Тип бассейна: Платформ
Подтип бассейна: Внутриплатформенный (интракратонный)
Класс бассейна: Синеклизный
Возраст бассейна: Древний - Палеозойский
Тип полезных ископаемых:
Геологический возраст начало:
Геологический возраст конец:
Площадь: 419132.28 км²
Murzuq Basin
Exploration in the Murzuq Basin
Petroleum exploration in the lightly-explored and sand-dune ridden Murzuq Basin started in 1957 using poor seismic data and unsophisticated testing techniques, but this effort led to discoveries in the last 25 years of economically significant oil accumulations in NC-115, NC-174, NC-186 and NC-101 (Fig. 1), having greatly increased interest for the area’s potential. The exploration history of the Murzuq Basin can be divided in three stages or periods: During an initial period (1957-1968) a number of wells were drilled in the Astan Arch, in the north-eastern border of the basin, leading to the discovery of the Astan gas field.
Fig. 1: Murzuq Basin oil and gas fields (after Hallett and Clark-Lowes, 2016).
Furthermore, five wells were also drilled southward, in the basin, of which the A1-76 well, drilled by PANAM in 1959, tested oil in the Devonian rocks. A second period (1970-1985) started with the drilling by Occidental of the well A1-NC34, and included significant exploration efforts by several other companies. Successful exploration efforts by ROMPETROL in NC115, and BOCO in NC101 led to the first economic oil discoveries in the Cambro-Ordovician rocks or northern Murzuq Basin. Extensive but unsuccessful exploration program was completed by BRASPETRO in NC58 in the southern part of the basin. The program included the drilling of eight wells, one of them, the A1- NC58 well, detected some oil accumulations in the Tahara Formation (Late Devonian). The third period, since 1990 until the present, mainly centered the exploration efforts at the NC58, NC101, NC115, NC174, NC186 and NC210 blocks, resulting the most notable for the successful exploration. In October 1997 an international consortium led by LASMO along with ENI and a group of five South Korean companies announced that it had discovered in the F1-NC174 well a large recoverable oil field called Elephant Field (also known as El Feel), with reserves around 700 MBB oil. In November 2000 a consortium led by REMSA along with TOTAL, OMV and SAGA announced the discovery of the NC186 oil field, which wildcat A1 flowed up to 2,500 B/D of 41ºAPI oil. In March 2001 they announces a second discovery by well B1-NC186, located 30km east to the well A1, which produced up to 1,300 B/D of 40º API crude. Three new findings were made in 2005 in the prolific block NC186: the D1, I1 and J1 wells, initially flowing between 2,097 and 4,650 B/D of light oil. In January 2007 Woodside Energy (a consortium also participated by REMSA and Hellenic Petroleum) announced the finding of gas in their well C1-NC210, initially flowing 986BOE/D. The well C1-NC210 is located about 150km southwards the Al Wafa gas field. Actually oil fields are in production, although with a low production rate, but exploration remains stopped since 2011 does to safety problems. Other paramount steps in the exploration history of the Murzuq basin were the findings by REMSA of the A1, B1, H1, M1, N1 and Q1 wells in NC115, and wells A1, B1, D1, J1 and I1 in block NC186, the AGIP wells, B1, C1 and F1 in block NC174, and the well D1 drilled by TOTAL in NC191 (Shalbak, 2015).
Reserves and Production
After the BP Statistical Review of World Energy (June, 2014), the Libyan proved reserves at January, 1, 2014 were of 48.5 BBB of crude and 1.50 TCM of natural gas. The proved reserves of oil and natural gas remained unaltered respect to the beginning of 2007. Table (1) shows the evolution of oil and gas reserves in the last 20 years in Libya, North Africa and the whole of Africa. According to these data, Libya results one of the African countries with larger oil in place reserves. Their crude proved reserves represent the 72.9% of the reserves of North Africa, and the 37.2% of the total reserves of Africa, as well as the 5.47% of the reserves of the OPEC and the 2.9% of the total proved reserves on the world. Respect to their reserves in natural gas, Libya has become an important gas province. Their current proved reserves of natural gas represent the 19.2% of the North African reserves, the 10.5% of the total reserves in Africa and the 0.8% of the gas reserves in the world.
Table 1: Proved reserves of crude (in BBB) and gas (in TCM) for Libya, North Africa and the whole of Africa (after Shalbak, 2015)
Libya, as an OPEC member country, has their production submitted to quota. The last allocation was established in the OPEC meeting as 1.7 MMBED (Shalbak, 2015).
The Libyan production in 2013 was 988 BBB of oil and 12.0 BCM of gas (BP Statistical Review of World Energy, June 2014). After a main drop in the production during 2011, these values represent the currently production tends to recover the activity before the production’s drop occurred in 2011. Fig (3) shows the Libyan’s evolution of crude and gas production between 1998 and 2013. The Libyan oil production during 2013 represents the 28.8% of the production in North Africa, the 11.2% of the total African production, the 2.7% of the oil produced by the OPEC and about the 1.1% of the world oil production. The production of natural gas smoothly arises during the period 2002-2007, with a trending to decrease after 2007 and a major drop during 2011 (Fig. 2). During the year 2013 the Libyan natural gas production was of 12.0 BCM, which represents the 8.2% of the North Africa production, the 5.9% of the total Africa production and the 0.4% of the world production. According with the above exposed data, the reserves-production ratio (R/P) for the whole Libya reach more than 100 years for both, oil and natural gas. Oil and gas reserves and production in Libya are owing to the contribution of five main sedimentary basins: Sirte Basin (onshore) and their offshore extension to the Pelagian (or Sabratah) Basin, the Ghadamis Basin, which extents offshore to the Gulf of Gabes as the Misratah Basin, the Cyrenaica/Benghazi and the Murzuq Basins. Of these five basins, Sirte and their offshore extension Pelagian Basins hold by far the larger reserves and production rates of Libya, whereas Cyrenaica (Benghazi) and Murzuq Basins, still remaining lightly explored, constitute two promising productive areas (Shalbak, 2015).
Fig. 2: Graph showing the evolution of oil and gas Libyan production since 1998 to 2013. Oil production in billion barrels (BBB axis) and gas production in billions of cubic meters (BCM axis) (after Shalbak, 2015).
The reserves of the Murzuq Basin represent about 7.4% of the Libya’s reserves. The larger probed reserves in the Murzuq Basin are located in the NC115, NC174, NC186 and NC210 blocks. The last oil in place estimation for the Murzuq Basin is about 7.3 BBB of oil and about 1.0 TCM of gas. The Murzuq Basin supplies about the 30% of the Libya’s current oil production (Shalbak, 2015).
The production of the Murzuq Basin began in late 1996, when the giant El Sharara Field comes onstream. Actually, El Sharara Field is producing about 200,000 B/D. Elephant Field started production by 2004, at an initial rate of 10,000 B/D rising to 125,000 B/D by 2007. Fields A and D in block NC186 started production in 2003-2004, producing in 2005 about 35,000 B/D (Shalbak, 2015).
Geology of the Murzuq Basin
A preliminary framework of the Murzuq Basin was firstly established by the geological map published by Desio (1939). The Murzuq Basin (Fig. 3) is an elliptical in shape, 800x800km large, covering an area of over 350,000 km2.
Fig. 3: Contour map of the basement of the Murzuq Basin (in feets) (after Shalbak, 2015).
The Murzuq Basin is a large intracratonic sag basin located in the North African Platform, which occupies a part of the southwest Libya and extends southwards into Niger, where it is there known as the Djado Basin. In the depocentre, the Murzuq Basin reaches more than 11,000feets (3700m) in depth (Fig. 3). The Murzuq Basin is not a sedimentary basin in the normally accepted sense, but it could more accurately be described as an erosional remnant of a much larger Paleozoic and Mesozoic continental margin which originally extended over much of North Africa (Davidson et al., 2000), so, the present-day basin geometry bears little relation to the broader and larger North African sedimentary basin which existed in the area during the Paleozoic times. The present-day borders of the basin are defined by erosion resulting from multiphase tectonic uplifts. The flanks comprise (Figs. 3-4): the Tihemboka high to the SW, the Tibesti high to the SE, and the Gargaf and Atshan highs to the N and NW respectively. The sedimentary infill of the Murzuq Basin comprises rocks from Cambrian to Eocene ages; however, the major and thicker sedimentary record corresponds to the relatively continuous Palaeozoic succession, whereas the Mesozoic and Cenozoic deposits are limited to thin and discontinuous sequences. The stratigraphic chart of the Murzuq Basin is shown in Fig (5).
Fig. 4: Geological map of the Murzuq Basin (after Shalbak, 2015).
Fig. 5: Stratigraphic chart of the Murzuq Basin (after Abdullah, 2010).
Petroleum System of the Murzuq Basin
Figs (6-8) show the petroleum system of the Murzuq Basin. There are two good reservoirs in the Murzuq Basin, namely the Hawaz Formation (Early-Middle Ordovician) and the Mamuniyat Formation (Late Ordovician, Hallett and ClarkLowes, 2016), while the poor and moderate reservoirs include the following formations:
1)Hasawnah Formation (Late Cambrian, Shaltami et al., 2019).
2) Achabiyat Formation (Early Ordovician, Shaltami et al., 2018).
3) Akakus Formation (Late Silurian, Shalbak, 2015, Shaltami et al., 2018).
4) Tadrart Formation (Early Devonian, Shalbak, 2015).
5) Awainat Wanin Formation (Middele-Late Devonian, Shalbak, 2015).
6) Assedjefar Formation (Early Carboniferous, Shaltami et al., 2019).
7) Dembaba Formation (Late Carboniferous, Shaltami et al., 2019).
Fig. 6: Lithostratigraphic column of the sedimentary infill of the Murzuq Basin showing the reservoirs (after Shalbak, 2015 and Shaltami et al., 2018, 2019).
On the other hand, the proved source rock in the basin is represented by the Hot Shale Member of the Tanezzuft Formation (Early Silurian, Hallett, 2002; Shaltami et al., 2017), whereas the potential source rocks include the following formations:
1) Melaz Suqran Formation (Late Ordovician, Shalbak, 2015).
2) Bir Tlacsin Formation (Late Ordovician, Shalbak, 2015; Shaltami et al., 2019).
3) Awainat Wanin Formation (Middele-Late Devonian, Shalbak, 2015).
4) Marar Formation (Early Carboniferous, Shalbak, 2015).
5) Assedjefar Formation (Early Carboniferous, Shaltami et al., 2019).
6) Zarzaitine Formation (Triassic, Shaltami et al., 2019)
Fig. 7: Lithostratigraphic column of the sedimentary infill of the Murzuq Basin showing the source rocks (after Shalbak, 2015 and Shaltami et al., 2019).
In addition, the seals include the Melaz Suqran, Bir Tlacsin and Tanezzuft formations, while the Wan Kasa (Early Devonian), Awainat Wanin, Marar and Tiguentounine (Late Carboniferous) formations are potential seals (Shalbak, 2015).
Fig. 8: Lithostratigraphic column of the sedimentary infill of the Murzuq Basin showing the seals (after Shalbak, 2015).
Where: HA = Hasawnah Formation AC = Achabiyat Formation HZ = Hawaz Formation MS = Melaz Suqran Formation MN = Mamuniyat Formation BT = Bir Tlacsin Formation TZ = Tanezzuft Formation AK = Akakus Formation TD = Tadrart Formation WK = Wan Kasa Formation AW = Awainat Wanin Formation MA = Marar Formation AJ = Assedjefar Formation DB = Dembaba Formation TG = Tiguentounine Formation
Data source:Petroleum System of the Murzuq Basin. Osama Rahil Shaltami, 2019
Следующий Бассейн: Sahara