Evaluation Of The Geothermal Energy Potential Of The Olkaria Field Kenya, Based On Geochemical Data - A Numerical Model

Abstract

The Olkaria geothermal field is located in the Kenyan Rift valley, about 120 km from Nairobi. It is surrounded by further geothermal prospects, such as Suswa, Longonot and Eburru. Exploration of the Olkaria geothermal resource started in 1956. Upon realization of resource potential deep drilling commenced in 1973. A feasibility study in 1976 indicated that development of the geothermal resource was feasible and consequently the construction of a three unit power plant of 15 Mwe each at Olkaria 1 build in 1981, 1982 and 1985 respectively (Ouma, 2010). Subsequent years saw numerous expansions with additional power plants being installed in Olkaria. These include a binary plant at Olkaria South West (Olkaria III) in 2000, with a capacity of 110 Megawatts (MW), a condensing plant at Olkaria North East (Olkaria II) in 2003, with a capacity of 105 MW and another binary plant at Olkaria North West (Oserian) in 2004, with a capacity of 2 MW. In the year 2014 additional 280 Mw was commissioned from the Olkaria East and the Olkaria-Domes fields. Evaluation of the reservoir response to exploitation has always focused on the measured pressure, temperature, total flow from wells and enthalpy. Though geochemical data is also of essence, the data had remained scattered i.e. reporting done on individual wells other than on the field integrating all the wells. This research therefore aimed at numerically modeling the geochemical data of the Olkaria area in order to determine its potential with major focus in the changes in concentration of chemical species of Cl, B, Li, gas and solute geothermometers amid drilling of additional wells which are deeper, reinjection and performance of the existing wells in the Olkaria East and the Olkaria-Domes fields. The Cl, B and Li are used as natural tracers to indicate the source of the fluids whereas the gas and solute geothermometers were used to show the geo-conditions of the reservoir. The research was a computer-based numerical model which would ultimately be used to predict the reservoir response to different exploitation scenarios. It considered sampling of all the wells in the fields of interest that is 52 wells; 16 in the Olkaria domes and 36 in the EPF that gave a total of 152 samples. The new data was used to verify the methods of sampling and analysis of v the data contained in the database. The representative fluid (both brine and steam) samples from the wells were collected from the weir box and webre separator respectively. The result of the model estimates reservoir temperatures at about 300oC. Deep wells like OW-5 has highest temperatures of about 320oC due to the deepening effect whereas shallow wells like OW-22 had the lowest temperatures of less than 240oC. OW-5 has the high values of chloride and silica concentrations of 950 ppm and 700 ppm respectively and thus thought to be tapping from deep, high temperature and pressure reservoirs. On production capacities, the result of this study reveals that the potential of the fields is depended on the reinjection strategy to be implemented. Without reinjection, for example, OW-5 will sustain production to 2028, 2025 for OW-19, OW-16 till 2022 and lastly OW-22 in 2019. Minimal reinjection translates to low pressure support for the field leading to the well on the periphery of the field receiving higher amounts of cooler fluids rendering them unproductive. With regard to well depths, deep drilled wells have the ability to sustain a given production regime for a longer period compared to shallow wells. This arises from the fact that deep wells tap from high temperature and pressure reservoirs of about 300°C and 200 bars which are suitable for geothermal resources. The silica scaling evaluation indicates that the wells have varying minimum separation temperatures. Deeper wells have the highest potential for scaling compared to the shallow ones as they have tapped from high temperature and silica content reservoirs. The gas species are not in equilibrium with the mineral assemblages due to processes of boiling, condensation, and mixing. The East production field had the smallest gas concentrations estimated to be about at 52 bars arising from degassing and near surface boiling The study recommends independent studies firstly, on the cause of measured high N2 gas of about 80mmol/kg in the central part of the EPF especially in well OW-5 which is also a deeper well. Secondly, a study be done to evaluate the effects of the accelerated drilling on the physical and chemical characteristics of the wells. Finally, tracer dilution studies to determine the connectivity of the reinjection wells. This will be to ensure targeted reinjection that minimizes early breakthrough in to the producing reservoirs.