Despite decades of E&P activities in onshore and offshore Africa, there is still much oil potential left to unlock in reservoirs and basins. Currently, Libya is offering its first new bid round in 17 years. In writing this edition, I paid special attention to studies on three basins in Libya, plus a neighboring basin in Algeria. All are conducted by native geoscientists and published in lesser-known journals.
Also, I want to briefly congratulate AAPG's new executive director, Tom Wilker, who was announced last week and will be starting his new role on 5 May. You can learn more about his appointment here.
Rasoul Sorkhabi
Editor, Core Elements
An Oligocene Delta in Sirte Basin
Tonnello Photogrpahy/ Shutterstock.com
An article in the Journal of African Earth Sciences reports on the discovery of an Oligocene deltaic system in the northeast Sirte Basin in Libya.
About the Sirte Basin:
The Sirte Basin in north-central Libya is one of the largest and petroliferous basins in Africa.
It formed during the breakup of Gondwana and has experienced four main subsidence episodes: Early Cretaceous, Late Cretaceous, Middle Paleocene–Early Eocene, and Middle Eocene–Present.
The sedimentary package in the Sirte Basin is divided into Pre-rift (Cambrian–Ordovician age), Syn-rift (Early Cretaceous–Early Eocene), and Post-rift (Middle Eocene–Present).
The new study:
The researchers studied the seismic stratigraphy and well logs of the Sirte Basin and observed that Oligocene sediments capping the earlier sediments were deposited in a deltaic environment, named Sequence 7 (a third-order depositional sequence) in the basin stratigraphy.
The Oligocene-age (34–23 Ma) deltaic sediments belong to the Arida sandstone formation and are divided into three facies: Distributary channel, delta front, and prodelta.
The formation thickness is 270–700 meters.
Why it matters: “The study presents the first deltaic system interpreted from three-dimensional seismic and well log data in the Sirte Basin,” the authors stated.
Libyan geologists recently performed geochemical analyses of 59 source rock samples from the Mallegh Formation (Upper Jurassic limestone) and the Taqrifat Formation (Upper Cretaceous shale) in four wells in the Cyrenaica Basin in northeast Libya, facing the Mediterranean Sea.
What they found:
Results from shale samples in three out of four wells in both formations indicate:
Poor-to-fair organic richness (total organic carbon, TOC, values less than 1 percent)
Kerogen types III/IV
Tmax values of 430–455 degrees Celsius (oil generation zone)
Samples from one well (T1-41) in the Taqrifat Shale showed higher TOC values of 1–5 percent.
The researchers also analyzed oil chemistry of oil samples from two formations: the Cretaceous-age Daryanah Formation and the Eocene-age Antenlat Formation. GC-MS biomarkers showed that the oil was generated from calcareous source rocks deposited in a marine environment.
Oil in the Daryanah Formation does not seem to have originated from the Mallegh Formation.
Oil in the Antenlat Formation appears to have come from Taqrifat Shale.
Two recent studies suggest that Silurian-Devonian sediments provide some of the most prolific petroleum source rocks in North African basins.
New study #1: A study by Algerian geologists describes the organic matter characterization of a Frasnian shale formation in the Ahnet Basin onshore Algeria.
About the Ahnet Basin:
Located in southern Algeria, this basin covers an area of 75,000 square kilometers.
The stratigraphic column ranges from Precambrian to Carboniferous sediments capped by Cretaceous rocks.
The main petroleum source rocks are Silurian-age black graptolite-bearing shales and Givetian–Frasnian-age (Middle-Upper Devonian) mudstone-carbonate rocks.
All Paleozoic sandstone formations in the basin can be considered potential reservoir rocks.
Study #1 design: Researchers conducted geochemical analyses of Frasnian shales from two exploratory wells, X1 (18 core samples) and X2 (52 core samples).
Well X1 results:
Researchers collected samples from depths of 1,528 to 1,950 meters.
TOC values range from 0.42 to 4.57 percent.
A modified Van Krevelen diagram indicates Kerogen type III.
The pyrolysis maximum temperatures at S2 peaks (Tmax) are 486 to 605 degrees Celsius, showing two thermal stages of wet gas condensate generation at 1,528–1,720 meters and dry gas generation at 1,773–1,950 meters.
Well X2 results:
Samples depths ranged from 1,562 to 1,663 meters.
TOC values range from 3.5 to 10.8 percent.
Kerogen is mainly type III.
Tmax values are 570–599 degrees Celsius, indicating dry gas phase.
New study #2: Libyan geologists recently published a geochemical study of Silurian-age Tanezzuft shale from the Ghadames Basin in northwest Libya.
The Ghadames Basin is an intracratonic basin with an area of 350,000 square kilometers in northwest Libya. The basin extends to Algeria, where it has its depocenter with a sediment fill of 21,000 feet.
Study #2 design: Researchers collected 17 Tanezzuft shale samples from two wells with different depths. Samples from well B1-23 were collected at depths of 4,595 to 4,733 feet, and samples from well Q1-23 were collected at depths of 9,652 to 9,774 feet.
What they found:
TOC values ranged from 1 to 12 percent for both wells.
Kerogen type included types II and III for Well Q1-23 and types I and II for Well B1-23.
Tmax ranged from 417 to 441 degrees Celsius, corresponding to vitrinite reflectance (Ro) values of 0.3 to 0.8 percent. Higher temperatures and Ro values came from the deeper Q1-23 well.
The calcite percentage of rock samples varied from 3 to 13 weight percent. Two samples from Well B1-23 had calcite percentages of 56 and 70 precent.
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