OVERLOOKED TUNISIA REEF PLAY MAY HAVE GIANT FIELD POTENTIAL
Fabrizio Rigo
International Exploration Consultant
Houston
Tunisia is considered by the petroleum industry one of the most favorable countries in the Mediterranean Basin. Merits are geological, economic, and political.
Exploration has been active in the last 20 years, but the various geologic provinces in the country are still considered immature at an international standard mainly because of complex geology. However, several discoveries (Fig. 1) (13146 bytes) like El Borma (Triassic production, reserves of 600 million bbl), Miskar (Upper Cretaceous production, reserves exceeding 1 tcf of gas), Ashtart (Eocene production, reserves of 290 million bbl), Sidi el Kilani (Upper Cretaceous production, reserves of 80 million bbl) indicate that Tunisia offers good possibilities for discovering semi-giant to giant oil and gas fields.
The economy is good, domestic gas market is quite large and expanding, and the Trans Mediterranean pipeline gives access to
European gas markets. Profit on oil is better than average due to proximity of refineries in Europe. Local currency, the dinar, is valued at the same level of the U.S. dollar, and inflation is flat.
In brief, Tunisia is considered the best country to invest in North Africa and one of the best among Arab nations.
REGIONAL GEOLOGY
The southeastern Tunisia Permian Basin (Fig. 1) (13146 bytes) is located in the Sahara platform, near the Mediterranean coast, at the northeastern margin of the early Ghadames basin, a Paleozoic cratonic sag basin bounded to the west by the Hassi Messaoud arch and to the east by the Tihemboka arch.
These arches are Mauritanian orogenic features, trending north-south and plunging to the north under the Atlas overthrust belt. The Atlas marks the general subduction area of the African plate under the European plate, which started during Oligocene times. Before reaching the Atlas the two Mauritanian arches encroach the Telemzane arch, a younger east-west trending Hercynian feature. The encroachment of Tihemboka with Telemzane arch is distinguished as Bou Nemcha high and defines the southwest margin of the Permian Basin.
The coastal area along the Gulf of Gabes, starting from the Libyan border, was the theater of sedimentation of over 4,000 in of Permian carbonates and clastics (Fig. 2) (17514 bytes). Axis of the basin trends northwest-southeast. The northwestern portion of the basin, probably more than half of its surface, foundered under thick late Mesozoic sediments and was later overthrusted by the Atlas fold belt. Mesozoic thickness here is over 4,000 in, while in the southeastern portion of the basin it does not exceed 2,500 in.
MESOZOIC STRATIGRAPHY
A brief description of Mesozoic sediments in the basin hereby precedes a more detailed discussion of Permian stratigraphy.
Triassic. The Triassic sequence displays an upper evaporitic facies, which extends upward in Liassic, and a basal clastics sequence.
Total thickness of Triassic ranges between 120-350 in, most of it evaporitic including salt. Maximum thickness of the basal clastics is 50 in. Triassic is missing along the alignment MA, ZMT, and BS wells and northeast of this alignment (Fig. 2) (17514 bytes). Triassic is generally transgressive over different levels of Permian. These transgressions are related to latest stages of Hercynian orogeny, which started in Upper Carboniferous-Permian times.
Jurassic-Cretaceous. Evaporitic sediments are present in the Liassic sequence along the southern flank of the Permian Basin, while towards the center of the basin Dogger becomes transgressive over Permian (BS1 well) or over Liassic. Middle Upper Jurassic is represented by 300-400 in of interbedded limestone, marl, shale, and dolomite of shallow pelagic environment. Aptian represents the Austrian unconformity, on top of Malm or even Permian (MA1 well). In Jurassic-Cretaceous transition times, sedimentation was characterized by continental clastics of various thickness, extending in age up to Cretaceous. Some evaporates are also present in this interval.
Middle Upper Cretaceous are represented by shallow water carbonate marl and shale with occasional intercalations of anhydrites.
PERMIAN STRATIGRAPHY
Lower Permian stratigraphy is known from subsurface well data, Upper Permian from both wells and outcrops.
Lower Permian. No wells penetrated Lower Permian. Its most complete stratigraphic sequence is known from ZMT well, which shows 680 m of marine pelagic limestone with thick shale intercalations at the top, followed by 608 m of continental to near shore shale with silt intercalations. This last sequence is cut by an Upper Permian unconformity. Extrapolations from seismic data indicate that total thickness sedimented was probably in excess of 2,000 m.
Upper Permian. Outcrops at Djebel Tebaga, northwest of the town of Medenine, along the northeastern flank of the basin consist of approximately 600 m of sediments. They begin with prevailing sandstone with limestone and shale intercalations followed by a 410 m thick sequence of biostromal and biohermal carbonates intercalated with shales and admitting channelized sandstones. The sequence ends with 120 m of shale and sandstone with rare limestone bed at the base. In several of the wells this Upper
Permian sequence is much thicker, probably over 3,000 m. The DSS well drilled 2,274 m prevailing Upper Permian carbonate with shale intercalations without reaching Lower Permian.
Two shallow water platforms developed in the Upper Permian basin (Fig. 2) (17514 bytes).
- Western platform.
It develops from the area of Kebilie extending as far as 75 km southeast. Thick biostromal carbonates with associated organic built-up ranging from barrier reefs to patch reefs are identified in this area by well and seismic data. Fig. 3 (21791 bytes) shows the seismic expression of barrier reefs B and B1 located south-southeast of Kebilie.
The two reefs developed along an east-west trending horst whose faults remained active from Upper Permian until Upper Jurassic times. Reef B is 14 km long (Fig. 4) (21662 bytes), with two culminations, towering over 650 ft above the base of the biohermal buildup. The structurally closed rock volume of this feature is in the order of 4 million acre-ft. Reef B is the second in a northwest-southeast trending alignment of six reefs, forming an uppermost Permian 75 km long barrier reef trend. Reefs are covered by several hundred feet of impervious terminal Upper Permian shale with sandstone intercalations. Their estimated depth varies from 2,800 to 3,300 m.
Fig. 5 (15983 bytes) shows the seismic expression of Reef E, in the southern part of the barrier. Northeast of Reef E a number of older reefs are found over a width of 25 km of shallow water platform facies. They are located at deeper Upper Permian and probably Lower Permian levels. These reefs are witnessing different cycles of biohermal build-ups, drowning under deep water, due to marine transgression over the platform.
- Eastern platform.
It outcrops at Djebel Tebaga (Fig. 2) (17514 bytes). It consists of a lower reef unit lying over a sandstone formation and an upper reef unit near the Upper Permian top. These units are covered respectively by 275 m of intermediate shale with biostromal intercalations and 120 m of uppermost shale and sand-stone sequence. Reefs of the lower reef complex are prograding over the platform with two main bioherms each 35 m thick. The upper reef complex consists of one 60 m thick bioherm. All bioherms are built up by encrusting algae and sponges. They are generally dolomitized and affected by karstification. For details refer to a study of the eastern platform published by ETAP in May 1994.
Seismic and well data indicate that the Eastern platform extends for at least 30 km southeast of Djebel Tebaga outcrops. Two reef-like seismic anomalies pertaining to two different levels in the lower reef unit are shown in Fig. 6 (13240 bytes). The DSS well drilled to test the shallower reef anomaly bottomed to 2,304 m in a shale and marl sequence with biomicrite, dolomicrite to dolosparite intercalations, with C1 to C3 gas shows. We do not have detailed information on the well, but it is our opinion that, if average vertical velocity to 1,350 msec is not less than 3,400 M/sec, the well missed the top of the reef by less than 100 M.
Of several other reef-like anomalies in the Eastern platform two were drilled by KJD and MED wells. Both wells tested salt water from thick biohermal carbonates deeply eroded and lacking impervious cover.
At KJD, Lower Triassic clastics at 986 m are transgressive over a 315 m thick sequence of Upper Permian shale, sandstone, and biomicrite with bryozoa, algae, and breccia. This last sequence probably represents a forereef facies. C1 to C3 gas shows and fluorescence were detected in the upper part of the sequence.
EXPLORATION HISTORY
First exploration in the area having Permian reef anomalies as primary objective was conducted between 1975-80. Three wells, KJD, DSS, and MED, encountered reef or fore-reef wet reservoirs with some gas shows. Results of these wells, located along the Eastern platform, discouraged further exploration efforts. Between 1985 and 1990 a new exploration cycle took place in the area of the Western platform. Primary objective of 10 wells drilled during this period was the Lower Triassic Tagi sandstone oil productive to the south at giant El Borma field. This interest for Triassic objective in this area quite far from El Borma was prompted by the BGL I well, which tested oil in basal Triassic Tagi sandstone.
Permian reef anomalies identified by seismic surveys were considered secondary objectives. Since Triassic objectives were thought to be present along most prominent anomalies or in sandstone stratigraphic traps, the obvious, deeper well-sealed reef anomalies were missed. However, most of the wells reported oil and gas shows in carbonate rocks of the Permian sequence.
By 1991 the permits, which covered the area containing the two Permian reef trends were abandoned by the operators.
RESERVOIRS
Main reservoirs in the area are Permian bioherms. Two are the types of bioherms described by ETAP:
- Limestone bioherms have both frame and fracture porosity. Frame porosity displays millimetric to centimetric cavities with an estimated original porosity of 30-35%. Naturally, early marine cement might have reduced these high values. In outcrops 0.5-4.7% porosities have been measured, but these low values are affected by late diagenesis. Fractures observed in outcrops are empty or enlarged by dissolution and locally cemented by calcite, barite, and iron hydroxides.
- Massively dolomitized bioherms are found both in outcrops and subsurface. In the Eastern reef zone (Fig. 7) (22979 bytes) they display intercrystalline pores, 2-50 microns in size (locally enlarged by dissolution), vugs of 400-500 microns in size, and fractures of at least two different orientations. Many of the fractures are empty. In KJD well dolomitized limestone of near reef facies displays an average porosity of 11.5%. An indirect reference to maximum potential reservoir quality of dolomitized limestone was found while drilling ZMT well, which lost circulation in 420 m thick dolomite zone and tested 36,000 b/d of saltwater.
Secondary reservoirs are represented by sandstone of basal Upper Permian and younger shallow marine channelized sandstone and underlying tidal bar to fluviatile sandstone. Sandstones are tens of meters thick.
Basal Lower Triassic Tagi sandstone, oil producing in Tunisia, is probably present in the block's area and could represent a third interesting reservoir objective.
TRAPS AND SEALS
The most important traps in the basin are bioherms embedded or covered by impervious late Upper Permian marine marl and shale. Above the reefs basal Triassic is structurally closed and Tagi sands, if present, would form good anticlinal traps.
Stratigraphic traps of both Permian and Lower Triassic channelized and tidal sandstones could be present in synclinal areas between reefs or against previously described west-northwest trending faults (Fig. 4) (21662 bytes). Seals for biohermal traps, besides Upper Permian shale, are also the basal Triassic clastics, with their numerous shale intercalations, and Middle Upper Triassic evaporites, including salt.
SOURCE ROCKS, MATURATION, MIGRATION
Ordovician. Geochemical analysis of well cores has demonstrated that Llanvimian Azel shale is a potential source with maximum TOC of 6% and an average TOC of 3.3%. Thickness of Azel shale can reach up to 150 m.
Silurian. In all North Africa Paleozoic basins, Silurian shales are known as excellent source rocks. In the basin area, the Tannezuft formation is composed of highly radioactive black shales with black mudstone stringers totaling over 100 m thickness. In Sabria North I well located west of Permian Basin, TOC values reached 11.92% with an average of 5.4%. Source potential is 27.6 kg/ton and vitrinite reflectance 0.8%.
Permian. The organically rich Upper and Lower Permian shale and carbonate in ZMT well penetrated between 1,500 and 2,600 m have TOC 0.22 to 6.85% and Ro of 0.3-1.0%. In the KGF well thermal maturity indicators suggest the interval from approximately 2,200 to 3,000 m is within the main oil generation window, in late mature stage of light oil or condensate generation. Some geochemical analyses of samples from wells in the Medenine area have given the following results:
HBR 1: 0.22-1.52% TOC, 0.8-1.8 P2 kg/ton
ZKH 1: 0.02-0.72% TOC, 0.3-0.6 P2 kg/ton
KJD 1: 0.1-2.07% TOC, 0.7-5.50 P2 kg/ton
Migration of hydrocarbons from Ordovician Azel shale probably occurred in late Cretaceous times, during Laramide orogenic activity. Migration of hydrocarbons generated in Silurian and Permian occurred in late Eocene Oligocene times, when the first alpine compressional forces had started to affect the area, the faults were rejuvenated and the fracturing of the reservoirs was dramatically increasing.
CONCLUSIONS
From available seismic data at least eight reef anomalies can be identified in the Western platform. The youngest reefs, located near the top of Upper Permian impervious sediments, form a 75 km long barrier trending northwest-southeast. Among them, anomaly B (Fig. 3) (21791 bytes) contains a closed rock volume of 4 million acre-ft.
At a low figure of 100 bbl recoverable oil per acre-ft, reserves could be 400 million bbl. With same parameters applied to four other reefs along the same trend, recoverable reserves could reach the 2 billion bbl mark. These reserves could strongly increase if reservoir parameters are better than the 100 bbl/acre-ft conservatively assumed above.
Deeper in the stratigraphic sequence three other anomalies would further contribute to the total reserve counted in the eight younger reefs. Moreover, other areas in the Western platform, covered by looser seismic grids, may conceal additional reef anomalies.
The Eastern platform is more tectonized than the Western platform and some of the anomalies are deeply eroded by Hercynian, Austrian, and Laramide unconformities. Geologic and seismic information are insufficient for an evaluation of the oil potential of reefs developed along this platform. However, the area deserves further studies. Over and above these biohermal anomalies, the basin probably contains subtler stratigraphic and possibly structural traps of both Permian and Lower Triassic clastics, which could be better defined when knowledge of the basin will improve following the search for hydrocarbons in the reefs.
In summary, all favorable parameters for discovering large oil fields seem to be present in the Tunisian Permian Basin:
- Biohermal, structural, and stratigraphic traps.
- Ordovician to Permian source rocks, including Silurian black shale which sourced over 100 billion bbl oil equivalent in Algerian, Libyan, and Tunisian basins.
- Excellent parameters for maturation, expulsion, and migration of hydrocarbons.
- Permian and Triassic shale, marl, and evaporate seals.
We should conclude that the general impression, from present knowledge of the area, is that little effort has been made for evaluating the huge potential of the Permian Basin. We find here a typical example of an overlooked play located in an area with favorable geological, logistic, and economic parameters.
THE AUTHOR
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