Guess low and the line freezes off at four in the morning. Guess high and you pump thousands of gallons a year you never needed — most gathering systems run 30 to 35 gallons per MMscf when 10 to 15 would hold the line. This works out the hydrate temperature, the subcooling, the concentration you actually need and the dose in gallons a day, while you stand at the wellhead.
One-time purchase. No subscription. No account. Works offline at the wellhead.
Hydrates plug a choke or a flowline and the well is down until somebody thaws it. That risk is why the injection rate gets turned up and never turned back down.
Nothing on the lease tells you the rate is too high. The well keeps flowing, the chemical truck keeps coming, and the cost sits in an account nobody questions.
Field estimates count produced water and forget the water condensing out of the gas as it cools. Both are free water. Both have to be inhibited.
The hydrate curve and the water-content chart are in the GPSA data book. Nobody carries it to the wellhead, so the rate is a habit rather than a calculation.
Every calculation ends with one number you can take to a chemical review: gallons of inhibitor per million standard cubic feet of gas. The app flags where yours sits against the published gathering-system bands.
Bands from GPA gathering-system optimisation work. Methanol is also a listed hazardous substance under EPCRA, so trimming over-injection trims your reportable inventory as well as the invoice.
| Step | Method | What it gives you |
|---|---|---|
| Hydrate temperature | Towler & Mokhatab (2005) | The temperature hydrates start forming at your pressure and gas gravity |
| Subcooling | HFT − flowing temperature | How far below the hydrate point you are running right now |
| Required concentration | Hammerschmidt (1939), inverted | Weight percent of methanol or MEG the free water has to reach |
| Water content of the gas | Bukacek (1959) | How much water condenses out as the gas cools to line temperature |
| Dose to the liquid | Material balance on free water | Pounds per day into the aqueous phase |
| Vapour loss | Methanol partition to gas phase | The methanol you never see again — the term field estimates skip |
| High-concentration check | Nielsen-Bucklin (1983) | A warning above 25 wt%, where Hammerschmidt over-predicts |
Method chain per GPSA Engineering Data Book Section 20 practice. Every formula and the substituted numbers are shown in the app and on the printed dosing sheet, so any result can be checked by hand.
Every hydrate correlation needs psia. The gauge reads psig. Forget the 14.7 and the hydrate temperature shifts several degrees — and the answer still looks plausible.
A dry gas well with no produced water still drops water out of the gas as it cools. Count only the produced barrels and you under-dose.
Methanol partitions into the gas phase and leaves with it. It is a real term, and it is a large part of why methanol usage runs so much higher than glycol.
MEG's vapour pressure is negligible. Carry the methanol vapour term across to glycol and you overstate the MEG dose badly.
If a regenerated stream is weaker than the concentration it has to reach, the material balance has no solution. Spreadsheets print a negative dose. This tells you why.
Towler & Mokhatab is fitted for sweet gas, 0.55 to 1.00 gravity. Outside that band the app refuses rather than quietly giving you a number.
Both silent-failure cases — gauge-to-absolute conversion and the impossible lean stream — are handled explicitly, because a wrong dose that looks reasonable is worse than no dose at all.
Illustrative example of the calculator at the worked case in the manual, not a product screenshot.
Change the pressure, the temperature, the safety margin or the chemical price and every number updates as you type. Drag the margin from 5 °F to 10 °F and watch what the extra insurance costs per month before you commit to it.
The hydrate curve is drawn from the same correlation at your gas gravity, from 100 to 3,000 psia, with your operating point marked on it. Above the line is safe, inside the shaded region hydrates form. It makes the margin obvious at a glance, and it prints on the dosing sheet.
Save each well or line as a named input set and flick between them. A route operator checks six sites in the time it takes to open a spreadsheet. Everything stays on your device — no account, no upload, no backend.
Print a one-page dosing sheet with the inputs, the results, the verdict, the formulas and the hydrate curve, with signature lines for calculated-by and reviewed-by. Export every saved well to CSV with all inputs and all computed outputs when the chemical review comes round.
Sweet gas only. H₂S and CO₂ raise the hydrate temperature significantly and are not modelled — the app says so on screen rather than quietly giving you a number. Salt in the produced water already depresses the hydrate point, so a dose calculated here is conservative on a salty system. This is an engineering estimate against published correlations, not a process simulation and not a replacement for your operator's chemical programme. Every formula is shown so any result can be checked by hand.
Built by people who have worked the lease. Oil Rigs Now has been making tools for oilfield professionals since 2011 — field-first, offline-first, and priced so a pumper can expense it without asking anyone.
Everything stays on your device. Nothing is uploaded, no account is created, and the calculator keeps working when the lease road has no bars.