OOIP, OGIP, Recoverable Volume and Reserves: The Difference

Original oil in place (OOIP) and original gas in place (OGIP) estimate how much petroleum an accumulation originally contained on a defined volume basis. A recovered quantity answers a further question about how much a stated process or project might produce. Reserves adds project and commercial requirements. These terms describe different information, so a larger calculator result is not automatically a larger reserves estimate.

The worked example builds a gas volume from rock geometry, porosity, initial water saturation and a compatible gas formation volume factor. It then applies a plainly hypothetical recovery fraction as separate arithmetic. The interactive control changes only that assumption. It does not assess a development project or assign a formal resources class. Use the official PRMS reference for those classifications.

Area multiplied by net thickness gives the rock volume included in a simple uniform reservoir model. With area in acres and thickness in feet, multiply by 43,560 to obtain cubic feet. For 160 acres and 50 ft, bulk rock volume is 348,480,000 ft³. This number includes the solid rock framework as well as its pore space; it is not a petroleum volume.

Multiply by porosity 0.15 to obtain 52,272,000 ft³ of pore volume. Under this example's initial gas-and-water occupancy assumption, water saturation 0.25 leaves gas occupying 75% of those pores. The initial gas-filled pore volume is therefore 39,204,000 reservoir ft³. The calculation does not establish net pay, spatial variability or saturation from raw measurements; those are supplied interpretations.

The initial gas formation volume factor Bgi relates gas volume at initial reservoir conditions to its volume at the stated standard conditions. Here Bgi is 0.005 reservoir ft³ per standard cubic foot. Dividing 39,204,000 reservoir ft³ by that factor gives 7,840,800,000 scf, or 7.8408 billion standard cubic feet. The reservoir-volume unit cancels, leaving a standard-condition gas volume.

Write the reference pressure and temperature behind the chosen standard cubic foot when preparing a real case. Also check the numerator units: a Bg supplied in reservoir barrels per scf cannot be entered unchanged into this cubic-foot form. The example treats the gas phase and its supplied Bgi consistently; it does not infer a gas composition or separator-product specification from a volumetric estimate.

OOIP is commonly reported as a stock-tank oil volume, while OGIP is commonly reported as gas volume at specified standard conditions. Their formation volume factors relate different reservoir and surface volumes. A quantity stated in reservoir barrels, stock-tank barrels or standard cubic feet needs its label retained throughout the worksheet. The words 'in place' describe the original quantity being estimated, not the physical conditions of the reported unit.

An in-place estimate can also come from material balance when production, pressure and fluid data support the chosen model. The linked general oil material-balance calculator rearranges an oil balance using compatible withdrawal, influx and expansion terms. It estimates N on a stock-tank oil basis. That is a different calculation route from this gas geometry example, and it still does not independently determine a project's commercial recoverable quantity.

For a teaching assumption of 60% recovery, multiply the calculated OGIP by 0.60. The result is 4.70448 billion scf of assumed recovered gas on the same volume basis. The remaining arithmetic complement is 3.13632 billion scf. Neither number is a forecast derived from a reservoir drive model; the recovery fraction is an input selected for this exercise.

Changing that fraction must leave the in-place estimate unchanged. The explorer keeps geometry, saturation and Bgi fixed so the distinction is visible. A recovery model for an actual accumulation would need additional information about its process, pressure behavior, displacement, wells and operating constraints. A convenient round percentage is not evidence that those conditions support that recovered volume.

PRMS treats reserves as remaining quantities expected to be commercially recovered through defined development projects in known accumulations under stated conditions and at an evaluation date. Classification therefore calls for information about discovery, recoverability, commerciality and the project. The official document provides the detailed criteria. A geometric quantity and an assumed recovery percentage provide only part of that information.

For this synthetic case, no development project, costs, production schedule or commercial assessment has been supplied. The honest output label is 'assumed recovered volume at 60%,' followed by its gas basis. Do not attach a reserves category to the result or interpret the slider's low and high settings as proved, probable or possible volumes. The control explores arithmetic sensitivity rather than uncertainty categories or project maturity.

Keep a short ledger that separates supplied reservoir inputs, calculated in-place volume and the separately assumed recovery fraction. Record the date and basis of each input interpretation. If a later model changes porosity, net thickness or Bgi, recalculate the in-place line before comparing recovered quantities. If only the assumed fraction changes, the original geometric estimate should remain the same.

Use a different worksheet for any project-based forecast and formal classification assessment. State whether a reported quantity concerns original or remaining petroleum, gas at standard conditions, or stock-tank liquid. This keeps a helpful educational calculation from acquiring an unsupported meaning as it moves into a slide deck or report. The linked calculators provide transparent physical arithmetic; their outputs need the surrounding case information to answer a project question.