To estimate the reservoir expansion projected onto the topographic surface, a geometrical concept was applied using Eq. (2). This expression calculates an equivalent heat area, i.e., the area needed to have equality between the cumulative heat production (\({Q}_{30}\)) and the stored heat in place (\({Q}_{0}\)). This area is presented as a circle, which in turn is the 2D surface projection of a 3D subsurface cylinder (Fig. 3). The circles traced per well show the resulting area calculated with Eq. (2) assuming a radial and steady flow (Fig. 6). Equation (2) describes the growing area as a function of extracted heat (\({Q}_{\mathrm{e}}\)). These circles will grow until production is stopped. Thus, the circle’s area might show the limit of the maximum level of extracted heat for the accumulated time of production.

When two cylinders’ outer boundaries meet, the heat production of the implicated wells could be affected. If two cylinders meet, their shapes merge, decreasing the heat flow rate in the overlapping zone to the wells. To compensate for this reduction in the flow, the other parts of both cylinders will have to grow faster.

The results of the model show that the wells H15, H30, and H31 might be good candidates to represent this effect. Figure 4a shows the feed zone of these three wells. Since it is at the same depth these wells could share the same aquifer. The deformation of the cylinder is a much more complicated case since the feed zones are not at the same depth nor the same thickness. The cylindric deformation could include a stretching or shortening of the feed zone. This effect is beyond the presented consideration.

As previously stated, recharge is not considered. However, when the recharge of fluid is included, this effect will be different. The encounter of cylinders might derivate into a decrease of the water level in the effective thickness, i.e., a drop of pressure. In response to this pressure drop, a higher rate of the aquifer fluid might enter into the cylinder. Thus, the deformation of the shape could be slower or it could go to one well. For example, if the pumping rate increases in well Hy (Fig. 7), this change on fluid demand could take fluid supply from the well Hx, diminishing the whole performance of Hx. In any case, this encounter effect results in an extra demand of fluid.

Here is another consideration. Although the injection wells do not seem to affect the temperature of fluid (Cendejas 1992; Iglesias et al. 2012), to satisfy this demand the cold front of injection could move faster towards these wells. If this new fluid is colder, then the temperature might be decreased affecting the performance of the implicated wells. Although no decrease in heat production has been recorded yet, it could happen within the next 30 years of production.

The CFE reports do not mention from which feed zone the fluid is coming into the well and there are no pressure measurements regarding the flow. Therefore, it was assumed that the geothermal brine is streaming into the well in all the feed zones. This model is extremely simple, but it might offer a very rough visualization of the possibility of wells interruption. Therefore, there is no evidence of this interruption measurable at the surface since the productivity of all the wells has not decreased. Thus, if there is any interruption in extraction between the wells, nothing at the surface could indicate the effectiveness of the recharge of hot fluids.

Finally, the porosity changes with depth have an implication on the results of Eq. (2). Taking the three most productive wells as an example, it can be seen that the area of each well increases up to 13% when the porosity is reduced by 80% of its measured value at lab conditions. The inverse of this relation is set by Eq. (2), where:

$$A \approx \frac{1}{\phi } .$$

### Technical potential extension

The size of the circles represents the used area, it also could be seen as the affected surface area of the system. The affected surface area is the portion of the reservoir that actually contains the hot fluid that was extracted by the wells. So, the area of Eq. (6) is the Los Humeros equivalent reserve extension [\(A\left({Q}_{0}\right)\)]. The difference between \(A({Q}_{0})\) and \(A({Q}_{30})\) is the potential area to be claimed with the installed equipment. In other words, it is the extension of the technical potential area of the Los Humeros.

The theoretical potential is 20 times bigger than the technical one. Bonté et al. (2020) consider a much larger reservoir thickness (ca. 5 km). In their work, each layer of rock has the same potential to be a reservoir of heat. In this study, it is not the case. It is just considered the effective thickness of the aquifer with less than 1 km (H12). In any case, this comparison just reflects the general idea about the technical potential of a geothermal resource, from which the entire potential cannot be extracted (Nathenson and Muffler 1975; Muffler and Cataldi 1978; Rybach 2015).