neqsim-reservoir-material-balance

Reservoir Material-Balance Analysis

Use pressure and cumulative production to test an in-place-volume hypothesis. This is a tank-level screening method, not a spatial reservoir simulator or a reserves classification.

When to Use

• Estimate or reconcile gas initially in place (GIIP), original oil in place (OOIP), or total surface-component inventories from pressure and production history.
• Compare a prior volumetric estimate with a pressure-production material balance.
• Test depletion-drive, gas-cap, known-water-influx, or known-compressibility cases.
• Separate formations or pressure compartments before matching a field total.

For compositional gas-condensate depletion, produced composition, or wellstream forecasts, use neqsim-reservoir-history-match-forecast. Use both workflows only when their fluid and volume bases are explicitly reconciled.

Inputs

• Dated static/average reservoir pressures, including test type, depth, unit, datum, source and correction provenance.
• Formation-allocated cumulative production and injection for oil, gas and water on one declared surface-volume basis.
• Initial and pressure-dependent PVT, initial pressure and temperature, and relevant rock/fluid compressibilities.
• Supported formation/tank boundaries, pressure communication evidence, and gas-cap/aquifer inputs where applicable.
• Prior in-place estimates and their date, range, volumetric/PVT basis and allocation assumptions.

Outputs

• In-place volumes and units by tank and supported model case.
• Pressure/volume residuals, fit diagnostics and identifiability warnings.
• Cumulative production, injection, aquifer influx and drive contributions on a consistent basis.
• Sensitivity range, comparison with the prior estimate, data gaps and discriminating next evidence.

Required Evidence

Before fitting, assemble one time-aligned history per candidate tank:

• Static or otherwise justified average reservoir pressure with date, wellbore, test type, gauge depth, pressure unit, datum, source, quality and correction method.
• Cumulative oil, gas and water produced and injected, on one declared surface-volume basis. Keep the formation allocation and its uncertainty; a field total is not automatically a formation history.
• PVT at initial conditions and at each pressure observation: pressure, Bo, Bg, Bw, Rs and Rv as applicable, with units, standard conditions and separator basis.
• Initial pressure, temperature, formation/water compressibility and saturation assumptions.
• Formation and pressure-compartment mapping, well completion intervals, shut-in/stabilization status, and evidence for or against pressure communication.
• The previous in-place estimate, estimate date, range, and the pore-volume, saturation, PVT and allocation basis used to calculate it.