TUNISIA - The Geology.

As in neighbouring Algeria, the geology of Tunisia is dominated by a post-Paleozoic unconformity. The main source of its oil is a set of Silurian shales with most oilfields producing from Triassic reservoirs. It is believed that the onset of generation was delayed until well after the Hercynian orogeny. Traps are found in faulted anticlines.

Tunisia is the smallest of the North African countries. Its 164,150 sq km onshore area is wedged between Algeria and Libya. The northern region and a large part of the country's eastern frontiers are delineated by a Mediterranean coastline stretching about 1,300 km.

Geographically, the country is divided into a northern region lying above the eastward extension of the Algerian range of Atlas Mountains, a middle section of low plateaux and plains sloping towards Tunisia's eastern coast, and a southern region adjacent to the Saharan areas of Libya and Algeria.

The geological elements which are best developed in neighbouring Libya and Algeria enter into Tunisia and cross the country. The Triassic Province, a prolific petroleum region in Algeria, enters into the southern tip of Tunisia. The Cretaceous trend for oil onshore is best developed in Tunisia. It is also found on the Algerian side of the border (see 2005 survey of Algeria in Vol. 64, Nos. 5-8).

Several oil and gas fields have been developed on the Tunisian side, with the main reservoirs in Triassic sandstones and subordinate reservoirs in Silurian clastics. Traps are found in faulted anticlines.

The Ghadames Basin straddling Algeria, Libya and Tunisia has become a very interesting prospect for companies investing on the Tunisian side. Of particular interest to Tunisia-based operators is the TAGI sands play. Big oil discoveries in TAGI sands on the Algerian side included fields in the prolific Berkine Basin, where large oil reserves have been proven. Agip in 1964 was the first foreign operator in Tunisia to find the TAGI horizon, having discovered and developed the billion-barrel field of el-Borma in those sands (see Part 2).

The series of Berkine fields and Qoubba discovered in the more recent years has also led new E&P operators in Tunisia, like EuroGas of Canada, to identify many targets on their blocks. TAGI reservoirs typically produce oil at high rates from relatively shallow depths giving low development costs.

The Ghadames Basin extends from Algeria and runs across Tunisia into Libya. On the Tunisian side, this has been relatively unexplored. Several companies are now drilling exploration wells on the Tunisian side, to the east of Algeria's Berkine Basin where large oil reserves have been discovered.

Agip, active on the Algerian and Libyan sides of this basin, has made some oil and gas finds on the Tunisian side in a Silurian formation (Fm) called Acacus and a lower Fm called Tannezuft. Agip is an oil producer in Tunisia, Libya and Algeria.

On the Tunisian side of the Berkine Basin, Agip's Hammouda-1 wildcat was in 1998 tested at 3,508 b/d of 42[degrees] API oil, 1,400 b/d of condensate and 14.2 MCF/day of gas in the Tannezuft Fm. In March 2001 Agip completed the drilling of Hammouda North-1 well at a depth of 3,507 metres. Two drillsteam tests were run in the Acacus sands and these flowed a combined 3,873 b/d of oil and 2.9 MCF/day of gas. Further finds have been made by Agip and other companies in the past four years and these now are producing (see Part 2).

Agip in May 2005 had its Nour-1 exploration well in the Adam block in the south tested successfully for oil and gas. The well was spudded in March and encountered an aggregate 48 metres of net oil and condensate pay and 10 metres of net gas pay in the Acacus and Tannezuft Fms, over a gross interval of about 300 metres at depths of 3,200-3,500 metres. The zones were equivalent to productive areas in the nearby Adam, Hawa and Dalia fields, discovered in the last four years.

To the north of the country, a series of oilfields associated with the southern margin of the Atlas Mountains is found in a north-east and south-west trending basin. Reservoirs are in Cretaceous carbonates, mostly dolomites sourced by Cretaceous shales, and traps are anticlinal closures.

In the Cap Bon region, in the north-east, an interesting oil discovery was made in 1998 by Ecumed. The weld flowed at 3,007 b/d of 52[degrees] API oil and about 0.57 MCF/day of gas from a Fm called Bou Dabbous.

The Eocene has attracted the attention of foreign companies in recent years. This followed Marathon's discovery in June 1992 of gas and condensates in the Zarat block in the south. Located in 90 metres of water about 106 km north-east of Ezzaouia oilfield, the first wildcat there flowed at around 17.5 MCF/day of gas and 1,498 b/d of condensates. The US company said the reservoir's depth was 8,629-8,842 feet and there was a column of over 97 metres in the Eocene el-Gueria Fm. The column had a 25-metre oil zone and more than 67 metres of gas/condensate pay.

Offshore prospects appear to be moderately promising, but more so for natural gas than for oil. The country has a broad continental shelf in the Gulfs of Gabes, Tunis and Hammamet. There is only a relatively narrow shelf to the north in the Mediterranean proper. It is in the broad shelf that several E&P companies have been interested.

A territorial settlement with Libya over the so-called "7th November" block offshore, in the Gulf of Gabes, has led to the creation of Joint Oil Co. (JOC) shared by Libya's NOC and ETAP. This area is rich in oil and gas, being developed for JOC by a consortium of Nimir Petroleum of Saudi Arabia and Petronas of Malaysia. The geological features of one structure there, Omar, are similar to Libya's nearby oilfield of el-Bouri which has a large gas cap (see July 2005 survey of Libya & who's who in Vol. 65, Nos 1-4).

The Pelagian Basin is a major petroleum province in Tunisia. It is proving to be more rich in natural gas than in oil. The basin straddles the coast and includes the Gulfs of Gabes and Hammamet, together with adjacent onshore areas. The hydrocarbon habitat is similar both onshore and offshore.

Candax of Canada in early 2006 made an interesting gas/condensate find with its Chaal-I exploration well in the onshore Pelagian Basin. The well tested the Ali Ben Khalifa prospect in the Late Triassic/Liassic Lower Nara Fm. Reserves of the structure are estimated at 60 BCF (2P) and 844 BCF.

Traps were produced by anticlinal folding and the source is believed to be Late Cretaceous to Early Tertiary shales. Reservoirs are provided by Cretaceous carbonates, both limestones and dolomites with rare sandstones, and Tertiary sandstones and limestones.

The offshore Amilcar block of British Gas (BG), which contains the largest reserves of natural gas in Tunisia, lies in the Pelagian Basin. In this block are the Miskar field, the country's biggest producer of natural gas, and several other structures. Miskar produces gas from Cretaceous reservoirs called Abiod, R-1 and Bireno at an average depth of 10,500 feet. Miskar's recoverable gas reserves have been estimated at about 20 BCM.

The biggest among the other fields now being developed by BG is Hasdrubal. This field's reserves are estimated at 250-260 BCF of gas and 24.9m barrels of condensate, lying in a nummulitic limestone reservoir.

In the Gulf of Hammamet, an interesting oil discovery was made in January 1998 by Agip from a Miocene Fm called Umm Douil and a Paleocene Fm called el-Haria. This is part of the Pelagian Basin. The wildcat, Baraka-1, was tested at 4,353 b/d of 43[degrees] API oil and 4.48 MCF/day of natural gas at the depth of 2,670 metres.

In 1982, Marathon discovered an oil and gas reservoir in an Albrian-Cenomanian Fm called Zebbag, in 8 metres of water. This lies in the Djeffara Basin about 17 km south-east of Zarzis. The company then estimated the field's recoverable reserves at 16m barrels of oil and condensates and more than 100 BCF of natural gas.

The onshore section of the Pelagian Basin, first explored by BG, is proving to be gas-prone as well. Preussag Energie of Germany (whose assets in Tunisia were in 2003 bought by OMV of Austria) discovered natural gas in several small structures in the Kerkennah Ouest Block B, which it acquired from BG in 1997. The largest among these is the Chergui field, whose reservoir in a Mid-Eocene nummulitic limestone called "Reineche" has been reported to contain more than 70 BCF of recoverable reserves.

Another onshore Pelagian Basin find was made in early 1998 by Premier Oil of the UK. The company's wildcat tested at 3,600 b/d of 42[degrees] API oil and 3.7 MCF of gas in carbonates of the Upper Cretaceous Bireno Fm. The discovery was made at depths of 3,350-3,423 metres. Premier also made a discovery in its appraisal well, el-Jem-2, which was tested at 245 b/d of condensate and 13 MCF/day of gas from an Upper Cretaceous limestone Fm called Douleb.

Most prospective areas in Tunisia are gas-prone and oil reserves are not likely to be of the size found in Libya or Algeria.

Oil exploration is maturing and prospects for major discoveries in the established areas are low. As with Algeria and Morocco, there may be scope for a deep overthrust play associated with the Atlas Mountains, but the area for such a play in Tunisia is very much reduced.

There is exploration on 44 permits - 27 onshore and 17 offshore. There are about 50 different production sharing agreements (PSAs) in effect in Tunisia. The number of companies involved in them and in new exploration is big, relative to the size and prospectivity of Tunisia. Exploration permits in force, mostly onshore, cover more than 150,000 sq km. Foreign firms operating in Tunisia include Agip, Anadarko of the US, British Gas, CMS Oil and Gas, Samedan Oil, Marathon, Kuwait Foreign Petroleum Exploration Co. (KUFPEC), Total, Nuevo Energy, Union Texas Petroleum, PetroCanada, ConocoPhillips, and Pluspetrol.

The E&P Regime: Called "Hydrocarbons Code", Tunisia's E&P law for oil and gas regroups all the fiscal and legal regulations for E&P and the downstream. It gives the operators a variety of incentives. These range from a flat income tax rate and negotiable prices for commercial gas and electricity to tax-deductible provisions for field abandonment and reinvestment in exploration.

Under the law, the tax rate has been reduced from 75 to 50%. The royalty is 10% for oil and 8% for gas. ETAP takes equity in every E&P venture. The law authorises ETAP to set gas purchase prices at levels acceptable to the E&P operators. Oil prices are set by mutual agreement between ETAP and the operators.

Gas prices are based on low sulphur fuel, now over $5/m CF. Previously the gas price used to be set at 85% of the value of high sulphur fuel oil in the west Mediterranean market. That deterred foreign operators from developing gas fields. This has been mainly in the case of BG, which refused to develop a huge field until the government improved the gas pricing system and the fiscal regime (see Part 2). BG was upset by the previous system because the price of high-sulphur fuel oil fell from an average of $113/ton in 1996 to just about $70/ton in 1998, and in early 1999 HSFO was trading at $50-55/ton.

The law grants the gas E&P company the option of having a concession for an IPP related to its gas production. STEG is authorised by the same law to negotiate the power purchase price with both ETAP and the operator. The same goes for Steg's purchase of natural gas from local operators. On the basis of the agreed price formula the operator can have an IPP in line with STEG's plans for the expansion of the power sector (see Downstream Trends).

Particularly interesting is that the very small and remote gas fields now can be developed for small IPPs. There are many such fields in Tunisia which have not been developed.

In addition, the new law gives ETAP greater flexibility in negotiating PSAs for oil and gas and for both new exploration blocks and known petroleum reserves. But E&P companies already operating in Tunisia and preferring to have their pre-2000 PSA terms unchanged have been allowed to maintain them.

The fiscal regime gives the operators tax deductions for the cost of abandoning a field whose reserves have been depleted. Under the previous system there were no such incentives. Another new incentive is that the law gives the operators tax relief when profits from oil and gas E&P are reinvested in Tunisia. This applies for reinvestment in both the upstream and downstream sectors, such as gas-fired IPPs. The tax relief is negotiable on a case by case basis as the law gives both ETAP and STEG flexibility on this.

The pre-2000 regime was based on a law No. 90-55 issued on June 12, 1990 which replaced all previous legislations regarding the petroleum sector. This remains in force for those operators who prefer it.

BG, the biggest foreign investor in Tunisia, was the main company to benefit from the new law. As soon as the law was initially approved in late July 1999, the UK major began preparations to develop the giant Hasdrubal gas field, which is to become part of its offshore gas production system.

Other than those already in Tunisia, however, the law has only attracted small companies. One of these is Athanor Resources, a little known US company, which bought the stake of the Hungarian firm MOL in the Kebili exploration block and the Sabria production licence.

Tunisia first became a target for oil exploration in 1894, when the French colonial authorities granted the licences. But it was only in 1909 that the first well was drilled by a French company.

The first oil discovery was made in 1964 by Agip at el-Borma, in the extreme south near the Algerian border. The field, in the TAGI sand of the prolific Ghadames Basin, was developed and put on stream in 1965 by Societe Italo-Tunisienne d'Exploitation Petroliere (Sitep), owned jointly by Agip and the Tunisian government. Since then there have been many oil finds but they are all small.

The second discovery was made in 1966 at Douleb, about 190 km north of el-Borma, but it was small and el-Borma has remained the largest oilfield in Tunisia. The second largest field, Ashtart, was found in 1971 by Elf in an offshore area and came on stream in December 1973. But both el-Borma and Ashtart are in steady decline (see Part 2).

In late February 2006, ETAP signed up partners for two prospection permits and an exploration permit as part of its drive to accelerate the development of its upstream sector. A consortium of ETAP and Rigo Oil of the US signed at the end of February a four-year permit to explore the 1,616 sq km Bazma field near Kebili in the centre of the country. The permit will be 100% operated by ETAP. Rigo will invest a minimum of $3.5m for a works programme including the drilling of one exploration well and reprocessing and interpretation of existing seismic data.

Two offshore prospecting licences in the north were awarded to a consortium of ETAP, Anadarko Petroleum of the US and PetroCanada. The first two-year licence covers the 7,648 sq km Bechateur field in which the operator Anadarko will invest at least $2.84m. The minimum work programme includes acquisition and processing of 1,000 km of 2D seismic and reprocessing and interpretation of existing seismic data. The consortium was give a two-year prospecting permit for the 7,476 sq km Cap Serrat field. Anadarko will invest a minimum of $1.17m to reprocess and interpret existing seismic data and acquire 500 km of 2D seismic. ETAP will have a 50% interest in both permits, with Anadarko holding 33.333% and PetroCanada having the remaining 16.666%.

Having added two tracts to its list of available acreage, ETAP last October offered 15 blocks for potential bidders. Two new blocks were the Ksour Essaf (E4) in the offshore Pelagian Basin and Zaafarane (S4) which corresponded to the previous Maatoug block. The Mahdia offshore block was reduced to 3,524 sq km. The open blocks are in various geological domains including explored areas with proven hydrocarbon potential and prospective areas still under-explored. Data were made available on blocks including seismic lines, airmag and gravity surveys, geological data, well reports and studies.

Last October ETAP gave permits to First African Petroleum Consortium (FAPCO) for exploration of the onshore Fawar and Mezzouna oil and gas fields in the central region. The five-year contracts, with an optional renewal for a further three years, called for one well at each field, and spending of $12m. Fawar in Kebili covers 3,032 sq km. Mezzouna, in Sidi Bouzid and Kairouan, cover 4,508 sq km.

ETAP also awarded in late October a two-year permit to the REAP Tunisia of the UK for prospecting the 3,352 sq km Nabeul field in the Gulf of Gabes.

Medoil, a UK-listed firm operating in the Mediterranean, in May 2005 got a prospecting permit and EPSA on the offshore el-Louza block. The contract was won in conjunction with TGS-NOPEC of Norway, which held 5% but was to cover a larger proportion of the costs. The two-year contract gives the group exclusive rights to enter into a seven-year exploration permit and 30-year PSA. TGS-NOPEC is the operator in the prospecting phase. There is an existing oil find on the 4,100 sq km permit. Four other undrilled prospects are near the discovery well, each said to hold 40-50m barrels of oil. The JV in late 2005 began 600 sq km of 3D seismic over the find and the other four prospects.

Hadi Bouchamaoui Sons Int'l (HBSI), a private Tunisian firm, in late 2004 got onshore block 22 in Syria. HBSI was committed to invest at least $6m in the first two years of the licence, drill two wells and conduct 400 sq km of 2D seismic.