In order to properly conduct material balance calculations, the wells must be producing from the same reservoir. Identification and grouping of wells in a common reservoir can be a challenging task.
Based on the flowing material balance (FMB), a methodology was developed that utilizes a well’s flow rate and flowing pressure history to identify which wells belong in the same reservoir, and which do not. This methodology, called the FMB model, continuously converts the flowing pressures and rates of each well into the average reservoir pressure. If these average reservoir pressure trends overlap, it indicates that the wells are in the same reservoir. If any of the trends are different, then those wells belong to different reservoirs.
The average reservoir pressure is determined in two ways. The first is from the productivity index (PI) and the flowing rates and pressures of that well. The second is from the material balance equation for the total production of the group of wells. These two average reservoir pressure trends will track over time if the well grouping is properly defined (i.e., all the wells in that grouping belong to the same reservoir), and if the correct hydrocarbon in place is used.
The FMB model can additionally be used to history match the flowing pressure of each well (using the flow rate as a control) or to match the flow rate of each well (using the flowing pressure as a control). These visual history matches increase our confidence in the interpretation of the FMB and can be used to investigate the sensitivity of magnitude of the hydrocarbons in place.
One field study consisting of three adjacent gas wells, coming on production at different times, and some of the wells not having a reliable initial pressure, illustrates clearly which wells are in the same reservoir and which ones are not, and yields the correct values of original gas in place.