Material Balance calculations for determining oil- or gasin-place are based on obtaining static reservoir pressures as a function of cumulative production. This requires the wells to be shut-in, in order to determine the average reservoir pressure. In a previous publication(1), it was shown that the material balance calculation could be done without shutting-in the well. The method was called "Flowing Material Balance". While this method has proven to be very good, it is limited to a constant flow rate, and fails when the flow rate varies.

The "Dynamic Material Balance" is an extension of the Flowing Material Balance. It is applicable to either constantflow rate or variable flow rate, and can be used for both gas and oil. The "Dynamic Material Balance" is a procedure that converts the flowing pressure at any point in time to the average reservoir pressure that exists in the reservoir at that time. Once that is done, the classical material balance calculations become applicable, and a conventional material balance plot can be generated.

The procedure is graphical and very straightforward:

  • knowing the flow rate and flowing sandface pressure at any given point in time, convert the measured flowing pressure to the average pressure that exists in the reservoir at that time;

  • use this calculated average reservoir pressure and the corresponding cumulative production, to calculate the original oil- or gas-in-place by traditional methods. The method isillustrated using data sets.


The material balance method is a fundamental calculation inreservoir engineering, and is considered to yield one of the more reliable estimates of hydrocarbons-in place. In principle, it consists of producing a certain amount of fluids, measuring the average reservoir pressure before and after the production, and with knowledge of the PVT properties of the system, calculating a mass balance as follows:

Remaining Hydrocarbons-in-place = Initial Hydrocarbons-inplace- Produced Hydrocarbons At face value, the above equation is simple; however in practice, its implementation can be quite complex, as one must account for such variables as external fluid influx (water drive), compressibility of all the fluids and of the rock, hydrocarbonphase changes, etc.

In order to determine the average reservoir pressure, thewell is shut-in, resulting in loss of production. In high permeability reservoirs, this may not be a significant issue, but in medium to low permeability reservoirs, the shut-in durationmay have to last several weeks (and sometimes months) before a reliable reservoir pressure can be estimated. This loss of production opportunity as well as the cost of monitoring the shut-in pressure is often unacceptable.

It is clear that the production rate of a well is a function of many factors such as permeability, viscosity, thickness etc… Also, the rate is directly related to the driving force in the reservoir, i.e. the difference between the average reservoir pressure and the sandface flowing pressure. Therefore, it is reasonable to expect that knowledge about the reservoir pressure can be extracted from the sandface flowing pressure if both the flow rate and flowing pressure are measured.

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