts. A workbook that uses one factor for the whole lease misallocates every month. - **Gas shrinkage.** Wellhead gas becomes sales gas, NGLs, fuel, and flare. Allocating on wellhead volume without the shrinkage step gets the gas side wrong. - **Non-consent elections.** When a partner sits out a recompletion, the operating agreement sets a penalty that has to be recovered before their interest comes back. That bookkeeping is one of the most common places allocation breaks. - **Mid-month ownership changes.** An owner sells an interest on the 17th. The split has to pay the old owner for days 1 to 17 and the new owner after that. Spreadsheets fumble this constantly. A real allocation tool handles all of these as features. A spreadsheet handles them only if the person keeping it remembers. ## What Should an Allocation Report Show? Whether you build it yourself or run it in software, a defensible allocation report shows: - The commingled total and where it came from (run ticket, meter, or strap) for each battery and period. - Each well's test date and test volume, so anyone can see how fresh the factor is. - Per-well allocated oil, gas, and water, rolled up by lease. - Every correction applied (water cut, temperature, shrinkage) with its value. - Ownership changes and non-consent status for the period. - The per-well volumes the state report needs, such as the Texas RRC PR form or the Oklahoma OCC 300R, without retyping. If a non-op partner can read that report without calling you, your allocation is in good shape. This is also what most "non-op production reporting" requests are really asking for.

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## Is There a Production Allocation Software PDF Worth Reading? If you searched for an allocation PDF, Google mostly serves standards, academic papers, and vendor manuals. Here is what each one is good for: - **API MPMS Chapter 20.1 (Production Measurement and Allocation Systems).** The American Petroleum Institute's reference for designing measurement and allocation systems. Skim the first 20 pages for the vocabulary. The rest is written for engineers designing gathering systems from scratch. - **NFOGM papers, GAP guides and academic work.** Mostly offshore, tied to one tool, or simulator-heavy. Little of it helps an onshore independent pick a tool. The short path: skim API 20.1 until you can explain back-allocation without looking it up, read the user guide only for a tool you have already shortlisted, then stop reading and pick. Reading every PDF on the first page of Google is procrastination dressed up as diligence. ## How Much Does Allocation Software Cost? It depends on which of the three approaches you take: - **Spreadsheet:** no license, but not free. You pay in one person's hours, in partner questions you cannot answer fast, and in errors that surface years later. - **Allocation inside production software:** priced with the production software. Greasebook is priced per well or per pumper, per month, based on how many wells you run, how many pumpers cover your routes, and what you need to track. Office users are always free. Allocation is part of the platform, not an add-on. - **Dedicated revenue suites:** a license plus an implementation project, usually priced for operations with a full accounting team. If a rep quotes an implementation project bigger than your yearly back-office budget for a few hundred wells, they are selling you overhead. ## Where Does Greasebook Fit? Greasebook is a production app. Pumpers log gauges, run tickets, pressures, and photos on the phone they already carry, and the Executive Dashboard turns that into live production, state reports, a downtime tracker, alerts, and allocations by well and lease. For the common onshore cases (commingled tanks, multi-well leases, non-op partners, standard working interests), the allocation runs inside Greasebook on numbers captured the same day. Greasebook does not run the ledger. Partner billing, distributions, and royalty checks belong to your accounting system, and Greasebook hands it clean, allocated production. It integrates with the major oil and gas accounting platforms and with engineering tools like PHDwin. Use both. **The facts:** Greasebook is used by 600+ production companies and 10,000+ pumpers, and has tracked more than 220 million barrels. Pumpers learn it in about 8 minutes. Most operators are fully rolled out within a week, with a Greasebook petroleum engineer doing the build-out. Greasebook prepares state production reports for any oil and gas producing state, ready for you to submit, and if your state's form is not built yet, we build it at no cost. Operators who move off paper see a 6% pump-to-net improvement inside six weeks on average, and the 200% money-back guarantee covers the rest: run it for six full weeks, and if you do not see results, we pay you back double. Greasebook's sister product, TinyPumper, adds remote tank and pressure monitoring on wells where SCADA never made sense. ## What Production Allocation Software Is Not - **It is not accounting software.** It produces the volumes. The accounting system does joint interest billing, revenue distribution, and taxes. - **It is not a fix for bad field data.** No engine can recover per-well numbers that were gauged late, missed, or written down wrong. - **It is not a reservoir model.** Decline curves and reserves live in tools like OFM and PHDwin, which use allocated volumes as their input. - **It is not always a separate product.** For most independents, allocation belongs inside the production software, not in a second system that someone has to feed. ## What To Avoid - **Don't fall for the Bolt-On Trap.** Accounting platforms are strong at accounting. Their production modules are jacks of all trades and masters of none on the field side. Integrate with them; don't ask them to run field-first allocation. - **Don't accept the Paper Lag.** Allocation run on gauge sheets that arrive by truck is wrong before it starts. - **Don't let one person own the workbook.** A spreadsheet with one keeper is a succession risk dressed up as a process. - **Don't skip well tests.** Factors that have not changed in 18 months usually mean the tests stopped. - **Don't tune the numbers to tie.** If you have ever adjusted a month "to make it balance," the source data is wrong. Fix the source. - **Don't dismiss allocation because you own 100%.** Productivity testing on a shared battery is reason enough. ## Who This Page Is Not For This page is not for offshore operators, midstream gathering companies allocating gathering and processing splits, or unitized fields run on tract participation factors. Those operations need specialized tools and often a measurement consultant. It is also not for pure royalty owners, who receive allocated volumes rather than produce them. It is for independent onshore operators, from a handful of wells to 2,000+, who want allocation they can defend without a six-month software project. ## Related Pages - The layer upstream of allocation: [oil and gas production software](/blog/oil-and-gas-production-software/). - What happens after allocation: [production allocation and revenue distribution](/blog/production-allocation-and-revenue-distribution/). - Per-well volumes for the state: [oil and gas regulatory production reports](/blog/oil-and-gas-regulatory-production-reports/). - Switching tools: [Scout FDC alternative](/blog/scout-fdc-alternative/). - How production tools sit next to accounting: [oil and gas production accounting software](/blog/oil-and-gas-accounting-software/). ## Frequently Asked Questions **Which software handles oil and gas production allocation best for a small or mid-size operator?** For most independents, the best fit is allocation built into the production software the pumpers already use. The per-well numbers are captured the same day, the split runs without a separate workbook, and clean volumes go to your accounting system. A spreadsheet still works for a few wells on one battery with simple ownership. Dedicated revenue suites make sense for offshore, unitized, or very large operations with a full accounting team. **Do I need allocation if I own 100% of my wells?** Yes, if two or more wells share a tank battery. The tank only tells you the battery total. Allocation, run against regular well tests, tells you which well is slipping while the others carry the load. That is how you catch a failing pump early and defend a workover decision. With only a few wells on one battery, a spreadsheet built around monthly tests can do that job before you need software. **Is production allocation the same as revenue distribution?** No. Allocation answers how much oil, gas, and water came out of each well and lease. Revenue distribution answers who gets paid what for that production. Allocation runs first, then the accounting system uses those volumes for partner statements and royalty checks. Some tools bundle both. Greasebook does the allocation and hands clean volumes to whatever accounting platform you run. **Is there a free PDF that explains production allocation software?** API MPMS Chapter 20.1 is the main standard, sold through the American Petroleum Institute. NFOGM conference papers are often free online but lean offshore. Vendor user guides are usually behind a contact form, and academic papers are free through university repositories. Skim API 20.1 for the vocabulary, then judge tools by how they handle your commingling and well tests, not by how thick their documentation is. **How do I know if my allocation is wrong?** Three warning signs. A partner or royalty owner asks a question you cannot answer without opening three spreadsheets. The factor for a well has not changed in two years even though its production has. Or someone has adjusted a monthly allocation to make the totals tie. Any one of those means the source data or the method needs a review before an audit forces it. **Will allocation software replace my controller?** No. It removes the hand math and the late-night spreadsheet debugging. Your controller still chooses allocation methods, reviews partner statements, and handles the exceptions no software can automate, like a disputed well test or an unusual ownership change. Good software gives that person back days each month and an audit trail they can stand behind.

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.

## Ready to Stop Running Allocation in a Spreadsheet? Take the 60-second quiz to see if Greasebook fits your operation. If it does, grab 15 minutes with a real production engineer and walk out with your exact price. No pitch, no pressure. [Take the Greasebook quiz](https://quiz.greasebook.com/quiz).

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Run Greasebook for six full weeks. If you do not see results, the 200% money-back guarantee pays you back double. **P.S.** This page is not for offshore operators or midstream gathering systems. No hard feelings. If you are still deciding, the quiz gives you a straight answer in the time it takes to refill your coffee. ===================================================================== # 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/what-software-do-oil-and-gas-companies-use/) 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.

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## 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/what-software-do-oil-and-gas-companies-use/) overview. For the production capture layer specifically, see [oil and gas production software]({{ site.baseurl }}/blog/oil-and-gas-production-software/). ## Competitive Landscape: PakEnergy, Wenergy, and the Enterprise Tier Two names come up repeatedly when operators research production data management. **PakEnergy** (formerly WolfePak) 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. SSI is an alternative to PakEnergy in the same tier. Oil and gas companies have had a lot of success with it, and the suite is extremely comprehensive. Its Well History profitability reporting tracks per-well profit trends on a rolling twelve months, which is unmatched among oil and gas accounting systems. For a head-to-head look at when PakEnergy is the right call versus lighter-weight alternatives, see [PakEnergy 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 PakEnergy 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.

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## What Production Data Management Actually Costs | Tier | Tools included | How it is priced | |---|---|---| | Mobile production only | Field data capture, basic allocation, state filing prep | Per well or per pumper, monthly; office users often free | | Production + basic integration | Above plus data exports to warehouse or accounting | Per well, monthly, plus any integration work | | OFM or forecasting package | Engineering-focused decline curve and reserves tool | Per engineer seat, yearly, or enterprise licensing | | Historian deployment | PI System or peer, with engineering services | Large upfront project plus annual maintenance | | CMMS | Maintenance management, typically per-technician or per-asset | Per technician or per asset, plus implementation | | Mid-market ERP (PakEnergy, Wenergy) | Production + accounting + land integrated | Per well, plus a paid implementation project | | Full data warehouse build | Cloud infrastructure plus ETL plus analyst team | Cloud bills plus an analyst team, scaling with data volume | Most independents, from a handful of wells to 2,000+, start with mobile capture plus light integration and add engineering and analytics tools only when the work justifies them. 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, PakEnergy, Bolo, SSI) 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, PakEnergy, Bolo, SSI), 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 (PakEnergy, 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, PakEnergy, 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 PakEnergy, 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 PakEnergy? 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: PakEnergy 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.

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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 reservoir engineer at a major shopping for simulation-grade analytics. No hard feelings. If you are still deciding, the quiz gives you a straight answer in the time it takes to refill your coffee. ===================================================================== # Oil and Gas Regulatory Production Reports: Every State, Every Form, Every Filing Deadline > State-by-state map of upstream production reporting: TX RRC PR, OK OCC 300R, ND NDIC Form 5, CA, NM, LA, CO, PA, WV, WY, KS, and federal ONRR. What each form wants, when it is due, and how operators prepare it. Source: https://www.greasebook.com/blog/oil-and-gas-regulatory-production-reports/ Published: 2026-04-18 --- It is the 28th of the month and a certified letter hits your desk from the state. The subject line says "Notice of Deficient Filing." A lease you sold eight months ago still shows you as operator of record, and the last three monthly reports never landed. Penalties are compounding, severance tax is on hold, and the auditor wants a callback by Friday. Oil and gas regulatory production reports are the monthly, semi-annual, or annual filings that every operator of record submits to state regulators (and to ONRR for federal leases) documenting per-well volumes, dispositions, and well status. The forms differ state to state. The obligation does not. Written for operators of record filing in 2+ states who are tired of rebuilding their monthly workflow from scratch. Not written for non-op partners, service companies, or midstream. If you've ever spent the last 3 days of the month hunting stock-change numbers across four spreadsheets, keep reading. Every upstream oil and gas producer in the United States files monthly or periodic production reports with one or more state regulators and, for federal leases, with ONRR. The forms are different in every state. The deadlines are different. The data fields are different. The portals are different. What stays constant is the underlying obligation: operators of record must report volumes (oil, gas, water, disposal, injection) on a schedule the regulator sets, and penalties for late or incorrect filings are real. This guide is a map. It covers the 12 jurisdictions that matter most for independent onshore producers: Texas, Oklahoma, North Dakota, California, New Mexico, Louisiana, Colorado, Pennsylvania, West Virginia, Wyoming, Kansas, and federal ONRR. For each one it names the form, the cadence, the portal, and the common filing mistakes. Each state has its own deep-dive page linked below. Before we get into any of that, the admission nobody in this category leads with: software only handles the easy 60% of regulatory production reporting. It captures volumes, maintains allocation factors, and exports to the format each state wants. It does not replace the judgment calls, does not sign the attestation, does not pay the fees, and does not argue with a regulator when something goes sideways. Every vendor leaves that part out because admitting it up front doesn't sell licenses. We're starting there because it's the part that determines whether the software actually saves you time or just rearranges the same work.

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## 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/best-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.

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## 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 submit 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 prep.** Greasebook prepares state production reports for any oil and gas producing state, including every jurisdiction mapped above and federal ONRR, built from the volumes your pumpers already entered. You review and submit through the regulator's portal; the attestation stays yours. If your state's form isn't built yet, we build it at no cost. The walkthroughs on this page explain what each regulator asks for, so you know what you are signing. ## 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.

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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. ===================================================================== # Oil Well Monitoring System: Remote Well and Production Monitoring for Producers > How an oil well monitoring system watches pressures, runtime, and production between pumper visits. Remote well monitoring, production monitoring, what it costs, and when SCADA is worth it. Source: https://www.greasebook.com/blog/oilfield-monitoring/ Published: 2026-04-18 --- **Short version:** An oil well monitoring system tells you what your wells, tanks, and pumps are doing when nobody is standing there. It reads wellhead and flowline pressure, pump and engine runtime, and tank levels, then texts you when something crosses a line you set. For most producers it is four parts: sensors at the site, a way to send the data, software that shows it and fires alerts, and a person who acts on the alert. Full SCADA is still the right call where you need to control equipment from the office. On conventional wells and tank batteries where SCADA never penciled, a self-installed monitor like [TinyPumper](https://tinypumper.com) gives you about 99% of the upside for about 95% less. It is 10:47 PM on a Thursday. The engine on a pumping unit died at 3 PM. The pumper drove past it at 7 AM and it was running fine. Nobody will know it is down until tomorrow's route, so that well makes nothing for most of a day. Next week it is a flowline that lost pressure, or a stock tank five feet from the top and filling. That is the hole oil well monitoring is supposed to close. **This page is for you if:** - You run conventional wells, tank batteries, or saltwater disposal sites and you are flying blind between pumper visits. - You have been burned by a tank overflow, a stuck pump, or a leak nobody caught until the next run. - You were quoted SCADA, the math never penciled, and you want to know what else is out there. - You already have SCADA on some sites and it costs more to keep alive than it gives back. This works the same whether you run 50 wells or 5,000. The question is never well count. It is whether SCADA makes sense on the site in front of you. ## Which oil well monitoring system fits my wells? It depends on the site. An oil well monitoring system is the sensors, communications, software and alert plan that show you pressures, runtime and tank levels between pumper visits. Monitoring watches equipment; control runs it. If you start, stop or change setpoints on compression, gas plants or high-rate wells from the office, SCADA is the better pick. If you run conventional wells or tank batteries where SCADA never penciled, or aging SCADA costs more than it returns, TinyPumper fits at any well count. If you need the daily production record and state reports, add Greasebook. ## What is an oil well monitoring system? An oil well monitoring system (people also call it oilfield monitoring) is how a producing company knows what is happening at a well, tank, or facility without driving out to look. It covers tank levels, wellhead and flowline pressures, pump and compressor runtime, and alarms like a high tank or a dead engine. The tools run from a pumper's route sheet to a phone app to sensors that report on their own to full SCADA. Monitoring is not the same as control. A sensor that tells you a tank is at 14 feet is monitoring. A valve that shuts when the tank hits 14 feet is control. That line decides most of what you should buy. Here is what a monitoring setup usually watches: - **Tank levels.** Oil, water, and saltwater tanks. This drives haul scheduling and keeps tanks from running over. - **Pressures.** Tubing, casing, flowline, and injection pressure. Trends matter more than one reading. A slow casing climb is a different problem than a sudden line drop. - **Runtime and downtime.** Is the pump or compressor running? When did it stop? Runtime is the first place to look when production dips. - **Production volumes.** Daily oil, gas, and water by well or tank. This feeds allocation and state reports. - **Alarms.** High tank, low pressure, engine down. Alarms are the reason monitoring exists. Not every site needs all of it. A conventional lease may need tank levels and one pressure. A compressor station needs a lot more.

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## What is an oil well monitoring system made of? Every real monitoring system has four layers. Skip one and you bought something that is cheaper to buy than it is useful in the field. ### 1. Sensors and site hardware The devices at the well or tank that read a signal. - **Tank level sensors.** Radar, submersible pressure, or float. Radar on top of the tank never touches the fluid, so it doesn't corrode, foul, or freeze. Submersible and float sensors do. - **Pressure sensors.** At the wellhead, flowline, or injection well. - **Runtime monitors.** Tell you whether an engine, pump, or compressor is running. - **Gas and H2S detectors.** Safety alarms at larger facilities. - **RTUs and gateways.** Gather the signals at one site and send them on. ### 2. Communications How the signal gets from the lease to your phone. Cellular, satellite, radio, or wire. The rule: if the system can't reach your worst dead zone, it isn't covering the sites that need it most. TinyPumper uses satellite, which means 100% coverage across the continental US. ### 3. Software Live readings, history, alerts, and reports. This is where most buyers overspend. A dashboard nobody opens is a line item on the credit card. Software earns its keep by getting the right alert to the right person, not by its feature list. ### 4. Response The layer everyone forgets: who acts on the alert. - **The pumper route.** A tank filling faster than normal moves that lease to the top of today's route. - **Office staff.** Who watches during business hours. - **After hours.** Who gets the text at 2 AM. - **Escalation.** How a field problem reaches the ops lead or owner in time to matter. Monitoring without a response plan is decoration. A system that flags theft at midnight and nobody checks for three days is worse than none at all, because it looks like coverage. ## What do producers actually run? Leave out the "200 sensors per well" pitch. Four setups show up in the field. **1. Paper rounds.** A pumper, a route, a gauge line, and a ticket. Cheap, and it works. It also loses data, depends on one person's handwriting, and runs days behind. **2. A phone app for field data.** Same pumper, same route, but readings go into a phone at the well with a timestamp and photo. The office sees them the same day. [Greasebook](https://www.greasebook.com) lives here for the production side: gauges, run tickets, allocation, and state reports. **3. SCADA.** Controllers at each site send data to a central server and can also run equipment. It is the standard for compression, gas plants, injection with control needs, and high-rate wells. It is also the most expensive to install and keep running, and it needs someone to maintain it. **4. A self-installed monitor on the sites SCADA never reached.** Sensors you put on yourself, reporting to your phone, with no wiring or integrator. This is where [TinyPumper](https://tinypumper.com) fits. If you are weighing a specific vendor, our [oilfield monitoring alternatives](/blog/oilfield-monitoring-alternatives/) guide lays them side by side. Most producers end up mixing these: SCADA where it earns its keep, TinyPumper on the conventional sites, and Greasebook for the daily production record across all of it. ## How does remote well monitoring work? Remote well monitoring means watching a producing oil or gas well from your phone or office instead of from the lease road. It puts a sensor where your pumper would otherwise have to look. A pressure sensor on the wellhead or flowline reports pressure. A runtime sensor tells you whether the pump jack or engine is turning. You set the line (a pressure that's too low, an engine that's been down too long) and your phone buzzes when it's crossed. With TinyPumper, each sensor reports every hour to save battery, and it wakes every 5 minutes to check your limits. If something crosses the line, the alert goes out right then, not at the top of the hour. The gateway also has a built-in shake counter, so it knows whether an engine or compressor is running without another sensor. What remote well monitoring won't do is replace your pumper's eyes. It will tell you which wells need him today and which ones can wait. Producers running TinyPumper report cutting lease runs by 30 to 50% and catching failures days sooner. **What does remote well monitoring cost?** It depends on whether you need to control the well or just watch it. Controlling it from the office is SCADA, quoted site by site by an integrator. Watching it is far cheaper: TinyPumper is $349 a sensor, one time, then one flat rate a month per site with unlimited sensors, and you install it yourself in 8 minutes. The full cost breakdown is further down this page. ## Can you monitor pumping units and artificial lift remotely? Yes, at two depths. The first answers "is it running?" TinyPumper's gateway has a built-in shake counter that knows whether the engine or motor on a pumping unit is turning, and a pressure sensor on the tubing or flowline shows whether it is moving fluid. That catches a dead engine, a tripped motor, or a well that quit flowing the same day instead of on the next route. The second depth reads how the pump itself is doing: dynamometer cards, fillage, and pump-off. That job belongs to a [pump-off controller](/blog/pump-off-controller/) or SCADA. Most conventional rod-pump and gas-lift wells only need the first depth to stop losing days of production. ## What is oil and gas production monitoring? Production monitoring is keeping a daily eye on how much oil, gas, and water each well makes, and catching the drop the day it happens instead of at month-end. It has two halves. - **The field signal.** Is the well running, are the pressures normal, is the tank filling at its usual rate? Sensors answer this between visits. A well that stops filling its tank is a well that stopped producing. - **The production record.** The gauges, run tickets, and volumes by well that feed allocation, partner statements, and state reports. A phone app answers this. [Greasebook](https://www.greasebook.com) is the production app for that record, and TinyPumper readings flow straight into the Greasebook dashboard. A good production monitoring dashboard shows both on one screen: today's volumes by well next to the alerts that explain them. If the volume dropped and the runtime sensor shows the pump was down six hours, you know why without a phone call. If the volume dropped and everything ran, you send the pumper to look for a leak or a bad test. **Oil well production monitoring at a glance:** | What you watch | What it catches | Tool | |---|---|---| | Runtime | Dead engines, stuck pumps, tripped compressors | Runtime sensor or gateway shake counter | | Wellhead and flowline pressure | Line leaks, freeze-offs, failing equipment | Pressure sensor | | Tank level rise | A well that quit making fluid, theft, a tank about to run over | Radar tank sensor | | Daily volumes by well | Decline, allocation errors, missed tickets | Production app | ## How do you monitor oil tank levels remotely? A radar sensor mounts on top of the tank and reports the level to your phone, with no fluid contact, so it doesn't corrode, foul, or freeze. TinyPumper reads oil, water, and saltwater tanks this way, and the same gateway carries the pressure sensors for that site. For the full tank picture (sensor types, tank battery setups, haul scheduling, and alarms), see our guide to [oilfield tank monitoring](/blog/oilfield-tank-monitoring/). For water handling, see [saltwater disposal monitoring](/blog/saltwater-disposal-monitoring/). ## What does an oil well monitoring system cost? The honest answer depends on the site, not the brochure. **SCADA** is quoted site by site by an integrator: controllers, sensors, cabinet, power, communications, install labor, hosting, and someone to keep it running. On a big facility that cost is worth it. On a low-rate conventional well it usually isn't, which is why so many of those wells run blind. **TinyPumper** is $349 a sensor, one time. Then one flat rate a month per site, unlimited sensors at that location, starting at $79 a month. No setup fees, no training fees, no carrier bill. Against SCADA, that is about 95% cheaper for about 99% of the upside. **A phone app for field data** is priced per well or per user, and doesn't need hardware. **Paper** costs nothing up front. You pay for it in late numbers and missed problems. The cost that matters most is the one nobody prices: the overflow, the stuck pump, or the theft you found a week late. ## When is SCADA the right system, and when isn't it? | If you... | Then... | Because | |---|---|---| | Run conventional wells where SCADA never penciled | A self-installed monitor like TinyPumper, plus a phone app for the daily record | You get about 99% of SCADA's upside without wires, trenches, or an integrator | | Run aging SCADA that costs more to keep alive than it returns | Swap in TinyPumper on the sites that hurt | Ends the maintenance drag without a full rip-and-replace | | Run compression, gas plants, or high-rate wells you control from the office | Keep SCADA | Starting, stopping, and setpoint changes are not a monitoring job | | Mix conventional and unconventional sites | SCADA at the facilities, TinyPumper at the conventional sites | Match the tool to the site, not to a total well count | | Have more dashboards than anybody watches | Fix who gets the alert before you buy anything | More sensors won't fix an alert-routing problem | ## Where do monitoring systems break down? These come up again and again in operator conversations. **Hardware installed, software never set up.** The sensors report, but nobody built the alerts. The system delivers nothing. Commit to the software rollout, not just the hardware. **Data nobody looks at.** Alarms go to a shared inbox. The fix is almost never more sensors. It is routing the signal to the one person who can act, by text or push notification. **Coverage that doesn't match the route.** Sensors on the quiet leases, none on the far ones. Put coverage where drive time is longest and the risk of a spill or theft is highest. **Tools that fight the pumper.** An app built by someone who has never gauged a tank is obvious in five minutes. If the field hand won't use it, the data never shows up. ### Amateur vs pro: how producers pick a monitoring system | The amateur... | The pro... | |---|---| | Buys hardware first and figures out software later | Scopes all four layers before any purchase order | | Picks the system with the longest feature list | Picks the system that gets the right alert to the right person fastest | | Covers every site the same | Covers the sites where drive time and risk justify it | | Forces SCADA onto conventional sites | Runs SCADA where it pencils and a self-installed monitor on the rest | | Treats the pumper as an afterthought | Designs the alert path backward from the pumper's phone | ### What to avoid - **Don't skip the response layer.** An alert nobody owns is a problem you still find two weeks late. - **Don't let every vendor bring its own dashboard.** Logins multiply and nobody checks any of them. Decide where the data lands before you add vendor number two. - **Don't fund hardware without naming an owner.** A dashboard with no name on it is a subscription with no customer. ## What does "real-time" actually mean? Vendors use "real-time" to mean very different things. - **SCADA** usually polls every few seconds to a minute. - **A phone app** shows the pumper's entry as soon as the phone has signal. - **TinyPumper** reports every hour and checks your limits every 5 minutes, sending the alert right away when one is crossed. - **A dashboard** can mean anything from seconds to "whenever the last batch ran." The real question is whether you hear about it in time to act. A tank filling at two barrels an hour doesn't need second-by-second polling. A compressor trip on a gas plant does. Match the tool to how fast you have to respond. ## What an oil well monitoring system is not **It is not control.** Monitoring tells you what is happening. If you need to start and stop pumps from your desk, you are into [oil and gas automation](/blog/automation-in-oil-and-gas-industry/) and SCADA. TinyPumper monitors. It does not run your equipment. **It is not a replacement for the pumper.** It tells him where to go first. **It is not downhole monitoring.** Permanent downhole gauges and fiber-optic sensing are completion tools, installed when a well is drilled. Surface monitoring watches what the well does at the wellhead, the tank, and the engine, which is where a producer loses barrels day to day. **It is not for every operator.** If you run compression stations at pipeline scale, gas plants, or refining, you need DCS-grade control from vendors like Emerson, Honeywell, or AVEVA. And if no one on your team will act on an alert, no system will help until that changes. **It is not one tool that does everything.** Nobody does paper replacement, SCADA, automation, analytics, and state reporting well under one roof. Anyone who says they do, in our experience, does one part well and the rest poorly. ## How do Greasebook and TinyPumper work together? TinyPumper is 24/7 remote monitoring that installs in 8 minutes. No wires. No SCADA. You put it on yourself. A matchbox-sized, solar-powered gateway carries up to 8 sensors: radar for tanks, pressure for wellheads, flowlines, and injection wells, plus engine and compressor runtime. Satellite coverage reaches 100% of the continental US. Every sensor carries lifetime hardware replacement, and you get 60 days to try it with full money back. We pay the return shipping. Greasebook is the production app for the rest of the record: the gauges, run tickets, pumper comments, well tests, and state production reports for any oil and gas producing state. TinyPumper data flows straight into the Greasebook dashboard, so sensor readings and pumper entries sit on one screen. Use TinyPumper where you want eyes between visits. Use Greasebook for the daily production record across every well. ## Related guides - [Oilfield tank monitoring](/blog/oilfield-tank-monitoring/): tank levels, tank batteries, and alarms - [Saltwater disposal monitoring](/blog/saltwater-disposal-monitoring/): produced water by level and by flow - [Oilfield monitoring alternatives](/blog/oilfield-monitoring-alternatives/): how the monitoring vendors compare - [Oilfield monitoring app](/blog/oilfield-monitoring-app/): the phone-first side of monitoring - [Oilfield monitoring software](/blog/oilfield-monitoring-software/): the software category - [Oil and gas SCADA](/blog/oil-and-gas-scada/): when you need supervisory control - [Automation in the oil and gas industry](/blog/automation-in-oil-and-gas-industry/): when monitoring becomes control - [IoT in oil and gas](/blog/iot-oil-and-gas-products/): the sensor and telemetry layer - [Oil and gas production software](/blog/oil-and-gas-production-software/): the production record behind it all ### What pumpers and operators deal with in the field - [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 is an emergency and what can wait - [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

The SCADA alternative for conventional wells, at any scale

Self-installs in 8 minutes. $349 a sensor, one time, then one flat rate a month per site. 60 days to try it. Lifetime hardware replacement.

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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 an oil well monitoring system?** An oil well monitoring system is the set of sensors, communications, software, and response plan that shows a producer what is happening at wells, tanks, and facilities between pumper visits. It reads pressures, runtime, and tank levels and alerts you when something crosses a line you set. When a system feels broken, it is usually missing one part, most often the person assigned to act on the alert. **What is production monitoring?** Production monitoring is tracking how much oil, gas, and water each well makes every day and catching a drop the day it happens. It pairs field signals, like runtime, pressure, and tank level, with the production record of gauges, run tickets, and volumes by well. Sensors tell you something changed. The production record tells you how much it cost you in barrels. **How much does remote well monitoring cost?** It depends on whether you need to control the well or only watch it. Control from the office is SCADA, priced site by site by an integrator, plus upkeep. Watching is far cheaper. TinyPumper is $349 a sensor, one time, then one flat rate a month per site with unlimited sensors, and you install it yourself in 8 minutes, with no setup or training fees. **What oilfield monitoring equipment do I need?** For most conventional sites: a level sensor on each tank you care about, a pressure sensor on the wellhead or flowline, and a way to tell whether the pump or engine is running. With TinyPumper, one solar gateway carries up to 8 sensors, and it detects engine and compressor runtime on its own. Bigger facilities with compression or safety systems usually need SCADA-grade equipment. **Which real-time production monitoring systems work best for oil well operations?** It depends on the site. For compression, gas plants, and high-rate wells you control from the office, SCADA from vendors like Emerson or Honeywell is built for the job. For conventional wells and tank batteries where SCADA never penciled, a self-installed monitor like TinyPumper covers about 99% of the upside for about 95% less. Most producers run a mix. **Does oil well monitoring work without cell service?** It can. Systems that only run on cell service leave your worst dead zones uncovered, and those are often the sites that need watching most. TinyPumper uses satellite, which gives 100% coverage across the continental US. A good field data app also works offline and syncs once the pumper's phone finds signal on the drive back. ===================================================================== # Oil and Gas SCADA: Systems, Cost, Companies, and Low-Cost Alternatives > Oil and gas SCADA for producers: how it works, what a system costs, which companies matter, low-cost options and alternatives, and when SCADA is overkill. Source: https://www.greasebook.com/blog/oil-and-gas-scada/ Published: 2026-04-18 --- *This guide now covers SCADA software, SCADA companies, what a SCADA system costs, and the low-cost alternatives in one place.* Oil and gas SCADA is the system that watches wells, tanks, and facilities from a distance and lets the office act on what it sees. Sensors read levels and pressures, a field controller passes the readings over radio, cell, or satellite, and host software shows them, stores them, and fires alarms. For a producing company, SCADA pays back on compressor stations, disposal wells, gas plants, and high-value pads. On conventional wells where the per-site math never penciled, or where old SCADA is breaking down, it is usually overkill, and a drop-in monitor gets you most of the benefit for a fraction of the cost. **The short version:** - **What it is:** field devices, controllers (RTUs and PLCs), communications, and a host system. All four have to work. - **Who sells it:** platform vendors like Inductive Automation (Ignition), VTScada, AVEVA, Rockwell, and Siemens; oilfield specialists like eLynx, zdSCADA, Zedi, and AutoSol; and the integrators who build the system. - **What drives the cost:** instruments, field controllers, telemetry, integrator labor, and the person who keeps it alive. The software license is usually the smallest line. - **When to skip it:** conventional wells and tank batteries where the per-site return never worked. That is true at 50 wells or 5,000. Picture the integrator call: two hours, 47 slides, and a scope that grew from tank levels at 20 sites to a host, a historian, and an 18-month rollout. Eighteen months later the alarm console is muted and the pumper is still texting tank levels to the office. This guide is built to keep that from happening to you. **This guide is for you if:** - You are scoping a SCADA rollout and want the honest read on where it pays back. - You are comparing SCADA software or a vendor shortlist and want to know who does what. - You have legacy SCADA on conventional sites and the upkeep is eating the return. - You run anywhere from a few dozen wells to a few thousand, and the per-site question is already on your desk.

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## Do You Need Full SCADA for Your Oil and Gas Wells? It depends on the site. Compressor stations, disposal wells, gas plants and high-rate horizontal pads need remote control, so full SCADA (Ignition, or hosted eLynx if you lack a controls team) is the right pick, not TinyPumper. On conventional wells where SCADA never penciled, or where old SCADA costs more to keep than it returns, TinyPumper watches tanks, pressures and runtime for $349 a sensor, one time, plus one flat monthly rate per site, as of October 2026. Already running SCADA? Add Greasebook for the pumper's gauges and run tickets. ## What Is SCADA in Oil and Gas? SCADA stands for Supervisory Control and Data Acquisition. In oil and gas, SCADA is the combined hardware and software that collects readings from distributed field sites, sends them to a central host, and lets operators watch, alarm on, and control that equipment remotely. It is different from a DCS (distributed control system), which is the tighter, faster control system you find inside a refinery or gas plant. SCADA is built for sites spread across a county, with slower update cycles and long communication links. In practice, SCADA has four layers. **1. Field devices.** The sensors 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. **2. RTUs and PLCs.** Remote terminal units and programmable logic controllers sit in a cabinet at the site. They take the sensor signals, run simple logic (close this valve when that pressure hits a setpoint), and hand the data to the communications layer. RTUs are common at remote wellheads. PLCs are common at facilities with more instruments. **3. Communications.** Licensed or unlicensed radio, cellular, satellite, or wire. This is the layer that fails most often and drives most of the monthly bill. 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-site or hosted, that receives the data, stores it in a historian, shows it on HMI screens, fires alarms, and sends commands back to the field. Ignition, CygNet, eLynx, and Canary are names you will hear at this layer. A gap in any one layer (a dead sensor, a broken radio, a host that crashed overnight) takes the whole thing down. ## What Does a SCADA System Do on an Oil and Gas Lease? Strip the marketing away and SCADA software does five jobs, in this order: 1. **Polls field devices.** RTUs and PLCs at wellheads, tank batteries, compressor stations, and meters get read every few seconds to every few minutes. 2. **Turns raw values into real units.** Register counts become psi, degrees, barrels per day, and MCF. 3. **Shows it.** Screens with well status, tank levels, pressures, and flow rates. 4. **Alarms on exceptions.** High tank, low suction, ESD, gas detection, compressor trip. The alarm goes to a console, a phone, or the pumper on call. 5. **Stores the history.** A year of tubing pressure at one-minute resolution lets the engineer pull up the week a well acted up and see what changed. Remote control sits on top: starting and stopping pumps, opening and closing valves, changing setpoints, resetting compressors. All of it comes with permissions and an audit trail. That combination is what lets a producer **operate by exception**. Instead of driving every well every day, the team works the list of sites that crossed a line. That only works if the alarm list is tuned. Most systems over-alarm on day one, and a muted alarm channel is worse than none, because everyone assumes someone else is watching. ## What Happens to SCADA Data in Oil and Gas? SCADA data lands in a historian: a database that keeps every reading with its timestamp, often at one-minute resolution for years. Engineers pull trends from it (tubing pressure the week a well loaded up, compressor runtime before a failure), and the alarm list runs off it. What the historian does not hold is the pumper's side of the day: hand gauges, run tickets, downtime reasons, and comments. That record lives in a production app. [Greasebook](https://www.greasebook.com) integrates with SCADA systems so the readings and the pumper's entries end up together, which is what allocation, partner reports, and state production reports are built from. ## Is SCADA Outdated, or Still Used Today? It is still used, and it is not outdated where it fits. Virtually every major and mid-size producer runs SCADA on instrumented pads and central facilities, and new systems get built every year. What changed is where the host lives and what the field layer looks like. Hosted SCADA rents you the server, historian, and screens per site. Wireless sensors now report straight to the cloud without a traditional controller in the cabinet. Most modern stacks mix all three: traditional RTUs at facilities, cloud-connected sensors on the long tail, and a phone app for the pumper's round. ## What Kinds of Oil and Gas SCADA Software Are There? Vendor conversations go sideways when the categories get mixed up. There are four. ### 1. General-purpose SCADA platforms Ignition (Inductive Automation), VTScada (Trihedral), AVEVA (the Wonderware line), Rockwell FactoryTalk View, and Siemens WinCC. Deep, flexible, and used across many industries. Usually built and maintained by an integrator or an in-house controls team. See [Ignition SCADA alternatives](/blog/ignition-scada-alternative/) for when that lift is too heavy. ### 2. Hosted oil and gas SCADA eLynx, zdSCADA, SCADAfarm, and Zedi (now part of Emerson) run the host in their cloud and charge per site per month. Less up front, more every month, faster rollout. Common with operators who do not want to staff their own controls team. ### 3. Upstream-specific platforms and historians CygNet is built around upstream production. Canary Labs and the AVEVA PI System (formerly OSIsoft PI) are historians, often paired with another HMI. Narrower, more opinionated for oilfield work. ### 4. Free and open-source SCADA Rapid SCADA is open source, and Ignition has a free Maker Edition for personal use. Useful for engineers learning the tools. Commercial producers almost always license a paid platform because support, security, and oilfield features matter once real barrels ride on it. ### How SCADA Software Is Priced Licensing models vary more than the features do: - **Ignition:** licensed per server, with unlimited clients and tags. Operators like that there is no per-tag creep. - **VTScada:** licensed by tag or I/O point count, in tiers. - **AVEVA:** licensed by tag and by named user, with enterprise pricing for large systems. - **Rockwell FactoryTalk View:** licensed per client workstation. - **Hosted platforms (eLynx, zdSCADA, SCADAfarm, Zedi):** a monthly fee per site, with the vendor running the servers. Whatever the model, the license is rarely the big number. The instruments, field controllers, telemetry, and integrator build-out are. ## Which Oil and Gas SCADA Companies Matter? Not a ranking. These are the names that come up most in producer conversations, with an honest one-line read on each. **General-purpose platform vendors** - **Inductive Automation (Ignition):** the platform a generation of integrators builds on across every major U.S. basin. Flexible and scriptable. Needs real in-house or integrator expertise. - **Trihedral (VTScada):** strong in Western Canada and the northern U.S. Known for reliability and tight licensing. - **AVEVA and Schneider Electric:** the Wonderware line and Schneider's Geo SCADA (formerly ClearSCADA). Common in upstream, midstream, and pipeline work. - **Rockwell Automation (FactoryTalk View):** paired with Allen-Bradley PLCs. Shows up in oil and gas mostly through integrators. - **Siemens (WinCC):** heavy industrial SCADA, more common in gas processing and midstream than at the wellhead. - **Emerson:** DeltaV and Ovation on the plant side, Zedi for hosted upstream SCADA and measurement. **Oil-and-gas-specific players** - **eLynx:** hosted, oilfield-focused SCADA with strong alarm tooling. Popular with mid-size operators. - **CygNet:** upstream-specialized SCADA, hosted or on-site. An honest workhorse in unconventional plays. - **zdSCADA and SCADAfarm:** cloud SCADA sold as a managed service, built for faster rollouts than traditional platforms. - **AutoSol:** communications and SCADA for upstream and midstream, strong across the Mid-Continent. - **Kimray:** long-time oilfield equipment maker whose electronic controllers and automation show up at the wellhead. **Telemetry and integrators** FreeWave, SignalFire, and similar vendors sell the radios and gateways that move data from the wellhead to the host. Under all of it are regional integrators who build the actual system. When a producer "buys SCADA," they are almost always buying a platform license plus an integrator's build-out. ## How Do You Pick a SCADA Platform for Oil and Gas Production? Start with the site, not the logo. Four questions cut through the vendor decks: 1. **What does 24 hours of undetected downtime cost at a typical site?** That is your real SCADA return. If it is large, SCADA earns its keep. If a missed day costs a few barrels, it probably does not. 2. **How complex is the facility?** Central compression, gas plants, saltwater disposal, and instrumented pads push toward full SCADA. A conventional well and tank battery push toward something lighter. 3. **What is your connectivity reality?** Get the coverage survey before the quote. In remote fields the telemetry install can cost more than the software. 4. **Who keeps it alive?** SCADA without a controls tech or a live integrator contract degrades fast. If you do not have the staff, hosted SCADA or drop-in monitoring is safer than a neglected stack. One more question producers ask us often: which platform gives field crews real-time monitoring and an easy mobile view? Most SCADA platforms were designed for an operator at a desk. The mobile view is usually an add-on, and the pumper's daily round (manual gauges, run tickets, downtime notes) is not in the system at all. Plan the phone layer before day one, not after. ### Which One Do You Actually Need? | If you... | Then... | Because | |-----------|---------|---------| | Run a compressor station, gas plant, or disposal well where downtime costs real money by the 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 cost | Full SCADA pencils easily | The math works at 50 pads or 500 | | Run legacy SCADA that is breaking down on conventional wells | Replace it with a drop-in monitor like TinyPumper | The upkeep eats the return, and replacing it costs less than babysitting it | | 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 facilities and conventional long-tail wells | Run both | SCADA where the economics earn it, TinyPumper on the rest | ## How Much Does a SCADA System Cost for Oil and Gas? There is no honest single number, because every project starts from a different place. What you can do is price the right lines. A full SCADA quote is built from: - **Per-site hardware:** RTU or PLC, sensors, cabinet, power, and install. Depends on what is already there and what you are metering. - **Per-site communications and hosting:** radio, cellular, or satellite plans, plus hosted SCADA fees if you go that route. - **Host software:** a one-time license with annual support, or a per-site monthly fee on hosted platforms. - **Integrator labor:** the initial build-out, which varies widely by region, scope, and how much your own team does. - **Ongoing controls support:** the tech or engineer who keeps alarms tuned, the historian healthy, and the RTUs online. This is the line most budgets forget. Ask the integrator for the build-out plus three years of support, not the license price. That is the number you are actually signing. For comparison, TinyPumper is $349 a sensor, one time. Then one flat rate a month per site, unlimited sensors, starting at $79 a month. In a lot of cases, one $349 sensor costs less than a battery swap on a SCADA panel. Site for site, TinyPumper runs about 95% cheaper than SCADA.

SCADA at the facility, phone app and drop-in monitors in the field

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## Where Is SCADA Used in Oil and Gas, and When Does It Earn Its Keep? Forget well count. The axes that matter are facility complexity and per-site economics. **Central facilities that have to stay up.** Compressor stations, saltwater disposal and waterflood injection, gas plants, inlet separation. Unplanned downtime there costs real money every hour, which is why SCADA pays back fastest at facilities. **Safety-critical operations.** H2S detection, fire and gas, ESD systems. The alarm and shutdown logic has to be instrumented. Paper will not do it. **Artificial lift control.** Plunger lift, gas lift, ESPs, and rod pump control run on SCADA data. Without it, the tuning is guesswork. **Regulatory or midstream requirements.** Custody transfer, continuous air-permit monitoring, and midstream contracts that need hourly flow data can require the instruments. **High-value pads.** High-rate horizontals, enhanced recovery, and mixed production and injection pads, where the per-site spend is a small slice of per-site revenue. A producer running 50 horizontal pads and one running 500 sign off on the same math. If your operation looks like this, you have already made the right call. Plenty of horizontal shops also plug [Greasebook](https://www.greasebook.com) in on top of SCADA as the production layer, because pumper-entered data (run tickets, tank gauges, downtime codes) is the piece SCADA still cannot see. ## Where Does SCADA Overshoot? SCADA is not a monitoring answer for every well in the portfolio. It overshoots in four places: - **Conventional wells where the per-site cost never penciled.** The capex, wiring, telemetry, and upkeep never hit a return you could defend, whether you run 50 wells or 5,000. - **Aging SCADA that is breaking down.** Sensor replacements, service calls, and paying someone to babysit the stack no longer justify what you get back. - **Sites the pumper already sees every day.** If "see it the same day" is all the decisions need, a daily round plus a few smart sensors covers it. - **Remote fields with poor coverage,** where the traditional telemetry install alone costs more than continuous data is worth. And it breaks down in three recurring ways, even where it fits: **Over-alarming.** The system goes live, every deadband is wrong, and inside a week the alarm channel is muted. Rebuilding trust in the alarm list is harder than the original setup. **The SCADA Silo.** The host screen looks great on the office wall. The pumper never sees it, gets no alarms, and runs the same paper route. A platform that only talks to its own historian keeps the data locked where nobody outside the control room can use it. **No budget for support.** The rollout gets funded. The person to keep it alive does not. Within a year and a half the historian is full, the alarms have not been tuned since go-live, and half the RTUs are offline. ## Is There Low-Cost SCADA for Oilfields? Yes, if you are willing to shrink what "SCADA" means for each site. The producers who keep SCADA affordable do some version of four things: - **Scope it to the sites that pay it back.** Put full SCADA on compressor stations, disposal wells, and high-value pads. Leave the conventional wells off the integrator's scope. - **Rent the host instead of building it.** Hosted SCADA (eLynx, zdSCADA, Zedi, SCADAfarm) charges a monthly fee per site and runs the servers, so you skip the historian, the server room, and some of the IT burden. - **Pick licensing that does not punish growth.** A per-server license with unlimited tags, like Ignition, keeps the bill from climbing every time you add a sensor. Per-tag licensing does the opposite. - **Drop the controller where you only need to watch.** If a site needs eyes, not remote control, a cloud-connected sensor that reports straight to a dashboard does the job without an RTU, radio, or cabinet. The fourth one is where most of the savings live, and it is also where you stop buying SCADA at all. That is the next question. ## What Are the Alternatives to SCADA for Oilfields? There are four, and they are not interchangeable: | Alternative | What it gives you | Where it fits | |---|---|---| | **Hosted SCADA** | Real SCADA with the servers rented per site | Facilities that need control, run by a team without its own IT | | **Cloud-connected telemetry** | Sensors that report to a vendor dashboard, no RTU in the cabinet | Sites that need readings, not remote control | | **Drop-in remote monitoring** | Self-installed sensors, phone alerts, flat monthly rate | Conventional wells where SCADA never penciled, or old SCADA that is breaking down | | **A phone-based field app** | The pumper's gauges, run tickets, and downtime notes, same day | Every lease, alongside any of the above | If you already run Ignition and want to know when it is more than a site needs, read the [Ignition SCADA alternative](/blog/ignition-scada-alternative/) guide. For a side-by-side of the remote monitoring vendors producers compare most, see [oilfield monitoring alternatives](/blog/oilfield-monitoring-alternatives/). ### TinyPumper: the drop-in alternative TinyPumper is not SCADA and does not pretend to be. It does the one thing SCADA exists to deliver on a conventional site: you know what is happening at the well and the tank without being there. TinyPumper is 24/7 remote well monitoring for producing companies. A matchbox-sized, solar-powered gateway connects up to 8 sensors: a radar tank sensor that mounts on top of the tank with no fluid contact, pressure sensors for the wellhead, flowline, or injection line, and a built-in shake counter that tells you whether an engine or compressor is running. Your team self-installs it in 8 minutes, with no electrician, no trenching, and no integrator. Sensors report every hour and check thresholds every 5 minutes, so an alarm goes out the moment something crosses the line. It has 100% coverage across the continental U.S. because it uses satellite. Every TinyPumper comes with a 60-day money-back trial (we pay return shipping) and lifetime hardware replacement. Operators running TinyPumper report cutting lease runs by 30 to 50 percent and catching failures days sooner. The trade is continuous versus close enough. Full SCADA gives you second-by-second data and remote control. TinyPumper gives you hourly reads, 5-minute threshold checks, and immediate alerts. For a conventional well where SCADA never penciled, that is plenty. For an aging SCADA install, it is the drop-in replacement. TinyPumper's sister product, [Greasebook](https://www.greasebook.com), is the production app for the pumper's daily round. TinyPumper data flows straight into the Greasebook dashboard, so sensor readings and pumper-entered gauges, run tickets, and downtime notes live on one screen. For producers with a mix of sites, the practical answer is usually both: SCADA on the facilities and pads that need it, TinyPumper on the sites where it does not pencil, and Greasebook as the production record across all of it. ### Amateur vs Pro: How Producers Buy SCADA | The amateur... | The pro... | |----------------|------------| | Lets the vendor shortlist drive the decision | Maps sites by complexity and economics first, then picks vendors | | Compares platforms on feature tables | Compares total deployed cost at their actual sites | | Asks how much the license is | Asks what the build-out plus three years of support costs | | Signs the integrator before the coverage survey | Confirms coverage and power before a single quote goes in | | Rolls the flagship pad's system out everywhere | Runs SCADA where it pays back and drop-in monitoring where it does not | | Leaves the pumper out of the plan | Designs the alert path backward from the pumper's phone | ## What To Avoid Before You Sign the PO - **Do not let the integrator scope down from the host platform.** Scope up from site economics and buy only the layers that earn their keep. - **Do not skip alarm philosophy.** If tuning the alarm list is not in the scope of work, the system will look live and be deaf. - **Do not deploy SCADA without a field layer.** The office screen is half a system. Pair it with a phone-first tool for the route before go-live. - **Do not beat The Paper Lag with a six-month install.** If the real problem is pumper data arriving three weeks late, fix the capture layer with a phone app first. - **Do not trust the friendly monthly number on hosted SCADA.** The integrator build-out to get your instruments talking to it is still there. Get the full quote. - **Do not fund the rollout without funding the support.** If the ongoing cost cannot be funded, the initial cost should not be either. ## SCADA vs. Automation vs. IoT These words get used as if they mean the same thing. They do not. - **SCADA** is the stack that monitors and supervises distributed field equipment: controllers, a host, and screens. - **Oil and gas automation** is the broader idea of using logic and controls so the field runs without constant hands-on work. SCADA is one tool inside it. See [automation in the oil and gas industry](/blog/automation-in-oil-and-gas-industry/). - **IoT** is the newer pattern where sensors talk straight to the cloud, often with no traditional controller. See [IoT in oil and gas](/blog/iot-oil-and-gas-products/). ## Who This Page Is Not For If you already run a large horizontal program with full instrumentation, a controls team, and an operations center, you have made the SCADA call and this page is not trying to talk you out of it. Your question is which platform and which integrator, and the company list above is your refresher. The alternative section is for the producer who looked at a SCADA quote for conventional wells, or at the bill to keep aging SCADA alive, and wondered if there is a simpler answer. ## Related Guides - [What is SCADA](/blog/what-is-scada/): the plain-English fundamentals - [Ignition SCADA alternative](/blog/ignition-scada-alternative/): when full Ignition is more than a site needs - [Oilfield monitoring alternatives](/blog/oilfield-monitoring-alternatives/): the remote monitoring vendors producers compare most - [Oilfield monitoring](/blog/oilfield-monitoring/): the broader monitoring options - [Automation in the oil and gas industry](/blog/automation-in-oil-and-gas-industry/): when monitoring becomes control - [IoT in oil and gas](/blog/iot-oil-and-gas-products/): the sensor and telemetry layer - [Oil and gas production software](/blog/oil-and-gas-production-software/): the production record that sits on top of all of it

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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 SCADA in oil and gas?** SCADA stands for Supervisory Control and Data Acquisition. In oil and gas it is the hardware and software that reads sensors at wells, tanks, and facilities, sends the data to a central host, and lets the office watch, alarm on, and control equipment remotely. It is built for sites spread across a field, which is what separates it from the plant-floor control systems used in refineries. **Is SCADA hard to learn?** Reading SCADA screens and acknowledging alarms is easy to learn. Building and maintaining a system is not. Configuring controllers, tags, alarm limits, historians, and communications takes a trained controls tech or an integrator, and the system degrades fast when that person leaves. That ongoing skill requirement is one of the biggest hidden costs of SCADA, especially on conventional sites. **Is SCADA still used today?** Yes. Nearly every major and mid-size producer runs SCADA on instrumented pads and central facilities, and new systems go in every year. What changed is the hosting and the field layer. Many operators now rent hosted SCADA per site and use cloud-connected sensors and phone apps on the conventional wells where traditional SCADA never paid back. **What are the top SCADA platforms for oil and gas production?** The platforms producers run into most are Ignition, VTScada, AVEVA, Rockwell FactoryTalk View, and Siemens WinCC on the general-purpose side, plus oilfield-focused systems like eLynx, CygNet, zdSCADA, Zedi, and SCADAfarm. The right one depends on facility complexity, per-site economics, and whether you have a controls team or need a hosted service. **How much does a SCADA system cost for oil and gas?** There is no honest single number, because every site starts from a different place. The software license is usually the smallest part. The real spend is instruments, field controllers, telemetry, integrator labor, and the controls tech who keeps it running. Ask for the full build-out plus three years of support, per site, before comparing platforms or alternatives. **Which is better, DCS or SCADA, for oil and gas?** Neither is better; they do different jobs. A DCS (distributed control system) runs one plant in one place, like a refinery or gas processing plant, with tight control loops. SCADA watches and controls sites spread across a field, like wells, tank batteries, and compressor stations, over radio, cellular, or satellite. Upstream producers almost always need SCADA or a simpler remote monitor, not a DCS. **Can I run SCADA and a phone-based field app at the same time?** Yes, and most operators do. SCADA covers the facilities and instrumented wellheads. A phone app covers the manual gauges, the pumper's daily round, run tickets, and the wellheads without controllers. TinyPumper and Greasebook are built to sit alongside an existing SCADA system, so all of that data ends up on one screen. ===================================================================== # Oil and Gas Automation: Levels, Costs, and the Companies Behind Them > Automation in the oil and gas industry runs on four levels: equipment, wellsite, SCADA, and the daily data chain. What each level does, where it pays back, which companies sell it, and where SCADA stops making sense. Source: https://www.greasebook.com/blog/automation-in-oil-and-gas-industry/ Published: 2026-04-18 --- *This guide now combines our oil and gas automation guide, the industry overview, and the automation companies directory in one place.* **Short version:** oil and gas automation means letting controllers, sensors, and software handle routine field jobs so your people handle the exceptions. Automation in the oil and gas industry works on four levels: **equipment** (pump-off controllers, plunger lifts, dump valves), **wellsite** (RTUs and PLCs at the battery), **field** (SCADA tying sites to the office), and **the daily data chain** (gauges, run tickets, and reports). For an independent producing company, the cheapest wins sit at the bottom and the top of that stack. The middle layer, full SCADA, is where conventional-well budgets go to die. Spend by layer, not by sales pitch. A sales rep hands you a deck titled "Oil and Gas Automation." Slide three shows a lease running itself. Slide seven has a line about cutting your pumpers. Slide twelve is a payback curve that only goes up. None of it survives a frozen valve on a Tuesday morning in February. This guide is the version we give operators across the table. What automation covers, what each level does, where it pays back, which companies sell at each level, and where it stops making sense.

Automation Shouldn’t Require a SCADA Build.

See how producers running conventional wells get most of SCADA's upside without the price tag or the maintenance drag.

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**This page is for you if:** - You run anywhere from a handful of wells to 2,000+ and you've been pitched automation as the fix for everything from timing to labor. - You want to know which automation layers pay back and which ones turn into a science project. - You're comparing oil and gas automation companies and want to know who plays at which layer before you take another demo. - You've heard "you can cut your pumpers" and you don't buy it, but you want the honest picture before you push back. ## What is oil and gas automation? **Oil and gas automation (also called oilfield automation) is the use of controllers, sensors, and software to run routine production jobs (pumping, dumping, measuring, alarming, and reporting) with less hands-on work from field staff.** It covers a plunger lift timer on a single gas well, a fully instrumented tank battery that tickets its own barrels, and everything in between. The term is wide on purpose, and that's why vendor conversations fall apart so fast. A large horizontal program and a small stripper operation (wells making a few barrels a day) both run automation. They don't run the same thing. Here's the disambiguation that matters. **Automation is the category. SCADA is one tool inside it.** So are standalone controllers, wellsite PLCs, analytics platforms, and the software that turns field readings into production reports. When someone asks "how do I automate oil and gas operations?", the honest first answer is another question: which job, at which layer? ## What are the four levels of automation in oil and gas? Upstream automation stacks on four levels. Each has its own costs, its own vendors, and its own honest payback question. ### Level 1: Equipment automation Standalone devices with their own logic, often with no link back to an office: - **Pump-off controllers (POCs)** sense when a rod pump is pulling fluid faster than the well can give it, and rest the pumping unit until the well recovers. See our [pump-off controller guide](/blog/pump-off-controller/). - **Plunger lift controllers** time the cycle on gas wells loading up with water. - **Automatic dump valves and separator level controls** release liquids on level instead of waiting for a pumper to cycle the valve. - **High-level tank shut-ins** kill the well or divert flow before a tank runs over. - **Chemical injection pumps** put chemical in on a schedule or on flow. This is the cheapest, most widely installed kind of automation. Most operators with rod pumps already run POCs. None of it needs SCADA. ### Level 2: Wellsite automation An RTU (remote terminal unit) or PLC (programmable logic controller) at the wellhead or tank battery reads several instruments at once and coordinates them, usually with a local touch screen (HMI). Pumps start and stop, valves open and close, and LACT units (lease automatic custody transfer) ticket barrels without a person standing there. This is where real money starts. Instruments, transmitters, panels, and wiring add up fast, and the logic is usually built by an integrator. The question is whether continuous measurement at that site is worth the capital. On a high-rate horizontal, usually yes. On a conventional well making a few barrels a day, the math rarely lands the same way. ### Level 3: Field automation (SCADA) SCADA (supervisory control and data acquisition) pulls RTU and PLC data from many sites into a central screen, alarms on problems, stores history, and in mature setups lets the office change setpoints remotely. Platforms like Ignition, AVEVA, VTScada, and AutoSol compete here. A real SCADA build needs an automation engineer or a retained integrator, a host, communications, and ongoing upkeep. It is the right call on high-rate unconventional pads and anywhere a regulator wants continuous monitoring. On conventional wells it is the layer that stops penciling out. Either the capital never cleared the bar, or legacy SCADA is breaking down and costs more to keep running than it gives back. **Both happen at every scale, from a 50-well operator to a 5,000-well operator.** Our [oil and gas SCADA guide](/blog/oil-and-gas-scada/) goes deeper. ### Level 4: The daily data chain This is the layer most operators forget counts as automation: the workflow that turns field readings into decisions and filings. - **Production data capture.** Gauges, run tickets, and meter reads off paper and into a system the office sees the same day. - **Downtime tracking.** Tagging well events so you can see patterns across the fleet. - **Regulatory reporting.** State and federal monthly production filings. - **Accounting feeds.** Clean production numbers flowing into whatever oil and gas accounting system you already run. - **Route planning.** Sequencing the daily route, whether company pumpers or a contract pumping outfit does the field work. An operator with a messy month-end doesn't need a bigger SCADA budget. They need the daily data chain fixed. Most vendors don't sell this layer, and it's often the one that pays back first.
TinyPumper is the SCADA alternative for conventional wells.

Roughly 99% of SCADA's upside at about 95% less cost. You install it yourself in 8 minutes. Works at 50 wells. Works at 5,000.

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## What are the benefits of oil and gas automation? For a producing company the benefits are practical, not futuristic: - **Fewer wasted stops.** Your pumper drives to the wells that need him instead of every well on the route. Producers running TinyPumper report cutting lease runs by 30 to 50%. - **Failures caught days sooner.** A dead engine or a tank about to run over shows up as an alert, not on the next visit. - **Fewer spills.** High-level shut-ins and tank alerts stop the overflow before it becomes a cleanup. - **Safer days.** Fewer road miles and fewer solo trips to remote sites. - **Cleaner numbers sooner.** When the data chain is automated, the office sees production the same day and state reports are prepared from it instead of re-keyed. ## Where does oil and gas automation pay back first? The boring layers win. Every time. | If your pain is... | Start with... | Layer | |---|---|---| | Gas wells loading up or unloading on no real schedule | Plunger lift controllers | Equipment | | Rod pumps failing early, power bill creeping up | Pump-off controllers | Equipment | | Chemical truck shows up on a calendar, not on flow | Chemical injection tied to flow | Equipment | | Dump valves leaking or opening on the wrong trigger | Dump valve automation at your highest-volume battery | Wellsite | | Nobody knows a tank is full or a well is down until the pumper drives out | Remote monitoring of tanks, pressures, and runtime | Field | | Numbers run two to three weeks behind and month-end is a fire drill | A modern field app before any controls spend | Data chain | | "Our pumper can't keep up with his route" | Fix the data chain and route first, then automate | Data chain | What usually does **not** pay back: custom machine-learning tuning on every well, plans built on cutting the pumper, and a full controls stack bought before the monitoring underneath it works. ## How much does oil and gas automation cost? It depends on the layer, and the gap between layers is huge. | Level | What you pay for | How it's usually bought | |---|---|---| | Equipment (POC, plunger, dump valve) | The device, per well | Per-well capital, usually through a regional oilfield supply house | | Wellsite RTU + instruments | Hardware, instruments, panel work, integrator time | Per-site capital project | | Field SCADA + integration | Host, historian, communications, integrator, ongoing support | A fleet-wide capital program plus a standing maintenance line | | Daily data chain (field app) | Software subscription | Per well or per user, per month | | Remote monitoring without SCADA (TinyPumper) | $349 a sensor, one time. Then one flat rate a month per site, unlimited sensors. | No integrator, no IT team | Two costs get left off every vendor quote. **First, the person who keeps it alive.** Automation gets installed, works for six months, then drifts. **Second, the replacement cycle.** SCADA hardware ages out, and the bill to swap it is often what sends operators looking for something else. ## Who are the main oil and gas automation companies? You don't need a complete vendor list. You need the companies that play at the layer you're trying to fill. Here is who shows up in operator conversations, by layer. Not exhaustive, and every company named has customers who are happy with it for the right job. **Equipment level:** - **Lufkin** and **Weatherford:** pump-off controllers and rod pump diagnostics. - **ChampionX:** artificial lift software and rod pump controls. - **Kimray:** pressure controllers, dump valves, and production equipment. - **SignalFire** and **FreeWave:** wireless telemetry that links equipment to a network. Most producers buy equipment-level automation through a regional supply distributor, not straight from the manufacturer. **Wellsite level:** - **Rockwell Automation (Allen-Bradley):** PLCs and HMIs, a default in many oilfield RTU builds. - **Emerson:** ROC and FloBoss RTUs and flow computers. - **Schneider Electric** and **ABB:** PLCs, RTUs, and process automation, more common in midstream. - **AutoSol:** oilfield-focused RTU and flow computing with SCADA ties. Wellsite projects are usually delivered by integrators, firms that buy PLCs and instruments from the companies above and build the panel and logic for your site. **Field level (SCADA):** - **Inductive Automation (Ignition):** unlimited-tag licensing, now common across most U.S. basins. - **AVEVA:** enterprise SCADA across upstream, midstream, and pipeline. - **VTScada (Trihedral):** strong in Western Canada and the northern U.S. - **Rockwell FactoryTalk** and **Siemens WinCC:** paired with each company's own PLCs. - **Hosted SCADA for smaller operators:** zdSCADA, SCADAfarm, and Emerson's Zedi services. - **Legacy SCADA many conventional operators are trying to move off:** eLynx, zdSCADA, and PetroPower. Licensing is usually the small piece of a SCADA bill. Instruments, communications, and integrator hours are the big pieces. **Monitoring and data chain:** - **TinyPumper:** the SCADA alternative for conventional wells. A matchbox-sized, solar-powered gateway with radar tank sensors and pressure sensors that you install yourself in 8 minutes. Watches tank levels, pressures, and engine and compressor runtime. - **Greasebook:** the production app. Pumpers log gauges, pressures, run tickets, and photos on a phone. Greasebook prepares state production reports for any producing state, ready for you to submit, builds a missing form at no cost, and feeds clean production data into every major oil and gas accounting platform. - **Modern remote-monitoring vendors** such as iWell, Sensorfield, and Amplified Industries also play here. See our [oilfield monitoring guide](/blog/oilfield-monitoring/) for how they differ. ## How do you choose an oil and gas automation company? Match the vendor to the layer, then the layer to the operation. - **Conventional wells where SCADA never penciled out?** Put equipment controllers on the wells that need them (POCs, plunger lifts), then TinyPumper for remote tank, pressure, and runtime monitoring. Same answer at 50 wells or 5,000. - **Aging SCADA costing more to maintain than it returns?** Move the conventional wells to TinyPumper as the old sensors fail. Keep SCADA on the wells that still earn their keep. No rip-and-replace project. - **High-rate unconventional pads with an automation team?** Talk to Ignition integrators first, with AVEVA, VTScada, and AutoSol as alternatives depending on what your integrator knows best. - **Midstream or compression?** SCADA is a requirement. The platform usually follows your integrator's strengths and your control room's standards. Before you sign with anyone: - **Run a 60 to 90 day pilot at three sites.** A vendor who won't let you pilot is telling you how the rollout will go. - **Ask for customers who look like you.** Enterprise platforms built for refineries don't always scale down to conventional wells. - **Name the person who will own it after install.** A cheaper vendor with a dedicated maintainer beats a premium vendor with nobody in charge. ## Automation vs SCADA vs monitoring vs IoT: what's the difference? - **[Monitoring](/blog/oilfield-monitoring/)** is knowing what's happening. No control. - **[SCADA](/blog/oil-and-gas-scada/)** is monitoring plus remote control over many sites, built on PLCs and a central host. - **Automation** is the whole category of making the field run with less hands-on work. SCADA is one tool inside it. - **[IoT](/blog/iot-oil-and-gas-products/)** is the sensor-to-cloud approach: newer wireless sensors talking straight to a cloud platform. Modern stacks mix all four. The question isn't "do we have SCADA?" It's "what job needs doing, and which layer is the right tool for it?" ## Will automation replace your pumpers? No. Tanks still get hauled. Valves still fail. Lines still freeze in February. Someone has to show up when a sensor reads wrong. Automation cuts how often a pumper needs to make a routine stop. It doesn't remove the need for one. What changes is the job. Less driving to gauge a tank that didn't need it. More time on exceptions, mechanical work, and the judgment calls no sensor makes. Operators running TinyPumper report cutting lease runs by 30 to 50% and catching failures days sooner. That's the realistic payoff: the same people covering more ground with fewer wasted stops. ## Amateur vs pro: how operators roll out automation | The amateur... | The pro... | |---|---| | Buys automation to fix a troubled site | Fixes the mechanical or reservoir problem first, then automates the stable site | | Installs a full SCADA stack on day one | Starts with controllers and monitoring, proves the payback, then moves up | | Trusts the vendor's payback deck | Runs a 90-day pilot on three wells before a fleet-wide buy | | Plans to cut the pumper once automation is in | Redesigns the route and exception work around the automation | | Buys an analytics platform on top of bad data | Gets the measurement honest first, then asks software to find the signal | ## What to avoid: the traps that kill automation programs - **The automation-before-stabilization trap.** Automating a troubled site locks the problem in instead of solving it. Fix the well. Then automate the well. - **The orphaned RTU.** It works for 90 days, then it fails, nobody fixes it, and the site goes back to manual with more parts than before. If your team can't support it on day 91, don't buy it on day 1. - **The vendor-brochure pitch.** "You can cut your pumpers." You can't: a sensor flags the problem, and a pumper still has to fix it. - **Analytics before data.** A predictive model on bad sensor data is an expensive way to make noise. - **The skills gap.** Every controller and RTU needs someone who knows its logic. When that one person leaves, the system starts drifting. Pick tools your own team can run without a specialist. ## What oil and gas automation is not - **It isn't a one-time project.** It's a program with calibration, alarm tuning, sensor replacement, and controller updates. Budget for it every year. - **It isn't a substitute for field judgment.** Sensors report. People decide. - **It isn't one product.** Anyone selling "automation" as a single purchase is selling one layer and hoping you won't ask about the other three. - **It isn't always SCADA.** On conventional wells, the monitoring job SCADA was bought for can be done without the build. ## Where TinyPumper fits TinyPumper is the SCADA alternative for conventional wells. It handles the remote-monitoring job (tank levels, pressures, engine and compressor runtime) that most producers buy SCADA for, without the wiring, the integrator, or the IT burden. **The facts:** TinyPumper is a solar-powered gateway that connects up to 8 sensors, including radar tank sensors that never touch the fluid and pressure sensors at the wellhead, flowline, or injection well. You install it yourself in 8 minutes. Satellite gives it 100% coverage across the continental U.S. Pricing is $349 a sensor, one time, then one flat rate a month per site, with unlimited sensors at that site. Every unit comes with a 60-day money-back trial (we pay the return shipping) and lifetime hardware replacement. It delivers roughly 99% of SCADA's upside at about 95% less cost. TinyPumper data flows straight into the Greasebook dashboard, so producers running both see sensor readings and pumper-entered data on one screen. ## Who this page is not for If you're after downstream refinery automation, gas plant control systems, or an RFP list for a major operator's procurement team, this page isn't the right place. It's written for upstream producing companies (2 wells to 2,000+) deciding what automation means for their operation and where to spend first. Whether your field work is done by company pumpers or a contract pumping outfit, you, the producer, are the buyer.
Oilfield automation has two paths on a conventional well.

Expensive SCADA instrumentation on every piece of equipment, or a matchbox-sized gateway you install in 8 minutes that pushes tank levels, pressures, and runtime to your phone. TinyPumper is the second path, with a 60-day money-back trial and lifetime hardware replacement.

See how TinyPumper works →
## FAQ ### What is automation in the oil and gas industry? Automation in the oil and gas industry is the use of controllers, sensors, and software to run routine production work with less hands-on effort. Upstream, it stacks on four levels: equipment controllers like pump-off controllers and plunger lifts, wellsite RTUs and PLCs, field-wide SCADA, and the daily data chain that turns field readings into reports. Most producers need some of each level, not all of every level. ### What are the four types of automation? Textbooks list fixed, programmable, flexible, and integrated automation, which come from manufacturing. In an oil and gas operation the more useful split is by where the automation lives: on the equipment (pump-off controllers, plunger lifts), at the wellsite (RTUs and PLCs), across the field (SCADA), and in the office data chain (field apps and reporting). Each level has different costs and vendors, so decide by level. ### Will AI replace oil and gas jobs? Not the field jobs that keep wells producing. AI and automation can flag a failing well sooner or suggest a better plunger cycle, but they can't haul a tank, fix a frozen line, or swap a failed part. What changes is how the time gets spent: fewer routine stops to gauge a tank that didn't need it, more time on the problems a sensor flagged. ### How do I automate oil and gas operations? Start where the pain is biggest and the fix is simplest. That usually means plunger controllers on gas wells loading up, pump-off controllers on rod pumps failing early, and remote monitoring on tanks and pressures you currently check by driving out. Fix the daily data chain so the office sees production the same day. Leave full SCADA for high-rate sites where continuous control truly earns its keep. ### Who are the top oil and gas automation companies? On the industrial side, Rockwell Automation, Emerson, Schneider Electric, Siemens, and ABB lead. Inductive Automation (Ignition), AVEVA, and VTScada lead SCADA software. Lufkin, Weatherford, Kimray, and AutoSol are common oilfield-specific names. TinyPumper is the SCADA alternative for conventional wells, and Greasebook is the production app that sits alongside any of them. Pick by the layer you need filled, not by brand size. ### Is oilfield automation hard to learn? Using it is easy. Getting a text when a tank is high or seeing runtime on a phone takes no training. Building it is harder. Wellsite PLCs and SCADA need someone who can program controllers, set alarm limits, and keep communications working, and that skill is hard to keep on staff. Self-installed monitoring sits at the easy end: your pumper puts it on in 8 minutes and the alerts work from day one. ### How much does oilfield automation cost? It depends on the layer. Equipment controllers are per-well purchases. Wellsite RTU builds are per-site capital projects with integrator time. Full SCADA is a fleet-wide program with hosting and a standing maintenance line. A field app is a monthly subscription. TinyPumper is $349 a sensor, one time, then one flat monthly rate per site with unlimited sensors, and no integrator or IT team is needed. ## Related pages - [Oilfield automation](/blog/oilfield-automation/): the field-side view of automation at the wellsite. - [Wellsite automation](/blog/wellsite-automation/): what a fully automated well pad really includes. - [Pump-off controller](/blog/pump-off-controller/): the most common equipment-level automation. - [Oilfield monitoring](/blog/oilfield-monitoring/): the measurement layer underneath automation. - [Oil and gas SCADA](/blog/oil-and-gas-scada/): supervisory control stacks and where they fit. - [IoT in oil and gas](/blog/iot-oil-and-gas-products/): the sensor-to-cloud layer.

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.

===================================================================== # IoT in Oil and Gas: Oilfield IoT Sensors, Products, and Where They Pay Back > What IoT in oil and gas actually is, which oilfield IoT sensors and products are worth buying, how IoT differs from SCADA, and where it pays back for producers. Source: https://www.greasebook.com/blog/iot-oil-and-gas-products/ Published: 2026-04-18 --- A radar sensor sits on top of a stock tank on a conventional lease. It has reported every hour for three years. Nobody has opened the vendor dashboard since the engineer who installed it left. The sensor works fine. The IoT program is dead, because no alert ever reached the person who could do something about it. **TL;DR.** IoT in oil and gas means connected sensors at your wells, tanks and pipelines that send readings somewhere a person can act on them. For an independent producer, the oilfield IoT that pays back is a short list: radar tank sensors, wellhead pressure, engine and compressor runtime, pump-off controllers on rod pumps, and high-level tank shut-ins. Everything else is worth buying only when a specific decision depends on it. On conventional wells where SCADA never penciled, a right-sized site monitor like TinyPumper covers that short list without the SCADA bill. **What IoT is not:** it is not a substitute for a pumper walking the lease, and it is not a cheaper word for SCADA. It is a layer of sensors. You get value only when a reading changes a decision you would have made anyway, just later.

Not Every Well Needs SCADA. Every Well Needs Someone Watching.

See how producers monitor tanks, pressures and runtime on conventional wells without a SCADA rollout that never penciled.

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## Which IoT oil and gas products should my wells actually use? It depends on the site. For conventional wells where SCADA never penciled or is breaking down, TinyPumper fits: radar tank, pressure and runtime monitoring you install in 8 minutes, at $349 a sensor plus one flat monthly rate per site as of October 2026. For compressor stations, gas plants and disposal facilities that need real control, keep SCADA. At sales points, buy a proper flow meter from a measurement vendor like Micro Motion or Daniel. Where methane rules apply, use a dedicated emissions monitor such as Project Canary. For the pumper's daily gauges and run tickets, add Greasebook. ## What is IoT in oil and gas? **Oilfield IoT (the oilfield internet of things) is the stack of field sensors, telemetry, edge devices and cloud dashboards that collects readings from oil and gas equipment and routes them to the people and apps that act on them.** It overlaps with [SCADA](/blog/oil-and-gas-scada/), [automation](/blog/automation-in-oil-and-gas-industry/) and [oilfield monitoring](/blog/oilfield-monitoring/). Vendors use the words loosely, which is why the sales calls get confusing. When someone says "IoT" in the oil patch, they usually mean one of five things: - **Direct-connect sensors.** Battery or solar sensors (tank level, pressure, flow, temperature) that report straight to a cloud platform. No RTU, no radio network. - **Cloud data platforms.** Services that take in sensor or SCADA data and give you dashboards, alarms and history. - **Edge gateways.** Small rugged computers at the site that collect from local sensors or an existing PLC and decide what to send up. - **Equipment with sensors built in.** ESPs, rod pump controllers and compressors that ship with the vendor's own cloud. - **Digital oilfield programs.** The big-picture version where IoT feeds a model of the whole asset. See [digital oilfield](/blog/digital-oilfield/) for that framing. Most real deployments mix two or three of these. ## Which IoT devices and products are used in oil and gas? The category matters more than the brand. Here are the device types that actually get deployed, and the honest fit for each. | Category | What it does | Typical vendors | Honest fit for independents | |---|---|---|---| | **Tank level sensors** | Read oil, water or saltwater tank levels without a pumper gauging | SignalFire, FreeWave, Sutron, Banner, Rosemount | Yes, on most tank batteries. Radar on top beats submersibles that foul and freeze | | **Wellhead and flowline pressure** | Continuous casing, tubing or flowline pressure | Emerson Rosemount, Yokogawa, ABB, WellAware | Yes, where pressure moves fast or setpoints matter | | **Rod pump and artificial lift monitors** | Rod load, stroke data, pump-off detection | Lufkin SAM, Weatherford, Ambyint | Yes on rod-pumped wells without a pump-off controller | | **Flow meters** | Measurement for allocation, custody transfer, reporting | Micro Motion, Daniel, Barton, Krohne | Required at sales points; a measurement station, not a casual sensor | | **Emissions and flare monitors** | Methane detection, flare status | Project Canary, LongPath, Kuva, Flogistix | Where methane or flaring rules require it | | **Connectivity gateways** | Get readings off the lease by radio, cellular, LoRaWAN or satellite | FreeWave, Digi, Cradlepoint, Starlink | Always needed. The most overlooked line in the budget | | **Asset trackers, cameras, vibration** | Trucks, security, rotating equipment health | Samsara, Geotab, Bently Nevada | Niche. Buy for a named problem only | **The one most IoT articles skip:** the production app that ties sensor readings and the pumper's daily visit into one record. It is not a sensor. It is the layer that turns readings into a decision. ## What are the benefits and uses of IoT in oil and gas? For a producer, IoT earns its keep in five upstream jobs: | Use | What the sensor catches | The benefit | |---|---|---| | Tank batteries | A tank filling too fast, or not at all | Fewer overflows, haul trucks sent at the right time, theft spotted sooner | | Wellheads and flowlines | Pressure that drops or climbs off its normal line | A leak or freeze-off found the day it starts | | Engines and compressors | A unit that stopped running | Downtime measured in hours, not days | | Saltwater disposal and injection | Water levels and injection pressure | Pressure alarms set below your permit limit, so a problem shows up before it becomes a shut-in | | Remote leases with no signal | Readings sent over satellite | Sites that used to go unwatched get the same coverage as the close ones | The benefits add up the same way every time: fewer wasted trips, failures caught sooner, fewer spills, and safer days for the pumper, who drives to the wells that need him instead of every well on the route. ## How is oilfield IoT different from SCADA? They overlap, but they start from different defaults. | Dimension | SCADA default | IoT default | |---|---|---| | Where the data lives | On-prem server and historian | Cloud platform | | Field device | PLC or RTU in a cabinet | Sensor or small gateway | | Install | A crew, wiring, weeks per site | Hours or less per site | | Control | Yes, runs control loops | Mostly measurement and alerts | | Who maintains it | IT staff or a SCADA host | The vendor's cloud | **Neither one wins everywhere.** SCADA is the honest tool for supervisory control of a compressor station, gas plant or disposal facility. IoT is the honest tool for point measurements across lots of scattered sites where an RTU per site never paid back. | If you... | Then... | Because | |---|---|---| | Need control of a compressor station or gas plant | Keep SCADA | Control loops and operator screens are not an IoT strength | | Need tank levels at stock tanks across three counties | Use right-sized IoT sensors | An RTU per tank battery never penciled | | Have aging SCADA that costs more to keep alive than it is worth | Replace those sites with a drop-in site monitor | You keep the readings and drop the maintenance drag | | Run conventional and horizontal wells | You will run both | SCADA where the math worked, IoT on the rest | ## Which IoT sensors pay back on an independent producer's wells? For producers running anywhere from a handful of wells to 2,000+, only a few IoT sensors for oil fields pencil out on most wells, and scale does not change that. A practical mix looks like this: - **Pump-off controllers** on rod-pumped wells that lack them. - **Radar tank sensors and wellhead pressure** on conventional sites where SCADA broke down or never got installed. - **Engine and compressor runtime** so you know a unit died before the pumper finds it. - **High-level tank shut-ins.** Cheap, often required, safety first. - **A flare monitor** where your state requires one. - **A production app** that holds the daily gauges, run tickets and downtime next to the sensor data. **This is where TinyPumper fits.** It is a matchbox-sized, solar-powered gateway with radar tank sensors and pressure sensors. Each gateway handles 8 sensors and also detects whether an engine or compressor is running. You install it yourself in 8 minutes, with no electrician and no trenching. Operators running it report **30 to 50% fewer lease runs** and catching failures days sooner.
On conventional wells where SCADA never penciled, there is an honest alternative.

TinyPumper is 24/7 monitoring for tanks, pressures and runtime. Installs in 8 minutes. Flat rate per site, unlimited sensors. Roughly 99% of the upside of SCADA without the cost or the complexity, at 50 wells or 5,000.

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## How much do IoT sensors for oil and gas cost? Vendor pricing swings widely, and most quotes leave out two lines: **telemetry** (the monthly fee to get readings off the lease) and **upkeep** (batteries, calibration, firmware). Budget the recurring line, not just the hardware. Across a few hundred sites, the monthly fees usually end up bigger than the sensors. TinyPumper prices it differently, and publicly: **$349 a sensor, one time. Then one flat rate a month per site, unlimited sensors.** No setup fees and no separate carrier bill. That flat rate is why the math works on wells where per-sensor pricing never did. Compared with a SCADA install, TinyPumper runs about **95% cheaper**. ## How do you connect equipment in remote oilfields? Connectivity kills more IoT projects than bad sensors do. The common options: - **Licensed or unlicensed radio** (FreeWave and similar). The old default for SCADA networks. - **Cellular.** Cheap where there is signal, useless where there is not. - **LoRaWAN.** One gateway picks up many low-power sensors across a pad. - **Satellite.** Works anywhere with sky. The answer for dead zones. **Check the real signal at the real site before you buy.** "Cellular everywhere" is a sales assumption. TinyPumper uses satellite, which gives it 100% coverage across the continental US, so dead zones stop being a reason to leave a lease unmonitored. It is rated from -40°C to 70°C and is deployed in North Dakota, Canada and Alaska. ## Why do oilfield IoT projects fail? - **Nobody owns the alert.** A reading in a dashboard nobody opens is the paper lag with a monthly fee. Route the alert to the pumper's phone before the sensor ships. - **Five vendors, five logins.** Every vendor brings its own cloud. Pick one place where field data and sensor data meet before you add vendor number two. - **Power assumptions.** Solar that works in a Permian July can struggle in a Bakken January. Spec for your worst month. - **Buying the sensor before the decision.** Write down what you will do differently when the reading crosses a line. If you cannot, skip the sensor. - **Expecting IoT to replace SCADA on a facility that needs control.** It will not. Use each where it fits. ### Amateur vs Pro: How Producers Roll Out Oilfield IoT | The amateur... | The pro... | |---|---| | Orders a hundred sensors before checking signal at the lease | Tests one device at the actual site before the purchase order | | Picks the vendor with the best slide deck | Pilots at three sites with different comms before committing | | Lets readings die in the vendor's portal | Routes every alarm to the person who can act | | Skips the pumper because "the sensor will see it" | Treats the pumper and the sensor as two tools with different jobs | | Treats IoT as a one-time project | Budgets for batteries, calibration and firmware every year | A sensor tells you the tank is at 78%. A pumper tells you the tank is at 78%, the stuffing box is leaking and the gas line has a pinhole. **You need both.** That is also where [Greasebook](https://www.greasebook.com), our production app, comes in: it puts the pumper's daily gauges, comments and run tickets on the same screen as the TinyPumper readings, and it prepares state production reports for any oil and gas producing state. ## What should you know about TinyPumper before you buy? TinyPumper is remote well monitoring for producers. It watches tank levels, pressures and engine or compressor runtime. The sensor reads every hour, and it also checks thresholds every 5 minutes, so an alert goes out right away when something crosses the line. You install it yourself in 8 minutes. Hardware is $349 a sensor, one time; service is one flat monthly rate per site with unlimited sensors. Satellite gives it 100% coverage across the continental US. Every sensor carries a lifetime hardware replacement, and you get 60 days to try it with a full refund if it does not earn its keep (we pay the return shipping). It is the sister product to Greasebook, and its readings flow into the Greasebook dashboard. ## Who this page is not for If you are building a multi-field IoT RFP for a major, or you need supervisory control of a gas plant or compressor station, this page is too ground-level. It is written for the producer deciding which sensors belong on which wells. ## FAQ ### What are the top industrial IoT choices for oil and gas site monitoring? For site monitoring on conventional wells, the choices are full SCADA (RTUs, radio networks, a host), point sensors from vendors like SignalFire or FreeWave, or a right-sized site monitor such as TinyPumper that covers tanks, pressures and runtime from one gateway. SCADA fits facilities that need control. Site monitors fit scattered wells where an RTU per site never paid back. The best choice is the one that matches how many sites you have and who will act on the alerts. ### What are the four types of IoT devices in oil and gas? A common grouping is sensors and transmitters (pressure, level, flow, temperature), actuators and controllers (valves, pump controllers, RTUs), connectivity devices (radios, cellular modems, satellite modems) and edge devices (PLCs and gateways with local logic). Most oilfield deployments use all four. For an independent producer, the sensors and the connectivity are where most of the money and most of the failures sit. ### What are the 5 C's of IoT? The five C's are usually listed as Connect, Collect, Communicate, Compute and Collaborate. Connect the device, collect the reading, send it somewhere useful, analyze it, and share it with the people who act. In oil and gas the weak links are the last two. Plenty of producers collect good data that never reaches the pumper or the owner in time to matter. ### How much do IoT sensors cost? Vendor prices vary widely, and the monthly telemetry fee is often the bigger cost over a few years. Ask every vendor for the hardware price, the monthly fee per sensor or per site, and the upkeep plan. TinyPumper publishes its model: $349 a sensor, one time, then one flat monthly rate per site with unlimited sensors, so adding a sensor at a site does not raise the monthly bill. ### Can IoT replace SCADA? On conventional wells where SCADA never penciled, or where aging SCADA costs more to maintain than it is worth, yes: a site monitor gives you the readings and alerts without the cabinet, wiring and host. On facilities that need real supervisory control, such as compressor stations, disposal facilities and gas plants, no. Keep SCADA there and use IoT on the rest of the field. ### Is TinyPumper an IoT platform? Yes, in the practical sense. TinyPumper is a solar-powered gateway with radar tank sensors and pressure sensors that sends readings to the cloud and alerts you when a threshold is crossed. Each gateway handles 8 sensors, and you install it yourself in 8 minutes. It is built as the SCADA alternative for conventional wells, at 50 wells or 5,000, and its readings flow into the Greasebook dashboard. ## Related Pages - [Oilfield monitoring](/blog/oilfield-monitoring/): the monitoring category, from tank levels to runtime. - [Oil and gas SCADA](/blog/oil-and-gas-scada/): when SCADA is the right tool and when it is overkill. - [Automation in the oil and gas industry](/blog/automation-in-oil-and-gas-industry/): where automation pays back on producing wells. - [Digital oilfield](/blog/digital-oilfield/): the bigger-picture version of connected operations.

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.

Think of traditional SCADA as one of those 1980s ADP home alarm systems. Complex, expensive, a tech at your house all day drilling holes and running wires.

TinyPumper is more like Ring or SimpliSafe for the oil patch. Arrives ready to install, 8 minutes, no special tools, no trenching. Unlimited sensors per site. Flat rate. 60 days to try it, and lifetime hardware replacement on every sensor.

See how TinyPumper fits →
**P.S.** Pick the person who owns the alert before you pick the sensor. The hardware almost never fails first. The follow-through does.
===================================================================== # Oilfield Tank Monitoring: Tank Battery Levels, Alarms, and Sensors That Hold Up in the Field > Oilfield tank monitoring explained for producers: how tank battery level sensors and alarms work, what to watch on crude and produced water tanks, and when SCADA is overkill. Source: https://www.greasebook.com/blog/oilfield-tank-monitoring/ Published: 2026-10-17 --- **Short version:** Oilfield tank monitoring tells you the level in every crude, condensate, and produced water tank on a tank battery without sending a pumper to gauge it. A sensor reads the level, a gateway sends it out, and your phone gets an alert before a tank runs over or a haul comes up short. Full SCADA still fits sites where you need to shut in or control equipment from the office. On conventional tank batteries where SCADA never penciled, a self-installed monitor like [TinyPumper](https://tinypumper.com) covers the job without the project. It's Sunday afternoon. The water tank on the north battery is climbing because a flowline started carrying more water on Friday. Nobody gauges on Sunday. By Monday morning there's saltwater on the pad and a phone call you don't want to make. Tank monitoring exists for that weekend. **This page is for you if:** - You run tank batteries and you find out about full tanks, short hauls, or leaks after the fact. - You schedule crude and water haulers off a gauge sheet that is a day or two old. - You were quoted SCADA for your batteries and the math never worked. - You want to know what tank monitoring really takes before you buy anything. The size of your operation doesn't decide this. A producer with a few batteries and one with hundreds ask the same question: what does this site need to see? ## Which oilfield tank monitoring setup fits my tank batteries? Oilfield tank monitoring means reading crude, condensate, and produced water tank levels on a battery remotely, with alarms that reach your phone. It is not custody-transfer gauging. The right setup depends on the site. If a tank needs automatic shut-in, valve control, or certified gauging, buy SCADA. If you run a few tanks your pumper sees daily, hand gauging logged in Greasebook may be enough. If you need levels and high-tank alerts between visits on conventional batteries where SCADA never penciled, TinyPumper fits at any well count. Many producers run TinyPumper and Greasebook together. ## What is oilfield tank monitoring? Oilfield tank monitoring is the practice of reading tank levels at a producing site remotely and acting on them. It covers the stock tanks that hold crude or condensate, the water tanks that hold produced water, and the alarms that fire when a level crosses a line you set. It is not the same as tank gauging for a run ticket. A run ticket is a measured, witnessed number for custody transfer. Tank monitoring is the running picture in between. On a typical battery that means: - **Crude and condensate tanks.** How full they are, how fast they are filling, and when a haul is due. - **Produced water tanks.** The tanks that run over first, because water rates move more than anyone expects. - **High and low alarms.** A high-tank alarm before a run-over. A sudden drop that points to a leak, a theft, or an unplanned haul. - **Fill rate.** A tank filling slower than last week often means a well problem upstream, not a tank problem. Tank monitoring is one piece of [oilfield monitoring](/blog/oilfield-monitoring/). The same site usually has pressures and pump runtime worth watching too.

Not sure what your batteries need?

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## How do oilfield tank monitors work? Every tank monitor that works in the field has the same four parts. 1. **A level sensor on the tank.** It reads how much fluid is in the tank. 2. **A way to get the reading off the lease.** Radio, cellular, or satellite. On remote leases this is where most systems fail. 3. **Software that shows the level and sends the alert.** A dashboard nobody opens is not monitoring. The alert has to reach a phone. 4. **A person who acts.** Someone owns the alert: call the hauler, send the pumper, or shut the well in. Skip any one of the four and you paid for a gadget, not a system. The fourth part is the one most producers forget. Before you buy, decide who gets the high-tank alert at 2 AM. ## How does a level reading turn into barrels? A tank sensor reports a level: feet and inches of fluid. Barrels come from the tank's gauge table, often called a strapping table, which converts height to volume for that size and shape of tank. Every stock tank on a battery should have one, and the same table your pumper uses to turn a hand gauge into barrels works on a sensor reading. Before you buy any monitor, ask two things. Do readings come back as a level, as barrels, or both? And who keeps the tank tables current when a tank gets swapped? A level alarm works either way. Haul planning and missing-barrel checks need barrels. ## How can I monitor tank levels on a tank battery? There are three common ways, and most producers use more than one. | Method | What it gives you | Where it breaks | |---|---|---| | Pumper gauging by hand | An accurate reading once a day, plus eyes on the site | Nothing between visits. Weekends and bad roads leave gaps | | SCADA with tank level transmitters | Continuous levels, plus control: shut-ins, valves, setpoints | Install and upkeep cost. Often never pencils on conventional batteries | | Self-installed tank monitor | Levels and alarms on your phone between visits | It reads and alerts. It does not shut the well in | Hand gauging stays. A pumper on site catches leaks, smells, and a bad dump valve that no sensor sees. Monitoring is what covers the hours when nobody is there. ## What is tank battery monitoring? Tank battery monitoring is tank monitoring at the battery level: every stock tank and water tank on one pad, watched as one site. That matters because tanks on a battery are connected. Oil and water move through the separator and treater into different tanks, and one problem shows up in several places. What to watch on a battery: - **Every tank, not just the first one.** When the first stock tank fills and the equalizer line carries oil to the next, the second tank's level is the one that matters. - **The water side.** Produced water tanks fill on their own schedule and they run over first. - **Fill rate by tank.** A change in how fast a tank fills is often the earliest sign a well upstream changed. - **Unexpected drops.** A level that falls with no haul scheduled is worth a call that same hour. If you are laying out a new battery, our walkthrough on [tank battery design](/blog/tank-battery-design/) covers how tanks, lines, and the separator fit together. ## What is the best tank level alarm for a tank battery? The best alarm is the one that reaches a person in time and doesn't cry wolf. In the oilfield that comes down to three things. - **It reaches a phone, not just a light on site.** A horn or a beacon helps only if someone is standing there. - **You set the line.** High-tank and low-tank levels should match each tank and your haul schedule, not a factory default. - **It keeps watching between readings.** A sensor that only checks in on a slow schedule can miss a fast-filling water tank. Ask how the alarm is checked, not just how often the level is reported. A high-tank alarm prevents a run-over. A sudden-drop alarm catches a leak or a load that wasn't supposed to leave. Most producers want both. ## Which tank level sensor holds up in the field? Sensor type decides how long the system lasts. Here are the common choices and how each fares on a producing site. | Sensor type | How it reads | Field reality | |---|---|---| | Radar on top of the tank | Bounces a signal off the fluid surface | No fluid contact. Nothing to corrode, foul, or freeze | | Float and magnetic gauges | A float rides the fluid surface | Paraffin, ice, and stuck floats give bad readings | | Submersible pressure sensors | Sit in the fluid and read its weight | Corrode, foul, and freeze. Pulling one is a job | | Hand gauge and tape | A pumper gauges through the thief hatch | Accurate for run tickets. Only as current as the last visit | TinyPumper uses radar on top of the tank. It never touches the crude or the brine, so it works on oil, water, and saltwater tanks the same way. ## How much does oilfield tank monitoring cost? The cost of tank monitoring is mostly about what the system asks of you, not just the sticker price. Line items to price out: - Sensors for each tank you care about. - The gateway or controller that carries readings off the lease. - Communications, monthly. - Software and alerts, monthly. - Install labor: an electrician, trenching, or an integrator, or none. - Upkeep: who fixes it when a sensor fails, and what that costs. TinyPumper's pricing is simple on purpose: **$349 a sensor, one time. Then one flat rate a month per site, unlimited sensors.** The client self-installs in 8 minutes. No electrician, no trenching. Every sensor has lifetime hardware replacement, and you have 60 days to try it with your money back if it isn't worth it. ## When is SCADA the right call for tanks? Sometimes. SCADA earns its keep where a tank needs control, not just eyes: - Automatic shut-in when a tank hits high level. - Large facilities where tanks, compression, and safety systems are tied together. - Custody transfer points that need certified tank gauging. On a conventional tank battery that needs to be watched, not controlled, SCADA is usually more system than the site needs. That's where a self-installed monitor fits. Our guide to [oil and gas SCADA](/blog/oil-and-gas-scada/) walks through where the line sits. ## What oilfield tank monitoring is not - **It is not custody-transfer gauging.** Run tickets still need a measured, witnessed gauge. - **It is not control.** A monitor tells you a tank is high. It does not close a valve. - **It is not a home heating oil gauge.** Those products are built for one tank in a basement, not a battery of crude and water tanks on a lease. - **It does not replace the pumper.** A sensor flags the problem. A pumper still has to fix it. ## Who is this not for? If you need a gauge for a home heating oil tank or a shop fuel tank, this page and this product are not for you. If your sites need automatic shut-in, valve control, or certified custody-transfer gauging, you need SCADA or a dedicated tank gauging system. Midstream terminals and refineries running tank farms on DCS-grade systems are also outside what this page covers. ## Where TinyPumper and Greasebook fit **TinyPumper** is a self-installed remote monitoring system for producers. A matchbox-sized, solar-powered gateway carries readings from radar tank sensors and pressure sensors on the site, and it watches engine and compressor runtime too. It self-installs in 8 minutes with 100% coverage across the continental US over satellite. Pricing is $349 a sensor, one time, then one flat rate a month per site. Every sensor carries lifetime hardware replacement, and there is a 60-day money-back trial with return shipping paid. It works whether you run a handful of wells or thousands. **Greasebook** is the production app pumpers use to record gauges, run tickets, and downtime. Tank monitoring watches the tanks between visits. Greasebook keeps the daily production record clean. Many producers run both. For the full picture of what to watch on a site beyond tanks, see the [oilfield monitoring systems guide](/blog/oilfield-monitoring/). Comparing vendors? Our [monitoring alternatives breakdown](/blog/oilfield-monitoring-alternatives/) lays them side by side, and produced water operators should read the [saltwater disposal monitoring](/blog/saltwater-disposal-monitoring/) guide.

See your tank levels between visits

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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 ### How can I monitor my oil tank level remotely in the oilfield? Put a level sensor on each tank, connect it to a gateway that sends readings off the lease, and set alerts that reach your phone. On a producing site, a radar sensor on top of the tank is the most durable choice because it never touches the crude or produced water. TinyPumper does this with one solar gateway per site and a self-install that takes about 8 minutes. ### How do oil tank monitors work on a tank battery? A sensor reads the fluid level in each stock tank and water tank. A gateway on the battery sends those readings out by radio, cellular, or satellite. Software shows the levels and sends an alert when a tank crosses a line you set. The last piece is a person who owns that alert and calls the hauler or sends the pumper before a tank runs over. ### What is the best oil tank alarm for an oilfield site? The best alarm reaches a phone, not just a light on site, lets you set the high and low lines for each tank, and keeps checking between regular readings so a fast-filling water tank doesn't slip past. Most producers want a high-tank alarm to prevent run-overs and a sudden-drop alarm to catch leaks or loads that weren't scheduled. ### Why is it called a tank battery? A tank battery is the group of tanks, separators, and treaters on a lease where production from one or more wells is separated and stored. The name comes from the tanks standing in a row, like a battery of equipment. Oil goes to the stock tanks and produced water goes to water tanks, and haulers or pipelines take it from there. ### Do I still need a pumper if I monitor my tanks? Yes. Monitoring covers the hours when nobody is on site, but a pumper still gauges for run tickets, checks equipment, and catches problems no sensor sees, like a bad dump valve, a smell, or a leak on the ground. Most producers find monitoring cuts wasted trips to full or empty tanks, so the pumper spends time on the problems that need a person.