Currently, a large part of the energy used to provide heat to heating network comes from gas boilers, a combustion process where 2.2kg of CO2 is emitted for every m^3 of gas. Deep geothermal energy is implemented more in The Netherlands over the last couple of years as a substitute to the conventional boilers and this is a technique that is proven to be working. However, one problem with geothermal energy is the fact that only base load extraction is possible, whereas the heating demand varies throughout the year. During winter there is an energy shortage while during summer there is a surplus. Hence, seasonal heat storage is seen as a promising technique to increase the portion of green energy in heating networks.

High-Temperature Aquifer Thermal Energy Storage (HT-ATES) can bridge the gap between the supply and demand, storing excess produced heat during summer and supplying during the winter months. This research focuses on both the technical aspects as well as the business case of the implementation of such a system in a heating network. Technical simulations are performed where the fluid transport and heat loss processes are modelled. The output of these simulations is used to compare the business cases of a heating network with and without HT-ATES implementation, based on the Levelized Cost Of Heat (LCOH) and total annual CO2 emissions in an economics tool developed in Python. All simulations are based on the situation at the TU Delft Campus, where plans are made for a HT-ATES in the Maassluis formation.

The base case shows a thermal recovery efficiency of 0.75 in cycle four. The LCOH for a project with a lifetime of 30 years is 52 €/MWh (14 €/GJ) when HT-ATES is implemented, compared to 61 €/MWh (17 €/GJ) in the case where only geothermal energy and gas boilers are used to supply the heat. Total CO2 emission reductions are 31%. Based on these values, one can conclude that the situation where HT-ATES is included is the economic scenario.

On top of the case study, a parameter sensitivity study is performed. The results show that storage volume, storage reservoir permeability and temperature differences between the wells are the key geological and operational parameters when assessing the project feasibility. Economic parameters such as the discount rate and gas prices also have a considerable impact on the economic results. The results of the sensitivity analysis shows that the project in Delft is feasible as long as the future average gas price remains above 21 €/MWh and the discount rate does not exceed 18.3%, while keeping the other variables constant.

The main objective of this study is to quantify interference effects between production and injection wells for geothermal projects that operate within the same reservoir. The secondary objective is to study the time it takes for the reservoir unit to thermally recharge after production has stopped. Two reservoir simulators are benchmarked to decide which one to use for reaching these objectives. The Ammerlaan, Duijvestijn and DAP doublets, all targeting the the Delft Sandstone Member in the West Netherlands Basin, serve as a case study. A literature review is presented to gain a better understanding of the geological history and the structural setting. A box-model of the study area is created and used to benchmark the two reservoir simulators. A static reservoir model is developed in Petrel through seismic interpretation, structural modelling, facies modelling and petrophysical modelling. Populating this static model with dynamic properties allows us to perform reservoir simulations in Eclipse100 and study the propagation of pressure and temperature. A discrete parameter analysis aims to capture the uncertainties that are associated with reservoir modelling and simulation. In this study, data is used from seismic surveys, wireline logs, core studies, a cuttings study and the monthly production volumes of the Ammerlaan and Duijvestijn doublets. It is shown that interference on temperature has a long term (20-30 years) effect on the Duijvestijn (positively) and the Ammerlaan and DAP doublets (negatively). The combined total energy production of the three doublets over 100 years is small with a decrease of 3% due to temperature interference, compared to when running the doublets in stand-alone configuration. Interference on pressure has a short term (days) effect on the achieved flow rate when the injection well cannot reach its target injection rate and is constraint on the maximum allowable pressure at which it is allowed to inject. This occurs under the low permeability scenarios and can be observed when the pressure wave arrives at the neighbouring injector. The Duijvestijn, Ammerlaan and DAP doublets all benefit from this through a combined increase in energy production of 8% over 100 years of production, averaged over all scenarios. During thermal recharge after production, the average reservoir temperature increases asymptotically. Temperature recharges to 96.1% to 97.4% of the initial reservoir temperature after 1000 years of recharging under different thickness and conductivity scenarios. The absence of a thermal influx at the bottom of the reservoir model is limiting the capacity of the reservoir to recharge to its initial average temperature. Interviews are conducted to investigate the implications that the findings of this research have on the policy measures for geothermal projects. Suggestions for changes in policy are made to optimize the recovery of heat in the subsurface.

In the context of the energy transition, rapid development of the geothermal sector in the Netherlands has to take place. The first steps have been taken by establishing the Green Deal UDG between multiple industrial consortia, which agree to share knowledge on the research and use of ultra-deep geothermal energy . The Dinantian carbonates are of interest for the deep geothermal wells, because of their high geothermal potential. This research project provides a case study of the Californië geothermal doublets in Limburg (NL), which are currently the only geothermal wells in the Netherlands producing from the Dinantian carbonates. However, the static and dynamic model prove that the Devonian Bosscheveld formation and Condroz group are also part of the reservoir formation. Due to the tight matrix of the reservoir rocks, the permeability is believed to be fracture and karst (meteoric and hydrothermal) driven. The goal of this Thesis is to create a static and dynamic model of the reservoir that confirms the current production data (history match) and that explores the development of the geothermal potential of the reservoir in space and time. The static and dynamic reservoir model are based on a limited amount of well and seismic data, which forms the main challenge in this project. A framework of assumptions has been created to construct the model and a scenario- based approach has been applied to construct a best case scenario that matches the production data. A key element in the static reservoir model is the Tegelen fault. To estimate the impact of the Tegelen fault on the permeability distribution in the reservoir, a fieldwork in an analogue carbonate quarry has been executed. The results are applied in the static model. The dynamic results in this study show that the permeability configuration applied in the best case scenario results in BHP, flow rate and temperature values that are of the correct order of magnitude and within an acceptable error margin of the production data. Multiple sensitivities have been simulated to determine the range of parameters that may cause an inaccuracy in the results. Additional data acquisition is necessary to validate and optimize the static model, which will result in a dynamic model with an improved history match and a larger predictive power for future production and reservoir management.

Sequestration of carbon dioxide (CO₂) in depleted gas reservoirs is an attractive choice, especially in The Netherlands, to reduce CO₂ emissions into the atmosphere. Injection of CO₂ in the subsurface geological formations can distort local thermal, chemical and geomechanical equilibria. As such, it results in highly coupled (thermo)physical effects in the near wellbore region, referred to as “near wellbore effects”. In this work, qualitative and quantitative descriptions of the near wellbore effects in depleted gas fields on macroscopic scale are provided. The primary focus is on the thermal effects (i.e., Joule-Thomson effect, water vaporization and CO₂ dissolution) and specific chemical effects (i.e., salt precipitation and hydrate formation). Occurrence and the corresponding magnitude of certain near wellbore effects influence the injectivity of CO₂ both positively and negatively. In several occasions these effects can lead to severe reduction of the injectivity. To accurately model these effects, thermal multi-component multi-phase simulations are conducted using both TOUGH2-ECO2MG and CMG-GEM commercial-grade simulators. Important is that these simulations include precipitation of salt and phase changes of CO₂ during repressurization of the reservoir. Extensive sensitivity study on numerous 1D, 2D and 3D reservoirs with various injection parameters and degrees of heterogeneity is carried out. A comprehensive 3D geological model of the nearly depleted P18-4 gas field (located in the Dutch North sea) is also investigated, in order to examine the near wellbore effects in a real-field application. Moreover, the potential control of the near wellbore thermal effects by interplay of controllable operational parameters (e.g. rate, temperature or composition) and the local reservoir pressure and temperature conditions is presented. Results reveal that the high injection rates targeted for real CO₂ injection (i.e., 1.1 Mt/yr) in combination with low initial reservoir pressures (> 40 bar) and a large reservoir volume provide favorable conditions for development of predominantly excessive cooling effects (15 ^oC) near the wellbore. Injection of CO₂ in gaseous conditions at low temperatures can cause such strong cooling that hydrate can form, which can potentially jeopardize the injection process due to clogging of the reservoir. However, as for its specific geometry and well location, the thermal effects are significantly less pronounced in the P18-4 field model. Besides, heterogeneity of the formations plays a key role in the distribution of the appearing effects along the wellbore. Overall, for the considered cases, the injectivity is found to be enhanced rather than decreased by the studied near wellbore effects, with the proviso that the conditions in the near wellbore region remain outside the hydrate formation window.