HT-ATES systems work as a pair of wells, known as a doublet. When excess renewable heat is available, groundwater is extracted from one well, warmed at the surface through a heat exchanger, and injected into the second well, the so-called hot well. During the heating season the direction reverses, and the stored warm water is pumped back up. Ideally, the hot water spreads as an even bubble through the aquifer, and most of it returns through the well screen when it is needed. In practice, however, heat is lost at the thermal front and at the confining layers above and below the aquifer, and buoyancy adds a further complication that has long been recognized: hot, lighter water tends to rise and tilt the thermal front upward during storage.

The new research, led by Stijn Beernink of KWR Water Research Institute and Delft University of Technology together with colleagues, goes a step further. The team realized that density differences do not only drive buoyant flow in the aquifer — they also alter the pressure distribution inside the well itself. When a column of 90-degree water stands next to a column of cool groundwater at roughly 12 degrees, the lighter column gains hydrostatic pressure more slowly with depth. That means the pressure difference between the well and the surrounding aquifer shrinks as you descend, and can even vanish at a certain depth, below which essentially no injection occurs at all.

To quantify the effect, the researchers built axisymmetric numerical simulations using the SEAWATv4 code, which couples groundwater flow with variable density and viscosity, and represented the well as a column of extremely high hydraulic conductivity so that water could distribute itself freely along the screen. They tested injection temperatures of 15, 30, 60 and 90 degrees Celsius in a 40-meter-thick aquifer, running a realistic seasonal cycle of 90 days of injection, storage, extraction and idle time with an annual storage volume of 100,000 cubic meters per well. They also developed analytical equations that describe the same physics, allowing the maximum depth of injection and the peak flow at the top of the screen to be predicted from simple operational parameters.

The results are striking. As injection temperature rises, the flow distribution becomes increasingly lopsided, with the highest inflow concentrated at the top of the well screen — in some scenarios reaching several times the average flow rate, and with essentially no water entering the deepest part of the screen at 90 degrees under low-pressure conditions. The degree of nonuniformity depends on the ratio of pumping rate to aquifer permeability, which controls the injection pressure head. When that ratio is small, the pressure available to push water into the aquifer is modest, the buoyancy term dominates, and hot water infiltrates only through the upper portion of the screen, sometimes just the top 40 to 50 percent.

Viscosity makes matters worse in a self-reinforcing way. Water at 90 degrees is nearly 75 percent less viscous than water at 12 degrees, so the first hot water to enter the top of the aquifer creates a zone of low hydraulic resistance precisely where flow is already strongest. More water rushes through that zone, which heats it further and thins the water even more. In the simulations including both variable density and viscosity, flows at the top of the screen reached up to 3.7 times the average rate. The lowered viscosity also reduces the pressure head needed to inject a given volume, which paradoxically deepens the nonuniformity because less pressure is available to overcome the buoyancy gradient along the screen.

Crucially, the researchers found that the flow distribution is fundamentally asymmetrical between injection and extraction. During injection, buoyancy can choke off flow entirely below the maximum depth of injection. During extraction, however, the pressure difference between the light water column in the well and the denser ambient groundwater grows with depth and can never reach zero, so water is always drawn in across the full length of the screen. The practical consequence is sobering: a well that only injected through its upper half must, during recovery, pull cold ambient groundwater from the bottom half, diluting the extracted heat and directly reducing the thermal recovery efficiency of the system.

The nonuniformity also carries a mechanical warning. Maximum flow velocity at the borehole wall is a critical design parameter for preventing clogging of the screen and gravel pack, and the study shows that assuming uniform flow can underestimate this velocity by a factor of up to 3.7. A well designed on the assumption of even flow distribution might therefore be far more vulnerable to clogging in practice than its designers believed. The team’s screening of published HT-ATES storage conditions, spanning eight earlier studies, indicates that the levels of nonuniformity they quantified overlap substantially with real-world operating conditions, making this a genuinely practical concern rather than a numerical curiosity.

There are also direct implications for how HT-ATES systems are modeled and designed. Many previous simulation studies forced a uniform flow distribution across the well screen as a simplifying assumption. The new work shows this assumption introduces errors of up to about 7 percent in predicted recovery efficiency, in either direction depending on the aquifer’s vertical permeability, and larger errors can be expected in strongly heterogeneous aquifers. Allowing flow to distribute freely, the authors argue, is the safer approach. Where conditions are unfavorable, design remedies exist: operating wells closer to their maximum flow rate, using larger-diameter wells, or deploying multiple partially penetrating screens to spread injection and extraction more evenly across the aquifer.

The findings extend beyond geothermal storage. Similar density-driven nonuniform flow arises in carbon dioxide injection and in aquifer storage and recovery of freshwater in brackish aquifers, where comparable density contrasts of 5 to 25 kilograms per cubic meter occur. The analytical tools developed here — the maximum depth of injection and the maximum normalized flow — could help engineers in those fields as well. As heat networks across Europe and beyond look to the subsurface for seasonal storage at temperatures up to and beyond 90 degrees, this study makes clear that gravity itself must be treated as a design constraint: ignore buoyancy at the well screen, and a significant share of the stored warmth may never come back.

Subject of Research: Buoyancy-induced nonuniform groundwater flow through well screens in high-temperature aquifer thermal energy storage

Article Title: How density and viscosity differences cause nonuniform flow distribution across well screens and impact heat recovery of HT-ATES systems

Article References: Beernink, S., Hartog, N., Vardon, P. J., & Bloemendal, M. (2026). How density and viscosity differences cause nonuniform flow distribution across well screens and impact heat recovery of HT-ATES systems. Hydrogeology Journal. https://doi.org/10.1007/s10040-026-03154-8

Image Credits: AI Generated

DOI: 10.1007/s10040-026-03154-8

Keywords: HT-ATES, aquifer thermal energy storage, well screen, buoyancy flow, groundwater density, viscosity, heat recovery, well hydraulics, thermal energy storage, geothermal energy, SEAWAT, clogging