Pressure at Depth in Oil Calculator

Inputs

Example Data Table

Assumptions: ρ = 850 kg/m³, g = 9.80665 m/s², surface pressure = 1 atm. Outputs shown in kPa.

Formula Used

Hydrostatic pressure in a static fluid column is: P(h) = P₀ + ρ g h

• P(h): pressure at depth h
• P₀: surface pressure (absolute or gauge)
• ρ: oil density (effective, possibly temperature-corrected)
• g: gravitational acceleration
• h: vertical depth (converted to meters internally)

If API gravity is selected, the tool uses SG = 141.5/(API+131.5) at 60°F and ρ = SG·ρ_water,60°F with ρ_water,60°F ≈ 999.016 kg/m³. Temperature correction (optional) uses ρ(T) = ρ(60°F) / (1 + β·(T − 60°F)).

How to Use This Calculator

1. Enter the depth and choose meters or feet.
2. Select a density method: direct density or API gravity.
3. If using API gravity, enter the API value at 60°F.
4. Optionally enable temperature correction and set β.
5. Provide surface pressure and choose gauge or absolute.
6. Set atmospheric pressure for gauge/absolute conversion.
7. Choose an output unit, then press “Compute Pressure”.

Why pressure-at-depth matters

Oil column pressure drives well control, pump sizing, and seal integrity. A 1,000 m column can add several megapascals, enough to change valve selection and safety margins. This calculator standardizes the workflow: enter depth, fluid properties, and surface conditions to produce gauge and absolute pressures for decisions.

Hydrostatic model used

The tool applies the hydrostatic relation P(h)=P0+ρgh for a static column. With g near 9.80665 m/s² and density between 800–950 kg/m³, gradients typically fall around 7.8–9.3 kPa/m. The model assumes a single effective density over the full depth and vertical depth approximates true pressure head.

Choosing oil density data

When laboratory or field measurements are available, direct density is the most transparent input. Common crude oil densities at 15–20°C range roughly 820–900 kg/m³, while heavier oils can exceed 930 kg/m³. Small density changes matter: a 20 kg/m³ increase raises gradient by about 0.196 kPa/m.

API gravity as an alternative input

If density is unknown, API gravity provides a practical estimate at 60°F. The calculator converts API to specific gravity using SG=141.5/(API+131.5), then multiplies by water density at 60°F (≈999.016 kg/m³). For example, API 35 yields SG≈0.849 and density ≈848 kg/m³ before any temperature correction.

Temperature correction and β

Density decreases as temperature rises, reducing hydrostatic head. With correction enabled, density is adjusted using ρ(T)=ρ(60°F)/(1+β·(T−60°F)), where β is a volumetric expansion coefficient (often 0.0006–0.0010 1/°C). A 30°C increase with β=0.0007 reduces density by roughly 2.1%.

Surface pressure, gauge vs absolute

Engineering calculations often mix gauge and absolute pressure. Gauge pressure is referenced to local atmosphere; absolute pressure is referenced to vacuum. This tool lets you enter surface pressure as either type and uses the atmospheric input to convert consistently. This is critical for comparing sensor readings, equipment ratings, and thermodynamic correlations.

Pressure gradient and quick sanity checks

The calculator reports gradient in Pa/m and psi/ft for fast checks. A typical oil with ρ≈850 kg/m³ produces about 8.34 kPa/m, which equals roughly 0.367 psi/ft. If your computed gradient is far outside 0.30–0.50 psi/ft, re-check units, density inputs, and depth conversion.

Using results in design and reporting

Use total absolute pressure for equipment exposed to sealed conditions and total gauge pressure for most field instrumentation comparisons. The CSV export supports engineering logs and spreadsheet QA, while the PDF report provides a shareable calculation record. For layered fluids or gas-cut oils, consider segmenting depths and summing multiple column contributions.

1) What is the main equation behind the calculator?

It uses P(h)=P0+ρgh, where P0 is surface pressure, ρ is effective oil density, g is gravity, and h is vertical depth. Outputs include hydrostatic, gauge, and absolute pressures.

2) Should I enter depth as measured depth or true vertical depth?

Use true vertical depth for hydrostatic head. Measured depth along a deviated well can overestimate vertical pressure. If only measured depth is available, convert to vertical depth using survey data for best accuracy.

3) How accurate is the API-based density estimate?

API gravity provides a useful approximation at 60°F, but real density varies with temperature and composition. For design-critical cases, use measured density or a PVT model and apply temperature and pressure dependence as needed.

4) What β value should I use for temperature correction?

Many oils fall around 0.0006–0.0010 1/°C. If you have lab data, use the reported volumetric expansion coefficient. When uncertain, start with 0.0007 1/°C and run sensitivity checks.

5) Why does the tool ask for atmospheric pressure?

Atmospheric pressure is required to convert between gauge and absolute pressures consistently. If your surface pressure is gauge, the tool adds atmospheric pressure internally to compute absolute pressure at depth.

6) What units can I use and what is the internal unit system?

You can input depth in meters or feet, density in kg/m³ or lb/ft³, and pressure in common engineering units. Internally the tool converts to SI (m, kg/m³, Pa) before converting outputs back.

7) When should I avoid a single-density hydrostatic model?

Avoid it when density changes significantly with depth due to temperature gradients, dissolved gas, water cut, or stratified fluids. In those cases, compute pressure in segments using different densities and add them.