Original Oil In Place Calculator

Example Data Table

These rows illustrate how porosity, thickness, and Boi shift volumetric oil estimates.

Plot

Formula Used

Stock Tank Original Oil In Place:

OOIP = 7758 x A x h x NTG x phi x (1 - Swi) / Boi

• 7758 converts acre-feet to reservoir barrels.
• A is reservoir area in acres.
• h is net pay thickness in feet.
• NTG is net-to-gross ratio.
• phi is effective porosity as a fraction.
• Swi is initial water saturation as a fraction.
• Boi is initial oil formation volume factor in reservoir barrels per stock tank barrel.

How to Use This Calculator

1. Enter mapped reservoir area and select acres or hectares.
2. Enter net pay thickness and choose feet or meters.
3. Provide effective porosity and initial water saturation in percent or fraction form.
4. Enter Boi from PVT data, then add NTG, recovery factor, and oil price if needed.
5. Press Submit to display OOIP above the form and review supporting metrics and chart.
6. Use the CSV or PDF buttons to export the calculated result set.

Reservoir Volume Controls

Original oil in place starts with geometry. Area and net pay create bulk rock volume, and net-to-gross removes non-productive intervals. A reservoir covering 640 acres with 50 feet of pay contains 32,000 acre-feet before screening. Applying 0.90 net-to-gross reduces rock volume to 28,800 acre-feet, showing why mapping accuracy and pay definition directly control later volumetric result estimates.

Porosity Impact on Storage

Porosity determines fluid storage capacity within the rock. At 18% porosity, 28,800 acre-feet of screened rock holds 5,184 acre-feet of pore volume. Raising porosity to 22% increases pore volume to 6,336 acre-feet, an uplift. Reliable core data, log normalization, and facies modeling are therefore essential because modest porosity shifts can change field ranking and reserve confidence for teams.

Water Saturation and Hydrocarbon Space

Initial water saturation removes pore volume filled with water. If water saturation is 25%, then 75% of pore space is available for hydrocarbons. On 5,184 acre-feet of pore volume, hydrocarbon pore volume becomes 3,888 acre-feet. If saturation increases to 35%, hydrocarbon pore volume drops sharply, which can materially reduce in-place oil before fluid-property conversion is applied.

Formation Volume Factor Conversion

The standard volumetric constant of 7,758 converts acre-feet to reservoir barrels. Multiplying 3,888 acre-feet by 7,758 gives 30,161,304 reservoir barrels. Dividing by a Boi of 1.25 yields about 24.13 million barrels. A lower Boi increases reported oil, so dependable PVT analysis is necessary whenever volumetric decisions influence development planning or asset valuation.

Recovery and Revenue Perspective

OOIP measures oil in place, not oil guaranteed for recovery. Applying a 30% recovery factor to 24.13 million stock tank barrels produces about 7.24 million recoverable barrels. At 75 dollars per barrel, indicative gross revenue exceeds 543 million dollars before costs and fiscal terms. This comparison helps engineers connect reservoir size with development attractiveness and commercial screening.

Using the Calculator for Decisions

Best results come from consistent inputs. Area should reflect mapped closure, net pay should follow cutoffs, porosity should be effective, and saturation should match the petrophysical model. Users should test low, base, and high cases rather than a single estimate. Sensitivity checks on porosity, saturation, and Boi quickly reveal the main uncertainty driver.

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