Dynamic Material Balance-Oil-or Gas-in-Place Without Shut-Ins

Abstract

Abstract Material balance calculations for determining oil- or gas-inplace require static reservoir pressures, which can only be obtained when the well is shut in. In a previous publication(1) titled "The ‘Flowing’ Gas Material Balance," it was shown that the reservoir pressure could be obtained from the flowing pressure for wells producing at a constant rate. The "Dynamic Material Balance" is an extension of the "Flowing Material Balance" and can be applied to either constant or variable flow rates. Both methods are applicable for 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; and,use this calculated average reservoir pressure and the corresponding cumulative production, to calculate the original oil- or gas-inplace by traditional methods. The method is illustrated using data sets. Introduction The material balance method is a fundamental calculation in reservoir 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, hydrocarbon phase changes, etc. In order to determine the average reservoir pressure, the well is shut in, resulting in loss of production. In high permeability reservoirs, his may not be a significant issue, but in medium to low permeability reservoirs, the shut-in duration may 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. If, indeed, the average reservoir pressure can be obtained from flowing conditions, then material balance calculations can be performed without having to shut in the well.