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e12-14 Jeroen van der Molen et al. wells. The outcome of the DoubletCalc scenario is used to calculate the economics of the geothermal system, based on the ThermoGIS calculation method (Van Wees et al., 2012; TNO, 2018). Heat price is based on the gas price, being €0.014 kWh−1 and €0.016 kWh−1 respectively (Lensink & Van der Welle, 2018). Two economic scenarios using the Net Present Value are calculated: one with and one without the feed-in premium for renewable energy (SDEþ subsidy) from the Dutch government. The reference price of the subsidy is €0.053 kWh−1 (Lensink et al. 2018). The lifetime of the geothermal doublet is set to 30 years. The cost of drilling and completing ROD-102 is estimated to be €10 million (M) based on the method of Lukawski et al (2014), and assuming a dollar–euro conversion rate of 0.69 in 2009 and a well cost multiplier of 1.5. Numerous (confidential) onshore gas field developments are used to determine the CAPEX (Capital Expenditures) and OPEX (Operation Expenditures). CAPEX, including surface facilities and pipelines, are estimated at €15M. The total initial investment thereby becomes €25M. Annual OPEX is based on a variable gas OPEX of €0.033 Sm−1. Royalties are set at 12%, tax at 25% and depreciation is set at 10 years. The economics of the reference model and the synergy scenario with the most prolific well configuration are calculated and compared. Based on the outcome, it is determined how much of the additional profit can be used to fund the geothermal system to break-even level. Results Using the DoubletCalc software the most profitable geothermal well configuration is deduced, assuming the reference model: geo- thermal producer at 250 m, geothermal injector at 2000 m and a flow rate of 250 Sm3 h−1. To account for the decreasing reservoir pressure due to gas production, the average reservoir pressure (265 bar at the producer and 300 bar at the injector) is used in DoubletCalc. Production pump depth (ESP) is increased from 700 m to 1500 m and pump pressure difference increased to 163 bar. The resulting base case geothermal power is 20.99 megawatts (MW), with a COP of 11.3 (Figure 21). This result is used to calculate the NPV over time, which shows that after 30 years of production with a SDEþ subsidy the NPV is €26.8M, but having no subsidy results in a negative NPV of €−41.1M (Figure 22A). The total gas production of the base case is 4.68 BCM, with production from ROD-102 ending at the start of 1993. The result- ing NPV after 16 years of production is €257.5M (Figure 22B). Synergy, with the addition of a geothermal producer at 250 m, geothermal injector at 2000m and geothermal flow rate at 250 Sm3 h−1, extends gas production in ROD-102 by 3 years. Total gas production is increased to 5.55 BCM, improving the NPV of the gas field after more than 18.5 years of gas production to €319M. Discussion The potential synergy between gas- and geothermal exploitation has been tested using a reservoir model of the Roden gas field. The sen- sitivity analyses on geothermal well configuration show that every configuration leads to a higher total gas production due to delay in detrimental water breakthrough. The position of both the geo- thermal producer and -injector combined with the geothermal flow rate is key to maximise the effect of synergy between gas- and geothermal production. Placing the geothermal producer closer to the GWC and the gas producer increases total gas production in ROD-102. While geothermal production has limited pressure effects on gas production, there is a significant pressure effect from gas production on geothermal production. The pump pressure in the geothermal production well has to be adapted following the decreas- ing reservoir pressure during gas production and possible repress- urisation due to active aquifer effects after gas production has ceased. The required increase of pump pressure upon reservoir depletion leads to higher electricity usage and subsequently to a lower COP. In addition, more expensive pumps are required in sup- port of the increased capacity. However, the reduced reservoir pres- sure also has a positive effect on the geothermal injection, as a lower pump pressure is required for injection. With geothermal production close to the GWC, higher geother- mal flow rates will also result in co-production of (free) natural gas. Free natural gas has the potential to hinder the overall production in the ESP, as is also often an issue for oil production. In this study the ratio of co-produced free gas and the produced water in the geothermal production well does not exceed 2.5%, thereby keeping the effect of free gas on the overall production very limited. So far no geothermal systems in the Netherlands co-produce free gas, yet formation water often contains dissolved gas which turns into free gas once it comes to the surface (MEA, 2018). The current average ratio for Dutch geothermal systems producing from the ROSL is more or less 0.3 Sm3 natural gas per 1 Sm3 of water produced. It is very likely that produced formation water from the water leg also contains dissolved natural gas, especially when a transition zone is present. This aspect has not been taken into account in the simulations and economic calculations of this study. Overall, both free and dissolved natural gas could have an added benefit for the geothermal project, either through gas sales and/or by providing power to the ESP in the geothermal production well, resulting in a reduction of the electricity costs of the pump. The economics of conventional geothermal systems depend on an optimal distance between producer and injector. This is, among others, modelled in the DoubletCalc 1.4.3 software (Van Wees et al. 2012). On the one hand, a shorter distance increases the pressure gradient and thereby improves water production at the geothermal producer. On the other hand, a longer distance increases the life- time of a geothermal system as breakthrough of cooler injected water at the geothermal production well is postponed. In the synergy scenarios, a greater distance between the geothermal wells will increase gas production. This benefit strongly outweighs the benefits of choosing a shorter distance for higher pressure gradients and improved geothermal power. The sensitivity analyses with regard to increased gas flow rate, increased permeability, added permeability trends and limited- and strong aquifer support all show a positive effect on total gas production when a geothermal doublet is added. However, each setting shows different reactions to the geothermal exploitation on the gas production: Increasing the flow rate of ROD-102 shows somewhat similar behaviour to the reference model, with the exception of increasing the injector distance to the geothermal producer at 500 m. The increased drop in reservoir pressure nullifies the pressure effect from geothermal injection at a distance of 2500 m or more from the GWC. More important is the effect of the lower reservoir pres- sure on the economic performance of the geothermal doublet. In this case a higher pump pressure would be required, resulting in higher costs for the geothermal system. While the relative increase in gas production due to synergy is higher than in the reference model, the absolute total gas production is lower. It is therefore important not only to find the optimal geothermal well configuration, but also to consider a proper gas production rate in order to correctly balance the gas- and geothermal production. Downloaded from https://www.cambridge.org/core. IP address: 173.229.12.141, on 13 Jan 2021 at 23:29:16, subject to the Cambridge Core terms of use, available at https://www.cambridge.org/core/terms. https://doi.org/10.1017/njg.2019.11PDF Image | Dual hydrocarbon–geothermal energy exploitation
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