EXPLORATION LIMITED SINCE '70S IN LIBYA'S SIRTE BASIN

David Thomas
Thomas & Associates Hastings
England

Esso Standard made the first Libyan oil discovery in the western Ghadames basin in 1957. The Atshan-2 well tested oil from Devonian sandstones, and the play was a continuation of the Paleozoic trend found productive in the neighboring Edjeleh region of eastern Algeria.

Exploration in the Sirte basin began in earnest in 1958. Within the next 10 years, 16 major oil fields had been discovered, each with recoverable reserves greater than 500 million bbl of oil (Fig. 1) (153180 bytes)(Table 1). (27656 bytes)

Libya currently produces under OPEC quota approximately 1.4 million b/d of oil, with discovered in-place reserves of 130 billion bbl of oil.

STRUCTURAL FRAMEWORK

Libya is situated on the southern Mediterranean foreland of the African shield and includes a series of relatively undeformed Paleozoic intracratonic and complex polyphase sedimentary basins.

Libya's structural framework is characterized by five major periods of structural development:

1. Folding and consolidation in the Precambrian;

2. Formation of a north-northwest/south-southeast trending fault system during Cambrian time, which defined the axis of subsequent regional uplifts, and sedimentary troughs during the Silurian and Devonian;

3. Structural trend modification into a west-northwest/east-southeast direction during the late Paleozoic and Mesozoic. The development of this large scale corrugated undulation coincides with the separation of the Sahara platform from proto-Tethys. This separation began in northwest Africa during late Carboniferous or early Permian and reached Libya during the early Jurassic;

4. A late Mesozoic (late Jurassic-early Cretaceous) crustal collapse in north-central Libya, which formed the northwest-southeast oriented intracratonic rift system of the Sirte basin;

5. Finally, in late Tertiary to Pleistocene time, volcanic activity formed large basalt plateaus. Vulcanism occurred mainly along well defined, old, re-activated structural elements.

SEDIMENTARY BASINS OF LIBYA

The Sirte basin in north-central Libya differs markedly from the neighboring Kufra, Murzuk, and Ghadames basins. The latter are broad, essentially unfaulted Paleozoic depressions that were sites of aggradation over much of Mesozoic time. In contrast, the Sirte basin comprises a series of regional distinct platforms and deep trough areas that began to develop in latest Jurassic-early Cretaceous time. The tectonic strain that developed from the complex movement between the mosaic of African sub-plates was responsible for a wide zone of lithosphere extension and thinning over the Sirte region, causing regional uplift, subsequent Mesozoic and selective Paleozoic erosion, intracratonic rifting, and collapse.

Libya's sedimentary basins can be categorized into:

• broad, relatively uncomplicated intracratonic basins, with Paleozoic and Mesozoic sedimentary fill, such as the Ghadames, Murzuk, and Kufra; and

• modified rift system basins as exemplified by the Sirte basin, and the offshore Gabes-Tripoli-Misurata basin. The latter has a polyphase history, and its Recent basin geometry is attributed to oblique plate (or sub-plates) interaction between Africa and Europe during the Mesozoic, which subsequently became an important Neogene sedimentary depocenter.

THE SIRTE BASIN

The onshore portion of the Sirte basin measures some 500 km north to south and 700 km east to west with an areal extent of approximately 375,000 sq km. It has an estimated sedimentary volume of 1.3 million cu km.

In excess of 7,000 m of predominantly marine late Mesozoic and Tertiary sediments have accumulated in the deeper segments of the basin. Although Paleozoic deposition was generally widespread across the northern portion of the African plate, within the Sirte basin, only a meager record of that period remains after the domal uplift and erosion consequence of lithosphere stretching.

The earliest pulse of rifting probably began in the southeast in Upper Jurassic-Early Cretaceous time with early-graben fill of continental-fluviatile sandstones. Subsequent subsidence of the region preserved these major Sirte basin reservoirs.

Following the basinwide northwest-southeast oriented rifting in late Early Cretaceous time, the Cenomanian marine transgression began to slowly fill the trough areas, firstly with heterogeneous clastics, thin-bedded evaporates, and shallow-water carbonates. Upper Cretaceous clastics, notably the diachronous Bahi formation, were deposited as an erosional product of the exposed structural highs. Basin, and trough subsidence in particular, was slow during Cenomanian to Santonian time and increased appreciably during the Campanian, with the rapid deposition of thick, organic-rich marine shales in the trough areas.

By Maastrichtian time (Kalash formation, and equivalent to the Abiod formation in Tunisia), sedimentary fill had covered most of the structurally high areas within the Sirte basin proper. The general, basin-wide subsidence continued, and with a contemporaneous, gentle, regional tilt to the north. Extensive carbonate banks and shoals developed during the Paleocene, primarily building on the ubiquitous Kalash formation. The limits of these areally extensive banks were influenced by the pre-Kalash northwest-southeast oriented structural framework. However, in the western Sirte basin, the Satal carbonate bank developed unconcerned across substantial bounding faults between structurally high platforms and adjacent deep troughs.

These regional carbonate banks that grew in relation to the general subsidence of the Sirte basin were affected by global rise and fall sea-level changes and are layered with high-energy regressive sequences. They are time-correlatable across the basin and prove to be excellent hydrocarbon reservoirs. Over suitable and localized structural highs, the carbonate banks virtually remained in a high-energy environment throughout the Paleocene (e.g., Zelten), and also the normal calcilutite type-section of the Kalash formation grades to a high-energy oolitic dolomitized packstone (e.g., Waha formation). In one significant trough area, discreet reefal development took place, with the formation of the Upper Paleocene Intisar reef complex, where regional subsidence was particularly sensitive to localized carbonate build-up development.

During the Eocene, a general basinwide sea-level regression is exemplified by the thick anhydrite/dolomite sequences of the Gir formation (Ypresian), which extends northwestwards into offshore and onshore Tunisia, and overlain by the foraminifera nummulite banks of the Gialo formation (Lutetian).

The Oligocene is mostly eroded in the western Sirte basin, and the period marks the onset of Tertiary elastic deposition in the Sirte basin. The sandstone sequences of the Arida formation are important petroleum reservoirs in Gialo field.

Regional and local unconformities during the

Oligocene and Miocene record the influence of the Alpine orogeny in the stratigraphic sequence. Pliocene deposition is insignificant onshore but thickens northwards into the offshore.

PETROLEUM GEOLOGY

• Oil production to date (1994) is estimated at 18 billion bbl.

• The oil reserve distribution is equally split between carbonate and clastic reservoirs.

• Approximately half the oil is found between 2,500 m. and 3,000 m. and the other half above 2,500 m.

• Major source rocks are identified as Lower-Upper Cretaceous shales. A Triassic shale contribution is unquantified.

• Most widespread source rock is recognized as the Sirte shale formation of Upper Cretaceous age.

• Most of the oil fields are gas undersaturated.

• Most of the oil fields have active water drives, but pressure maintenance programs have often been installed early in their productive lives to accommodate the high production rates.

PLAY TYPES

Hydrocarbon production in the Sirte basin can be categorized into four play types (Fig. 2) (79285 bytes)(Fig. 3). (44916 bytes) Each of these categories contains giant oil fields in the Sirte basin.

• Type 1: Lower Cretaceous Sarir sandstones.

  Oil production from the Lower Cretaceous Sarir or Nubian sandstones is restricted to the extreme southeast sector of the Sirte basin. The preservation of these fluvial sandstones which range in age from possible Jurassic to Lower Cretaceous is limited to this part of the Sirte basin.

  The 'Sarir' basin is an east-northeast /west-southwest depression measuring some 25,000 sq km and bounded by several structural high areas consisting of pre-Mesozoic basement. Clastics eroded from these uplands constitute a sedimentary succession that reaches a thickness of more than 2,500 m in some discreet depocenters. A system of syn-sedimentary listric normal faults, mostly east-northeast/west-southwest oriented, has affected the sedimentation at different times as shown by the rapid thickening close to the downthrown sides and the rotation of tilted blocks. The 'Sarir' basin is made up of a number of inter-connected half-grabens.

  The Intra-Cretaceous (Aptian-Cenomanian) unconformity defines the base of the marine Upper Cretaceous sequence and is present throughout the Sirte basin. The unconformity reflects the cessation of nonmarine conditions during the syn-rift phase and the transgressive onset of marine conditions during the Cenomanian-Turonian.

  The unconformity is directly attributable to the entrapment of multiple billions of barrels of oil in the underlying non-marine Sarir sandstone.

• Type 2: Upper Cretaceous basal sandstones; pre-Cretaceous non-marine clastics; fractured Cambro-Ordovician quartzites; and fractured basement.

  Petroleum production from the Upper Cretaceous basal transgressive sands and the underlying fractured Cambro- Ordovician quartzites and basement is located on the platform areas within the Sirte basin.

The Cambro-Ordovician Gargaf formation quartzites are up to 300 m thick and constitute major reservoirs in Balat, Ora, and Raguba oil fields and Hateiba and Atta-haddy gas fields. With the exception of a few horst structures, these quartzites cap the basement highs within the Sirte basin.

The Upper Cretaceous basal transgressive sands of the Bahi formation are derived from the underlying Cambro-Ordovician quartzites and are major reservoirs in Nafoora/Augila, Waha, Raguba, and Hateiba fields. These sands are rarely more than 100 m thick and even in core samples are difficult to differentiate from the underlying quartzites. The reservoir qualities of these sands are quite variable and range from good to very poor. The Bahi is diachronous in nature and prone to facies changes with the shales and carbonates of other Upper Cretaceous sequences to produce reservoir-type facies such as the Maragh and Waha formations. The sands tend to develop in haloes surrounding the higher energy depositional locations and can have rudist mounds associated with them.

The Pre-Cretaceous nonmarine Amal formation sandstones (recognized only in Amal field) were inferred to be a fining upward sequence deposited by a "high-gradient, braided system carrying conglomerate detritus from the Rakb high." Amal sandstone litho-units are stratigraphicly time transgressive; a Cambro-Ordovician age was tentatively assigned to the Amal in 1972 by Barr and Weegar.1 On the basis of subsequent spore and pollen grain studies, the Upper Amal was later assigned a Late Jurassic-early Cretaceous(?) age. This formation is the principal reservoir of Amal oil field, from which it derives its name.

Play Type 3: Paleocene carbonate regressive sequences and build-ups.

Oil production from the Paleocene is spread widely across the western and central and southern parts of the basin. This was the area of clear shallow marine seas that supported a rich coral and algal population and was ideal for carbonate deposition and preservation. The seas became deeper and more open marine to the north where thinner marine shales were deposited.

It is convenient to differentiate the Paleocene into two gross carbonate depositional cycles:

The first cycle:

Danian Lower Landenian Lower Paleocene deposition transformed the basin configuration with extensive carbonate deposition in the east and over parts of the Dahra and Beda platforms in the central Sirte basin. The structurally high regions of the Zelten and Beda platforms shoaled the Paleocene seas and became the location of large cor-algal reef developments (Zelten, Defa, and Beda fields). These localized carbonate build-ups continued to keep pace with subsidence and achieved substantial vertical relief. The coralgal carbonates in Zelten and Beda oil fields continued to grow into the Upper Paleocene.

In the west, and overlying the deep marine Hagfa shale, the Beda formation became more and more under the influence of the basinwide regressive conditions and resulted in the deposition of high-energy carbonate (miliolid/pelloidal/algal) reservoir units, and with the subsequent development of the important Ora, Meem, and Beda C members of the Lower Paleocene and the Mabruk member of the Upper Paleocene-aged Dahra formation. They are major oil producing intervals in Ora, Meem, Sabah, Mabruk, and Dahra-Hofra fields.

The second cycle:

Lower Upper Landenian

The beginning of the second unit is recognized in the Upper Paleocene by the deposition of a transgressive shale sequence. During middle and upper Landenian time, progressive shallowing of the cycle occurred. The western and central parts of the basin were dominated by the deposition of a regional calcilutite facies (Zelten facies) within a restricted shelf and localized high-energy carbonate complexes, while deeper-water deposition (marls, shales, limestones) with localized reef carbonates (Intisar A, B, C, D, and E) and the Upper Sabil shelf carbonates developed in the eastern part of the basin.

Important Upper Paleocene production is found on the Zelten and Beda platforms.

The reef growth at Nasser (Zelten) and Beda continued uninterrupted throughout the Paleocene. At the end of the Paleocene a widespread shale section was deposited. This unit completed the second cycle of the Paleocene and sealed the Zelten and Beda reefs. The fact that some of the Intisar reefs are wet or only partly filled with oil can possibly be attributed to seal problems. The reefs may be in communication with the overlying porous Lower Eocene Gir formation dolomites and carbonates.

Play Type 4: Eocene and Oligocene carbonates and sands.

Production from Eocene and younger rocks occurs in three areas in the Sirte basin.

Giant Gialo field is located on the axis of the Adegabia trough, and other production is scattered in fields on the Zelten and Jahama platforms and in the western Sirte basin trough areas.

Gialo field production is mainly from Middle Eocene nummulite facies of the Gialo formation. There is also production from Oligocene sands of the Arida formation. The Gialo structure is an anticlinal drape feature produced by differential compaction of Upper Cretaceous and Paleocene sediments over a structurally high basement horst. Local depositional topography during the Middle Eocene accounts for the development of good reservoir facies.

A significant Eocene play exists in the Dor Al Beida and Zella troughs (western Sirte basin), with production from regressive dolomite units of the Facha member, and overlain by thick evaporates of the Gir formation. Ghani, (150 million bbl), 'VVV' (100 million bbl), and Zella (120 million bbl) are the most significant oil fields. Zueitina (ex-Occidental) has pursued this play in its NC74 permits acquired in 1976 and is presently producing about 40,000 b/d of oil from the Zella trough region.

Oil has also been produced from Lower Eocene dolomites located south of Gialo field.

SOURCE ROCKS

The most widespread source rock in the Sirte basin is the Campanian aged Sirte shale formation. The Upper Cretaceous marine transgression encroached from the north, and although the northern areas of the Sirte basin were generally open marine, basin geometry and sedimentary fill sequence in the trough areas gave rise to restricted marine environments further into the interior of the basin. The semi-enclosed seas confined to the graben and relatively low-lying areas in pre-Kalash time, promoted water stratification and anoxic conditions ideal for the preservation and accumulation of organic-rich material. The source rock depositional model is one of continuous structural growth of platform and graben elements with constant supply of sediments and nutrients by marine and fluvial drainage systems into the troughs. By the end of Campanian time, the grabens were silled.

TOC values greater than 1% occur commonly in the central parts of the troughs, and in the deeper graben areas net intervals exceed 500 m. Concentrations of TOCs in excess of 5% are also recorded.

Geochemical analysis defines - the type of organic matter as mostly amorphous and herbaceous, while algal fractions increase towards the center of the troughs.

In southeast Sirte basin, possibly two other source rocks have been identified. Oils have been identified that are carbon isotopically heavier and quite distinct in sterane-triterpane comparisons from the Sirte shale source rock. Some of the Play Type I oils are waxy and appear to have an affinity to Lower Cretaceous non-marine shales and/or Etel formation evaporates (Turonian). The oils in Amal field are also distinct and bear source/oil similarity to an adjacent nonmarine Triassic shale interval.

GENERATION, MIGRATION

Sirte shale maturation studies indicate a required depth of burial in the order of 3,500 m for major oil generation. Favorable organic facies and significant net TOC intervals are found in the trough areas. Thus, sources of major hydrocarbon generation can be recognized within the interconnecting graben system of the Sirte basin.

Sirte shale oil generation is estimated to have started in the Early Miocene and is continuing today. So potential oil accumulations were formed, modified, and even destroyed by the tectonic effects of the Alpine orogeny.

It is also recognized that the major oil accumulations on the platform areas are adjacent to the oil generative depressions. On the wider platform areas no large oil accumulations have been discovered away from the platform bounding faults, and this suggests a generally short lateral oil migration system on the platform areas. This is probably attributed to impermeability within carbonate facies variations.

OIL RESERVES

Libya in 1990 raised its official estimates for proved remaining recoverable reserves to 45-50 billion bbl from 22.8 billion bbl. This was based on an estimated 130 billion barrels of oil-in-place and an average 35% primary recovery factor.

Libya has to date produced some 18 billion bbl of oil from the Sirte basin. This implies ultimate recovery of 63-68 billion bbl (Table 2) (16147 bytes). Such a recovery of 48-52% of in-place oil would only be possible under secondary and tertiary recovery techniques. Libya has already begun selective secondary recovery schemes and Intisar 'D,' for example, had a miscible flood scheme installed from virtual first production stage. But substantial further capital investment is required to achieve the implied rates of recovery.

A rationalization of the official reserve estimates is provided (Table 2). (16147 bytes) The estimate of secondary and tertiary recovery for the smaller fields is illustrative, and it is high unlikely that secondary and tertiary recovery techniques could be deployed economically for most of these reserves. The official estimate therefore has to attribute a slightly higher ultimate recovery factor to the giant fields than the official 48-52% range for all fields.

The giant fields clearly have further potential. For instance, Sanford' suggested in 1970 that Sarir field had the potential from primary recovery to extract 3 billion bbl from the estimated 12-13 billion bbl in place. With secondary recovery he estimated this could rise to 6 billion bbl. Production history suggests this may well be the case.

POTENTIAL

Production. Libya has a small number of giant oil fields that hold some 77% of discovered in-situ resources. The country's reserve replacement from the mid 1970s has been poor and not adequate to have replaced reserves produced in the same period. Libya is therefore depleting a mature oil reserve base. Implementation of secondary and tertiary recovery techniques is therefore vital to the future maintenance of Sirte basin production levels in Libya beyond the 1990s.

Exploration. In 1958 to 1961 some 62% of reserves found had been discovered. By 1969 approximately 81% of all oil discovered to date had been found. This reflects the early discovery of the larger fields in the Sirte basin.

Since the late 1970s the Sirte basin has not experienced intensive exploration, and it is arguable that the lack of oil reserve replacement is the result of too little wildcatting and a too cautious approach to the application of new exploration ideas. The combination of modern geophysical techniques and a much greater confidence in stratigraphic play concepts-which ironically is a proved and prolific oil trapping mechanism in the basin-will most certainly enhance the reserve base in the future.

The known and potential gas reserves of the Sirte basin have not been discussed in this article. However, they represent a significant resource base.

ACREAGE AVAILABILITY

A wide band of open acreage is available in the northern onshore and southern regions of the Sirte basin.

An important exploration concern is the encroachment of fresh water along the onshore boundaries of the basin. However, in the intracratonic Murzuk basin to the southwest an important oil province has been discovered in a predominantly fresh-water flushed environment.

THE AUTHOR