reservoir · material balance
Material Balance OOIP (Undersaturated Oil)
N = Np × Bo / [(Bo − Boi) + Boi × ct × (Pi − P)]
click formula to derive ↑
Inputs
STB
RB/STB
RB/STB
psi
psi
psi⁻¹
Description
Solves for OOIP from production history and PVT data using the single-phase (undersaturated, above bubble point) material balance equation. Provides a dynamic OOIP estimate independent of the volumetric approach, enabling a cross-check that reveals reservoir connectivity, compartmentalization, or water influx.
Variables
| Symbol | Unit | Description |
|---|---|---|
| N | STB | OOIP (from MB) |
| Np | STB | Total oil produced to date at stock-tank conditions, from production accounting. |
| Boi | RB/STB | Oil formation volume factor at initial reservoir pressure Pi — from a PVT report or the black_oil_pvt calculator at initial conditions. |
| Bo | RB/STB | Oil FVF at current (depleted) reservoir pressure P — from PVT or black_oil_pvt at current P. Bo < Boi for undersaturated oil (above Pb, oil contracts as pressure drops). |
| Pi | psi | Initial (discovery) reservoir pressure. |
| P | psi | Current average reservoir pressure, from a pressure buildup test or multi-well pressure survey. |
| ct | psi⁻¹ | Total system compressibility (rock + oil + connate water) in psi⁻¹, from the pore_volume_compressibility calculator or a standard field value. Typical undersaturated oil: 10–25 ×10⁻⁶ psi⁻¹. |
Assumptions
- The reservoir is above the bubble point throughout the production history being analyzed — once the reservoir drops below Pb, free gas forms and the single-phase denominator is no longer correct
- No significant water influx — water entry would require adding an aquifer influx term (We) to the numerator, making N and We jointly underdetermined from a single pressure point
- Reservoir is connected and pressure is approximately uniform — compartmentalized reservoirs will yield different N values from different parts of the field
Limitations
- A single-point calculation cannot distinguish between a small connected reservoir and a large but partially depleted compartment — use multiple (P, Np) historical pairs for a Havlena-Odeh straight-line analysis if more than one pressure datum is available
- ct must be accurate; it is often the least well-constrained input and is particularly uncertain in tight or highly fractured rocks
- Produced water and gas volumes are excluded from this simplified above-bubble-point form — if significant water or gas production exists, use the full general material balance equation instead
Use Cases
- → Dynamic OOIP cross-check: Compare the material balance OOIP against the volumetric OOIP (ooip calculator) — agreement within 15–20% suggests consistent reservoir description; large discrepancy signals compartmentalization or water influx.
- → Reservoir connectivity assessment: Apply the MB separately to different fault blocks or well groups; consistent N across blocks suggests communication, while inconsistent N values reveal compartmentalization.
- → Early field management: Track how the MB-derived N evolves as production history accumulates — convergence toward a stable N value as ΔP grows gives increasing confidence in the OOIP estimate.
Related Calculations
Region Notes
Permian Basin
Wolfcamp tight-oil above the bubble point: ct typically 15–25 ×10⁻⁶ psi⁻¹; compressibility-drive term often dominates early because ΔBo is small for tight-oil PVT at moderate pressure drops. Multi-well pressure surveys are needed to get a reliable average P for the material balance.
Gulf of Mexico
High-quality GOM sandstones often show rapid pressure depletion (large ΔP) even with moderate production — strong compressibility drive initially, transitioning to solution-gas drive once Pb is crossed. MB OOIP often confirms or refines volumetric estimates within 10–20%.
North Sea
Brent Group chalk and sandstone reservoirs in undersaturated condition: consistent PVT data are usually available from early appraisal, enabling reliable MB analysis. Water influx from active aquifers can mask the correct N — check for non-linearity in P/Np trend.
Global
Always plot Np × Bo vs. cumulative expansion (denominator) to check for linearity — a curved trend is the classic indicator that the single-phase, no-water-influx assumptions are being violated.
References
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