Ordovician Tight Gas Play in Tunisia, Ghadames Basin – North Africa
In North Africa and particularly in the Ghadames sag basin, large resources of natural gas are in place in semi-conventional low-permeability Paleozoic sandstone reservoirs. The greatest potential for gas-condensate accumulations in the Tunisian part of the Ghadames basin is generally seen in Ordovician tight sandstones (Kasba Leguine, Bir Ben Tartar, Jeffara main sand and M'Krata Formations), immediately below the Lower Silurian Tannezuft world-class source rock (“hot shale”).
This rich source rock (TOC up to 17% and an average thickness of 30m) is currently in the gas-condensate to oil window and it directly overlies the low-permeability Ordovician reservoirs. The Silurian hot shale represents the essential ingredient for the development of a pervasive gas accumulation play. The gas generated from this excellent source rock interval charges the underlying sandstones mainly through a complex faults system in the central part of the basin. With the gas charge, the pore pressure increases at rates that exceed the normal gradients and the Ordovician sandstones become locally over-pressured. The lateral migration via regional faults is confirmed by numerous discoveries at the edges of the Ghadames basin.
The Ordovician reservoirs have a remarkable lateral continuity and the detailed facies description tied with electric-log signature led to the subdivision of the Ordovician reservoirs into two pro-gradational third order sequences. The overall progradational pattern was terminated by transgressive events as a major drop of sea level is recorded at the end of the Lower Caradocian due to the regional Taconic transpressional event.
Besides the relatively small-scale structural traps (four-way dip closures or fault-bounded anticlines) more complex, combined structural and stratigraphic traps are found in the glacial Upper Ordovician Jeffara deposits. The stratigraphic trapping mechanism is related to the development of incised paleo-valleys filled with multiple fluvio-glacial and marine clastics. Their present day depth ranges from 3,300 to 4,400m. The discovery of pay zones outside of structural closures confirms the significant stratigraphic upside in such a pervasive gas play. The trapped reservoir fluid is gas with substantial condensate yield and a high dew point pressure. This might cause early liquid drop-out in the reservoir during the depletion drive production resulting in productivity index deteriorations.
Mesogenetic alterations which include abundant quartz overgrowths and clay cementation have had an impact on deposition-related porosity modifications, thus on reservoir quality, and enhanced the heterogeneity of the glaciogenic deposits. The quartz overgrowths and the silica cement are the cause of reservoir degradation in the sandstones resulting in permeability of 0.1-1mD and low porosities of 6-11%. Net pay ranges from 10 to over 30m with an average Sw of 30%.
The low permeability of the reservoir is the critical factor for production. The contribution of natural fracturing to the reservoir performance is not fully understood yet. Substantial gas-condensate rates, however, have been observed in several wells without any reservoir stimulation. It is expected that proper stimulation and drilling of deviated or horizontal wells will improve reservoir performance significantly and will drain the unconventional upside pay located outside the existing closures.
This pervasive gas play is becoming a very attractive target in the Tunisian Ghadames Basin, as it has substantial gas resources which can be tied to a pipeline in the next few years.
AAPG Datapages/Search and Discovery Article #90226 © 2015 European Regional Conference and Exhibition, Lisbon, Portugal, May 18-19, 2015