Reservoir Volume Estimator (OOIP)

Volumetric STOOIP · recovery factor · multi-zone · sensitivity

Units

Unit System In metric no conversion constant is needed — area × thickness already gives volume, and porosity and saturation are dimensionless.

Reservoir Zones (★ add layers)

Formation Volume Factor

Boi (rb/STB) ★

GOR (scf/STB) — rough estimate helper

Rough guide only: Boi ≈ 1.05 + 0.05 × (GOR/100). Real PVT lab data always takes priority.

Recovery Factor (optional)

Recovery Factor (%)

Drive Mechanism (reference) General context only — selecting one fills a mid-range value you can edit.

Sensitivity (optional)

Uncertainty ± (%) on area, porosity, Sw Gives a simple P90 / P50 / P10-style low-mid-high band. Not a Monte Carlo simulation.

Result

Enter area, net pay thickness, porosity, water saturation and Boi for each zone to calculate original oil in place, optionally with recoverable reserves from a recovery factor and a low/mid/high sensitivity range

The volumetric method gives oil originally in place, not what can be produced — only the recovery factor converts it to reserves, and that factor depends on drive mechanism, rock and fluid properties, well spacing and development strategy, so the reference ranges here are context rather than prediction. Net pay thickness should already exclude non-reservoir intervals, and average porosity and water saturation should be net-pay-weighted; using gross thickness or unweighted logs is a common source of large error. Boi must come from PVT analysis whenever available, since the GOR-based estimate here is only a placeholder. The sensitivity band simply flexes the most uncertain inputs together and is deliberately simpler than the probabilistic workflows used for booked reserves — formal reserves reporting follows PRMS/SEC guidelines with proper uncertainty analysis and qualified evaluator sign-off. Solution gas in place can be approximated as the solution GOR times the oil in place when a gas figure is needed for context.

Reservoir Volume Estimator (OOIP): Volumetric STOOIP, Recovery Factor and Sensitivity Range

The volumetric method for oil in place is one of the oldest and most trusted tools in petroleum engineering, but most calculators only handle it as a single number for one uniform reservoir, which isn’t how real reservoirs actually look. This OOIP calculator lets you add as many reservoir zones or layers as your field actually has, each with it’s own area, net pay thickness, porosity and water saturation and adds them together for a proper field total. It works in field units with the familiar 7758 constant or in metric where and this often surprises people, no constant is needed at all, since area in square metres times thickness in metres already gives you cubic metres directly. Beyond a bare in-place figure, it estimates what’s actually recoverable using a recovery factor, with typical ranges shown by drive mechanism for context and it gives you a simple low, mid, high range in the spirit of P90/P50/P10 reporting by flexing your most uncertain inputs together, without pretending to be a full Monte Carlo simulation. The oil formation volume factor stays fully editable throughout, real PVT lab data should always come first.

How to Use

Step 1: Pick your unit system

Select Unit System: Field (acres, feet, giving STB with the 7758 constant), or Metric (hectares, metres, giving m³ with no constant needed at all). A hint under this field explains exactly why metric skips the constant, area times thickness already is volume, and porosity and saturation are just plain fractions with no units of their own.

Step 2: Add your reservoir zones

Tap Add Zone for each layer or section of your reservoir. For every zone, enter it’s Area, Net Pay Thickness, Porosity, and Water Saturation.
Repeat for as many zones as your field actually has, they all get summed together into one field total at the end.

Step 3: Set your formation volume factor

Enter your Boi (rb/STB) directly if you already have this figure from PVT lab analysis, since real lab data is always better then any estimate.
If you don’t have a lab value yet, you can use the GOR helper, enter your GOR (scf/STB) and tap Estimate Boi for a rough placeholder figure, Boi ≈ 1.05 + 0.05 × (GOR/100). Treat this only as a stand-in until real PVT data comes in.

Step 4: Add a recovery factor, if you want recoverable reserves

Under Recovery Factor (optional), enter your Recovery Factor (%) directly if you know it.
Or pick a Drive Mechanism from the reference dropdown, Solution-gas drive, Water drive, Gas-cap drive or Gravity drainage, each fills a mid-range typical value you can then edit. These are general context only, not a prediction for your specific field.

Step 5: Add a sensitivity range, if you want one

Under Sensitivity (optional), enter your Uncertainty ± (%), applied to area, porosity, and water saturation together, to get a simple low/mid/high band in the style of P90/P50/P10 reporting. This isn’t a full probabilistic simulation, just a straightforward way to see how sensitive your answer is to it’s shakiest inputs.

Step 6: Calculate and read your result

Tap Calculate OOIP. The result shows original oil in place for your field total, a per-zone breakdown, recoverable reserves if you entered a recovery factor, and the low/mid/high sensitivity band if you set an uncertainty percentage.

Step 7: Export

Use Print / PDF for a clean printable copy or Copy to paste the numbers into your reservoir report.

Key Features

Multi-zone summation, add as many reservoir layers as your field needs, each with it’s own properties, combined into one field total
Field and metric units, with the metric mode explicitly explaining why no conversion constant is needed there
Editable Boi, with an optional rough GOR-based estimate as a placeholder only until real PVT lab data is available
Recovery factor reserves, converting in-place oil into recoverable reserves, with typical ranges by drive mechanism shown for context
Simple low/mid/high sensitivity band, flexing your most uncertain inputs, area, porosity, water saturation, in a P90/P50/P10 style without claiming to be a Monte Carlo simulation
Associated solution gas note, giving a rough gas-in-place figure alongside the oil figure when needed
Export as PDF or copy the result.

Formula / Logic Used

Volumetric OOIP, Field Units

$STOOIP = \frac{7758 \times A \times h \times \phi \times (1-S_w)}{B_{oi}}$

Where 7758 converts acre-feet directly into barrels.

Volumetric OOIP, Metric Units

$OOIP\ (m^3) = \frac{A\ (m^2) \times h\ (m) \times \phi \times (1-S_w)}{B_{oi}}$

No conversion constant is needed here, area in square metres times thickness in metres is already cubic metres and porosity and water saturation are dimensionless fractions either way.

Multi-Zone Total

$OOIP_{total} = \sum_{zones} OOIP_{zone}$

GOR-Based Rough Boi Estimate

$B_{oi} \approx 1.05 + 0.05 \times \frac{GOR}{100}$

Recoverable Reserves

$Recoverable = OOIP \times Recovery\ Factor$

Sensitivity Range

Area, porosity and water saturation are each flexed together, up for the high case, down for the low case, by your entered uncertainty percentage and OOIP is recalculated at each end to give a low/mid/high band, in the general spirit of P90/P50/P10 reporting.

low_case: area x (1-u), porosity x (1-u), (1-Sw) x (1-u) [approx]
high_case: area x (1+u), porosity x (1+u), (1-Sw) x (1+u) [approx]
where u is the entered uncertainty fraction

Who Should Use This Tool

Petroleum engineering students and junior reservoir engineers doing a preliminary, deterministic volumetric estimate for study or early-stage evaluation. This tool is explicitly a simplified estimator, formal reserves reporting for investment or regulatory purposes must follow PRMS/SEC guidelines with proper probabilistic uncertainty analysis and a qualified evaluator’s sign-off.

Frequently Asked Questions (FAQs)

1. How do you calculate original oil in place using the volumetric method?

Multiply reservoir area by net pay thickness to get bulk rock volume, multiply by porosity to get pore volume, multiply by one minus water saturation to get the oil-bearing share, then divide by the oil formation volume factor to convert reservoir volume into stock-tank barrels at surface. This tool applies this directly, with the 7758 constant in field units or no constant at all in metric.

2. Why doesn’t the metric version of this formula need the 7758 constant?

That constant exists purely to convert acre-feet into barrels, a field-unit quirk, in metric, area in square metres multiplied by thickness in metres is already a volume in cubic metres, with no unit conversion needed at all, since porosity and water saturation are just plain fractions either way.

3. What is the difference between oil in place and recoverable reserves?

Oil in place is the total oil sitting in the reservoir rock, while recoverable reserves is only the portion that can actually be produced, found by multiplying oil in place by a recovery factor that depends on drive mechanism, rock and fluid properties, well spacing and development strategy. This tool keeps these two figures clearly separate rather then blending them together.

4. Should I trust the GOR-based Boi estimate, or get a real lab value?

Always get a real PVT lab value whenever it’s available, the GOR-based formula in this tool is explicitly labelled a rough placeholder only, meant to give you a starting number before proper lab data comes in, not a substitute for it.

5. What does the low/mid/high sensitivity range actually tell me?

It shows how much your OOIP figure could shift if your most uncertain inputs, area, porosity, and water saturation, turn out to be somewhat different then your best estimate, in the general spirit of P90/P50/P10 reserve reporting. It’s a deliberately simple flex of these inputs together, not a full statistical Monte Carlo simulation, which is what formal reserves booking would actually require.

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