A Geothermal Project As A Complement For An Oil Field Development

Abstract

The R&D Thermal EOR Project launched in 2017 a geological study with a french specialized start-up, TLS Geothermics, about the geothermal potential of the Lake Albert area in Uganda. This region is located in the western branch of the East African Rift System (EARS) and yields a high geothermal gradient. As such, it could provide significant geothermal resource as a complement to power a heavy oil field development. It is probably the first time that Total operates a hydrocarbon development project so close to an abundant geothermal heat source, and using this resource to support the oil development of the North and East leases of Lake Albert looked as a challenging but promising idea. Geothermal energy could in addition provide renewable electricity in the region for a moderate cost, as a by-product of the oil field development. The pre-feasibility study provided a conceptual geothermal model based on a preliminary geological model documented in terms of assumed or identified potential drains, and notional parametric reservoir study (flow‐temperature) drawn from known regional geological scenarios. In addition, it demonstrated that the subsurface water is mainly of meteoric origin (hot springs) and circulates in faults zones below the sedimentary cover (“upflows”) which ensures a thermal sealing of the system. The peripheral drainage basin of the study area largely provides fluid supply. By analogy with known geothermal systems similar to this very favorable tectonic context (active faults, stress field) the expected permeabilities are high, and the range of fluid flow rates estimated between 50 and 100kg/s. The temperature gradients associated with permeability contrasts along the major drains make it possible to have average gradients between 40 and 50°C/km. The realized thermal model demonstrates that in high-permeability faults zones and taking into account the conductivities and the heat production of the surrounding areas, the temperatures would be around 150°C at less than 3.5 km depth. In conclusion, there is a high probability to encounter a Rittershoffen-type geothermal system, with 150°C hot water and 50 to 100 kg/s flow per production well within the petroleum leases. The thermal stakes concern several hundreds of MWth, which could be exploited as a hot water loop and/or to produce power, for the oil processing facilities. The Total E&P Uganda “Tilenga” Project (development of onshore oil resources of blocks EA1-EA2) is expected to run out of associated gas after 7-years production and it would need to self-consume part of the crude oil production to provide the facilities with heat and power. Economics accounting for additional oil export vs additional CAPEX for the geothermal facility are deemed negligible, but CO2 emissions associated with oil consumption could be reduced or cut out without jeopardizing the project. Geothermal energy appears to have significant pro’s such as low production cost, locally available power and low impact on surface. The next steps of the study will include a higher resolution feasibility study based on newly acquired geological, geochemical and passive geophysical field data.

AAPG Datapages/Search and Discovery Article #90345 © 2018 AAPG European Region, Geothermal Cross Over Technology Workshop, Part II, Utrecht, The Netherlands, April 17-18, 2018