Limitations & Assumptions
The most significant limitation of the MB calculation is that there is no time factor included. That means that while a material balance calculation can tell us what happened, it can’t tell us when it happened. If we combine the material balance calculations with other methods it is possible to infer time information. The combination between the time information from well productivity equations and the pressure/production information from MBE can give time details.
Another inherent limitation is the averaging of reservoir properties. We are able to get an average distribution for different saturations, i.e. Sw, So and Sg from Sw + So + Sg = 1. But we aren’t able to determine the distribution of these saturations, are they spread more or less evenly across the reservoir? Are there areas of localized high concentration within the reservoir?
Fluid properties and pressures are averaged over the entirety of the reservoir for MBEs. The other aspect it cannot handle is the representation of variations in fluid or gas properties, i.e. change in compositions due to change in bubble point laterally or vertically.
The degree to which a MBE is invalidated is a function of the magnitude of such fluid property variations.
The MB has a series of assumptions that can cause errors in calculations.
The MB equation assumes that the reservoir has constant pressure throughout its volume. This has been demonstrated to not be the case, as is in the example of radial flow. The equation ignores pressure gradients throughout the reservoir by taking averages of fluid properties and pressures at a given time, and using these as indicative of real properties and pressures at that time.
Temperature is assumed to be constant at isothermal conditions. This is usually the case, however there are examples such as thermal recovery and large cold water injection procedures that will affect temperatures and introduce errors.
MBEs do not include permeability in the calculations and consequently there is no time component for production or rate sensitivity. Some conditions such as water drive, which are rate sensitive, require the addition of other equations to the MBE in order to better model reservoir properties.
Representative PVT Data
When performing PVT tests it is not possible to measure properties at exact reservoir conditions, as in the example of the differential test to reflect below bubble point conditions.
Good Production Data
It is necessary to have quality production data on gas, oil and water to be able to apply MBEs.
Significance & Use
Material balance equation is an approximate relation between four variables:
- Oil and Gas in place (N, m or G).
- Production (Np, Rp, Wp)
- Water Influx (We)
- Average reservoir pressure (PVT parameters pressure dependent, and in pore/water compressibility term)
The significance is that if three of these quantities are known, then we are able to calculate the fourth.
Once production and pressure information is available, can update the original estimate of STOIIP and N, which would have been previously estimated from petrophysical data. The MBE result is a more effective value.
MBE can determine support from an edge water drive system where other systems or observations may not be possible (think measuring the advancing OWC line).
- Water influx as a function of time can be determined if production and pressure are given as functions of time, and oil and gas in place are available from volumetric estimation. Its magnitude has a direct influence on secondary recovery procedures.
- Oil in place can be determined from production and pressure information if no natural water drive exists, i.e. We = 0. The volumetric estimate and further production from the reservoir however can be influenced by this.
- Pressure at a future date can be calculated by assuming a degree of water influx and if there is known oil in place. This calculation can help to decide if or when artificial lift facilities will be needed; and estimating the hydrocarbon reserves down to abandonment pressure, also a function of cumulative gas oil ratio Rp.