A techno-economic study of a pump storage hydropower system for ultra-deep level mines applied to Driefontein No. 9 Shaft
The energy required for mineral recovery is a major operational cost and strategic focus for the global mining sector. Power disruptions result in loss of production throughput and deceased profitability. Therefore, mines are required to review their power sources to ensure the sustainability and viability of their operations. In the South African region, the recent electricity tariff increases have had a major effect on energy-intensive users and subsequently significantly impacted investor decisions. The business case for alternative energy sources, which include renewable energy sources, has become far more compelling in the current economic climate. However, renewable energy is characterised by an intermittent supply, but with the selection of an appropriate storage mechanism, power variability can be mitigated and the system?s flexibility is enhanced. Only pumped storage hydropower is capable of meeting the anticipated technological and economic constraints with regard to storage capacity. High energy recovery has been recorded for energy recovery systems in deep level shafts. More than 50 turbines with a combined capacity of over 65 MW have been installed underground in various mines in South Africa. The use of current mine infrastructure of existing deep level mine shafts for underground pumped hydro-electric storage (UPHES) systems reduces the initial system capital cost and the depths of a potential network of tunnels provides potential hydraulic heads exceeding 1000 m. Driefontein No. 9 Shaft, a sub-shaft system consisting of a main shaft with shaft diameter 9.15 m and a shaft depth of 2 095 m, has been under care and maintenance for several years. The shaft is fully equipped with a dedicated production winder, dual-purpose production and men/material winder, shaft steelwork, electrical and communication cabling, various pipe columns and main haulages connecting the main shaft to the sub-vertical and ventilation shaft. A concept UPHES system model was produced in Excel and populated with the Driefontein No. 9 Shaft system parameters. The UPHES system configuration consists of a lower reservoir and pump station on 24 level, 2 095 m below datum (BD), a mid-shaft reservoir and pump chamber in mid-shaft - 1 050 m BD and a upper reservoir on intermediate pump chamber level, -150 m BD. The turbine chamber is also located on 24 level. Various assumptions are made, which include operational assumptions, such as when pumps are operational and when turbines are operational and system assumptions, which pertain to the general system components and their associated capacities. The UPHES system model was verified by using a simulation model developed in Engineering Equation Solver (EES). Unlike the Excel model, the EES simulation allows the pump and generating schedules to be varied for weekdays, Saturdays and Sundays. Therefore, the system was optimised using the EES simulation. The first priority for optimising the EES simulation model was to reduce the return on investment (ROI) as it is required that the asset investment is returned in the shortest time possible for the mine to benefit from the system?s energy saving potential. Therefore, in order to optimise the utilisation of existing infrastructure and lower capital costs, the costs dependent on the system output parameters were optimised along with the output parameters. The largest energy savings are achieved by maximising the number of hours of generating electricity during periods in which a peak tariff is charged and maximising the number of hours pumped only in periods in which off-peak tariffs are charged. This strategy maximises the number of hours during the day in which the maximum differential cost between tariffs is charged. Strategically scheduled pump and generating schedules are required to achieve the optimal system energy saving. An optimisation matrix was used to evaluate the pumping and generating schedules and the effect thereof on the number of pumps required per pump chamber, lower reservoir capacity, capital expenditure (CAPEX), electricity savings and ROI. It was determined that a break-even point exists at which the electricity cost savings are negatively affected by a decreased differential between the higher and lower tariff charged, because the cost of power consumed due to pumping cannot be recovered when energy is generated with the turbine. It was determined that if the percentage differential between peak and off-peak tariffs in the low demand season reaches 64% (off-peak tariff as a percentage of the peak tariff) or higher, the system no longer displays any electricity cost savings. Also, the percentage differential between the high demand season standard and peak tariff for the current 2016/2017 Megaflex tariff structure is 188% (standard tariff as a percentage of the off-peak tariff). The break-even point for the high demand season standard and peak tariff differential was calculated as 157% (standard tariff as a percentage of the offpeak tariff), therefore if the percentage differential reaches 157% or lower, the system no longer displays any electricity cost savings.
- Engineering