Shale gas is an unconventional hydrocarbon resource. In its simplest terms, it can be defined as a natural gas resource sourced from organic rich fine grained rocks that act as a source, reservoir and

seal. Following the recent technical and commercial success obtained in the US, exploration activities is being taken to basins which are thought to have potentials for shale gas around the world.

Basin Evolution

The Ghadames Basin (also referred to as Berkine Basin, Illizi Basin or Murzuq Basin in literature) is a ‘large Intracratonic-Sag basin’ covering parts of Tunisia, Algeria and Libya with a basin area extent

of about 350,000km2 (see Fig 1). The basin was initiated in the Early Paleozoic (via the reactivation of pre-existing structures created during the Pan African orogeny) as part of a very large Paleozoic

passive margin extending from Morocco (west) to Egypt (East). The present day basin is the result of successive regimes of tectonic activity which has led to reactivation and modification of fault

patterns (inversion) and depocentre migration through time.

These tectonic episodes can be summarized into 3 main events:

The first being the Pre-Hercynian episode which was a period of basin initiation/subsidence (due to reactivation of Pan African structures) of a very large Paleozoic Passive margin basin covering the

whole of North Africa of which the Ghadames basin was part of .

The second episode was the Hercynian episode characterized by widespread uplift and erosion Pre – Hercynian sediments especially significant in the North and west of the Ghadames. The

widespread uplift allowed for a demarcation of the initial large Paleozoic basin into smaller sag and foreland basins

The third episode occurred in the Mesozoic and is related to the initiation of the Tethys and the Central Atlantic. This event gave rise to a regional tilt of Paleozoic rocks and a Northwest shift in the

basin’s depositional axis

The basin has a sediment fill of about 8000m (in its deepest parts) which comprises of continental clastics, glaciogenic sediments, marine carbonates and evaporates.

Exploration History

Exploration for conventional hydrocarbon resources in the Ghadames basin began in the 1950’s. Several discoveries were made in the Libyan end of the basin before 1990’s and the recoverable

reserve volume was put at 3.5BBOE. These initial efforts targeted fault bounded structural highs.

However in the 1990’s, additional recoverable reserves of about 5-6BBOE discovered in the Triassic and Devonian reservoir intervals was estimated to be in the Algerian end of the basin. These

successful exploration efforts were driven by better seismic imaging and better understanding of plays.

Currently the Ghadames basin is thought to be underexplored, and the reserve estimates is put at 32BBOE with the Algerian end having a larger share of the resources. The key reservoir intervals are

Cambro-Ordovician (gas is the dominant phase), Silurian-Devonian (even split of oil and gas resources, especially in Libya) and the Triassic (oil is the dominant phase).

Shale gas exploration in the Ghadames basin is in its infancy: At the moment, exploration efforts is being carried out in the Tunisian end of the basin. The current reserve estimate is put at 80-120TCF.

Source Rocks

The main prolific source rocks in this basin are the Early Silurian source rocks (Tanezzuft Shales) and the Middle – Upper Devonian (Frasnian) source rocks (Aouinet Ouinine Formation). These source

rocks are responsible for hydrocarbons generated (Tanezzuft: 80-90%; Frasnian: 10-20%) within the Paleozoic basin. It has been established that more than one period of generation and expulsion of

hydrocarbon the source rocks due to exhumation associated with tectonism (especially the Hercynian, Austrian and Alpine orogenic episodes).

Early Silurian source rocks (Tanezzuft Shales)

The widely spread Tanezzuft Shales is a graptolitic, organic rich, laminated, commonly gypsiferous and occur as grey – green and red shales with interbeds of silt and fine sands. Its thickness varies

from < 200m to over 500m and was laid down during the onset of widespread flooding of the sea in a Passive Margin tectonic setting in Early Silurian times It is dominantly a Type 2 kerogen source

rock with present day TOC ranging from about 3% to > 15% and HI values varying form 250-450mgHc/g. It has been termed a ‘double hot shale’ in some parts of the basin . Generally, it shares very

close similarity to the Barnett shale (US) in terms of composition and can be subdivided broadly into three lithostratigraphic units - an upper layer which is quartz rich, an intermediate layer rich in

calcite and a lower clay rich hot shale with the highest source rock quality.

Middle – Upper Devonian (Frasnian) source rocks (Aouinet Ouinine Formation)

Aouinet Ouinine Formation is a calcareous / marly, organic rich radioactive shale with very similar source rock characteristics to the Tanezzuft shales. It has 4 end members (I, II, III, IV ), with the best

source rock properties in III and IV (i.e. average organic richness (TOC) of 5% and high HI of about 700mgHC/g TOC and oil prone T2 kerogen). Its thickness increases to about 200ft towards the

2% TOC

cut off

1% Ro cut off

Detailed shale reservoir characterization and

geochemical analysis should be carried out to understand

heterogeneity within the shales and also to find out the

dominant shale gas type (i.e. free gas, sorbed gas or

dissolved gas.

Basin modelling was carried out for wells BRD—1 & ONE-1

using BASINMOD software (see Fig 3). Amount of

exhumed sediments during tectonic events and heat flow

values (see Fig 8) used was taken from literature.

Fig 8: Heat flow model for Ghadames Basin (After Underdown &

Redfern, 2008)

Fig 10: Burial history plots for well ONE-1

Source rock is

late mature

and currently

in the wet gas

window

Fig 9: Burial history plots for well BRD-4

Source rock is

over mature

and currently

in the main

gas window

Fig 1: Ghadames Basin (modified after Underdown and Redfern, 2008)

Longitude

Latitude

Fig 4: Initial TOC 3D Map of the Tanezzuft shale

Latitude

Longitude

Fig 6: Thermal maturity 3D Map of the Tanezzuft shale

Longitude

Fig 3: Initial TOC Map of the Tanezzuft shale

Latitu

de

Fig 5: Thermal maturity Map of the Tanezzuft shale

Longitude

Latitu

de

Basin Modelling Wells

Fig 7: Hydrogen index map for the Tanezzuft shale

Longitude

Latitu

de

High risk :

High TOC,

Low Maturity

Low risk : High

TOC, High

Maturity

Fig 8: Maturity map + Initial TOC of the Tanezzuft shale

Basin modelling results for well BRD-4 results show that the source rock has

only recently entered the main gas window in the Paleocene. This plus the

fact that it has not been affected by basin tectonics since it entered the main

gas window is particularly good for shale gas development because there is

potential for gas absorption and retention of the gas it has generated.

Well ONE-1 basin modelling results show that the source rock is currently in

the wet gas window and has also not be affected by tectonic episodes since

it entered the wet gas window.

Basin screening results shows that ‘sweet spot’ (see Fig 8) exist for shale gas

exploration in the western and parts of the central Ghadames.

Key References

Underdown, R. & Redfern, J. 2008. Petroleum generation and migration in the Ghadames Basin, North Africa: a two-dimensional basin modelling study. American Association of Petroleum Geologists Bulletin, 92, 53–76.

Jarvie, D.M., Hill, R.J., Ruble, T.E. and Pollastro,

R.M.,2007, Unconventional Shale Gas Systems: The

Barnett Shale of north-central Texas as one model for

thermogenic shale-gas assessment. The American

Association of Petroleum Geologists, AAPG Bulletin,

V. 91, No. 4 (April 2007), PP 475-499

Troudi, H.R., Meskini, A., 2012. The Unconventional

Gas play in Tunisia Ghadames Basin require a certain

edge. Shale Gas Workshop—Oran, Algeria 27-29

February, 2012.

Ghadames Basin Background

Introduction Basin Modelling

Recommendation

By Aitalokhai Joel Edegbai, Email: joel.edegbai@yahoo.com

Shale gas Potential of the Ghadames Basin

Aims and Objectives

The main aims and objectives of this study is to evaluate the Shale gas potential of the Ghadames

Basin and identify ‘sweet spot’ for exploration within the basin based on Jarvie et al., (2007). To

achieve these, the following questions should be answered.

Does the Early Silurian source rocks (Tanezzuft Shales) possess sufficient TOC (i.e. ≥ 2.0% Initial

TOC)?

What is its Kerogen type?

Has Early Silurian source rocks (Tanezzuft Shales) reached the right thermal maturity (1.e >1.0%

Ro)?

Does the shales have suitable chemical composition?

Methodology

Basin Screening:

Screening the Ghadames basin under the following set criteria

Organic richness (≥ 2.0% Initial TOC)

Kerogen type (Preferably Marine source rocks)

Thermal maturity (≥ 1.0% Ro)

Mineralogy/chemical composition ( ≥ 40% Quartz or Calcite )

Basin Modelling:

BASINMOD software will be used to do the following:

Modelling of wells in areas that passed Basin screening to find out where they are in the

maturity window and the time of entry into their present maturity window

The Ghadames basin was screened with the aforementioned criteria (based on Jarvie et al., 2007). The following deductions were made:

The Early Silurian source rock (Tanezzuft shales) have sufficient initial TOC over large areas of the basin (see Fig 3 and 4).

The Tanezzuft Shales are predominantly Type 2 - Marine source rocks (from literature).

Maturity increases towards the west where the gas shales are currently within the wet gas—main gas generation window (see Fig 5 and 6)

Findings from Troudi and Meskini, (2012) suggests that the Tanezzuft shales have moderate amounts of Silica and Calcite.

Basin Screening

Fig 2: Ghadames Basin Stratigraphy (after Yahi et al, 2001)

Based on the available literature, the Early Silurian source rock (Tanezzuft shales) have the lowest exploration risks. It is the main exploration target for Shale gas since it has a better geographical spread and it is currently in the wet gas to dry gas stage of hydrocarbon generation (especially in the Western Ghadames).

Hence, this study would focus on the Early Silurian source rocks (Tanezzuft Shales).

Study Focus

1

1

‘SWEET SPOT’

2

2

The following conclusions can be made from the this study:

Ghadames basin has got the potential for shale gas (Reserve estimates are put at 80-120TCF).

The ‘sweet spot’ for shale gas exploration based on the

available data is majorly the western and parts of the

central Ghadames basin (see Fig 8).

Conclusions Discussion

Ghadames Basin

—- BRD-4 well

—- ONE-1 well