Reservoir input panel
Use the three-column grid on large screens, two columns on tablets, and one column on mobiles.
Example data table
| Case | Fluid | Area | Thickness | NTG | Porosity | Swi | FVF | Recovery |
|---|---|---|---|---|---|---|---|---|
| Base oil case | Oil | 640 acres | 85 ft | 0.82 | 18% | 24% | 1.28 | 32% |
| Gas upside | Gas | 2.5 sq km | 32 m | 0.75 | 14% | 28% | 0.0052 | 74% |
| Integrated review | Both | 1,050 acres | 110 ft | 0.69 | 16% | 26% | 1.18 | 38% |
Formula used
Volume building blocks
- Net pay = Gross thickness × Net-to-gross
- Bulk rock volume = Area × Net pay
- Pore volume = Bulk rock volume × Porosity
- Hydrocarbon pore volume = Pore volume × (1 − Swi)
Reserve equations
- STOIIP = 7758 × HCPV ÷ Boi
- GIIP = 43560 × HCPV ÷ Bg
- Recoverable reserves = In-place volume × Recovery factor
- Marketable reserves = Recoverable reserves × (1 − Abandonment factor)
The oil constant 7758 converts acre-feet to stock tank barrels. The gas constant 43560 converts acre-feet to standard cubic feet when Bg is entered in reservoir cubic feet per standard cubic foot.
How to use this calculator
- Enter the project name and choose oil, gas, or both.
- Provide mapped area and gross thickness, then select their units.
- Enter net-to-gross, porosity, and initial water saturation values.
- Supply the correct formation volume factor for your chosen fluid.
- Add recovery and abandonment factors to estimate commercial outcomes.
- Press Calculate reserves to place results above the form.
- Use the export buttons in the result panel for CSV or PDF output.
Why volumetric estimates matter
Volumetric reserves estimation is often the first engineering screen for a discovery, prospect, or redevelopment interval. It turns mapped geometry and petrophysical assumptions into an in-place hydrocarbon number planners benchmark quickly. Because the method is transparent, inputs can be challenged by geology, petrophysics, drilling, and facilities teams before capital is committed. That visibility makes volumetrics useful during field ranking, farm-in reviews, and portfolio comparison.
Area and thickness drive scale
Mapped closure area and gross reservoir thickness establish physical size. When both values increase, bulk rock volume rises proportionally, so contour changes can materially shift reserves. A ten percent area uplift and a ten percent thickness uplift together produce about a twenty-one percent bulk volume increase. This is why contour certainty, depth conversion, and spill-point control deserve review in every case.
Net rock controls effective pay
Gross thickness does not equal productive thickness. Net-to-gross applies cutoffs for shale content, porosity, and permeability to isolate rock that can realistically store hydrocarbons. In thinly laminated reservoirs, small cutoff adjustments can sharply alter net pay. Teams should document cutoffs, core calibration, and any averaging method used across the mapped interval before publishing a reserve range.
Porosity and saturation shape pore inventory
Porosity converts rock volume into pore space, while initial water saturation determines what share of that pore system is occupied by hydrocarbons. A reservoir with higher porosity but higher water saturation may underperform a tighter interval with cleaner hydrocarbon fill. Sensitivity testing both parameters is essential. Workflows run low, base, and high cases so decision makers can see how uncertainty changes volume.
Formation volume factor links reservoir and surface
Formation volume factor bridges reservoir and surface conditions. Oil uses Boi, while gas uses Bg, so choosing the correct fluid property is critical for converting hydrocarbon pore volume into stock-tank barrels or standard cubic feet. Because pressure, temperature, and composition influence these factors, engineers should align the selected value with PVT data, representative pressure depth, and the phase assumed in the study.
Recovery factor converts geology into planning volumes
In-place volumes are not sales volumes. Recovery factor recognizes displacement efficiency, pressure support, mobility contrast, well spacing, and operational constraints. Abandonment factor then removes volumes likely left behind at economic limit. Together they convert geology into commercially relevant numbers. Strong reserve practice pairs volumetric estimates with scenario charts, analog fields, and updates so the model evolves as appraisal wells, tests, and dynamic data reduce uncertainty.
Frequently asked questions
Does this calculator replace reserves certification?
No. It is a screening and planning tool. Certified reserves require audited data, consistent classifications, economic assumptions, and formal review under the reporting framework your organization follows.
Which area unit should I choose?
Use the unit that matches your mapped interpretation. The calculator converts acres, hectares, square kilometers, and square miles into a common acre-based workflow before computing volumes.
How should I enter formation volume factor?
Enter the fluid-specific factor that matches reservoir conditions and the reserve equation you intend to use. Oil cases use Boi. Gas cases use Bg with consistent unit definitions.
Why can marketable reserves be much lower than in-place volume?
In-place volume ignores sweep limits, pressure decline, well spacing, and economic abandonment. Recovery factor and abandonment factor reduce geological volume to a commercially realistic outcome.
Can I evaluate uncertainty with this page?
Yes. Run multiple low, base, and high cases by changing area, net-to-gross, porosity, saturation, and recovery inputs. Compare exported outputs and the Plotly chart for quick sensitivity insight.
What input errors matter most?
Unit mismatches, unrealistic recovery assumptions, and poorly justified water saturation values usually have the largest impact. Confirm cutoffs, mapping limits, and PVT consistency before sharing results.