Juan Carlos Pucci
Consulting petroleum geologist
Buenos Aires
Argentina, in terms of the exploration/production potential involved, has opened three types of areas to the international industry:
- Areas of secondary interest (marginal fields);
- Yacimientos Petroliferos Fiscales SA's (YPF) central
fields; and
- Exploitation and exploration association contract areas.
The areas (Fig. 1) differ by the oil and gas potential included in each, the resultant contract terms, and the difference in risk involved in exploitation versus exploration targets.
In this article, specific areas and fields are discussed, especially the oil and gas potential as expressed by past production, remaining reserves, and future potential.
PRODUCTION, RESERVES
Argentina's all time cumulative production is 5.18 billion bbl of oil and 14.578 tcf of gas; 37,667 wells have been drilled, about 70% of which were oil productive and 22% were abandoned as dry holes as of December 1991.
About 84% of the production is due to primary recovery and 16% is by enhanced methods. Oil recovery averages 198,279 bbl/well. More data are shown (Table 1).
Since 1982 Argentina is self sufficient in oil, but less oil was discovered than was produced. During 1991, the country's production averaged 56.7 b/d/well and 2.36 MMcfd/well of gas. A total of 10,123 wells produced 176.4 million bbl of oil, while 1,222 wells yielded 868.4 bcf of gas.
At yearend 1991 the proved reserves totaled 1.56 billion bbl of oil, but oil production rose 13% in 1992. If domestic demand were to rise at that rate in the future, the country could become a net importer by 1998.
In 1990 the proven reserves were audited by a U.S. consulting firm, and the results indicated that the country's oil reserves at yearend 1989 were almost 630 million bbl less than those originally calculated.1
In addition, a new adjustment was made for the 1991 reserves.
MARGINAL FIELDS
The first stage of the oil and gas privatization policy was the sale of 221 marginal fields grouped into 86 areas (Table 2).
The selection of the fields was given in Decree No. 1055; it established that YPF's fields that averaged less than 1,260 b/d during 1988 or fields inactive for more than 5 years were included in areas with a limited 1,000 sq km of adjacent acreage for supplementary exploration.
Most of the areas had known oil reserves, although a total of 42 fields without reserves were included. The areas were offered in three rounds of bids; more than $470 million was obtained for 86 areas, 69 of which contained reserves of 62.4 million bbl of oil and 819.56 bcf of gas. The average value paid was $7.21/ bbl.
NORTHWEST BASIN
In the Northwest basin the fields were grouped into nine areas (Fig. 2), leading to a total exploitation fee of $19.996 million.
The most significant field offered was Caimancito (Fig. 3). The field corresponds to an anticline with surface expression and was originally outlined and drilled by Ultramar before World War II; drilling had failed to reach the targeted limestone due to limited rig capacity.
In 1968 YPF drilled the 1X Caimancito well that flowed 2,860 b/d of oil at 13,087 ft depth and resulted in the discovery of one of Argentina's most prolific fields.
The field's cumulative production of about 62.37 million bbl of oil was obtained from carbonate reservoirs in a north south trending anticline with a faulted east flank. Minor production is from Tertiary clastics of the Maiz Gordo formation. The field's reserves are 2.48 million bbl of oil.
Although the Puesto Guardian area drew the highest exploitation fee, it does not contain the maximum amount of reserves. The area includes a series of 11 fields located along the southern flank of the Lomas de Olmedo sub basin. The production is recovered from sandstone intercalations and limestones of the Lower Tertiary Upper Cretaceous Yacoraite formation.
In the Vinalar, Selva Maria, and La Brea areas the reservoir is also the Yacoraite formation, while in the Surubi and El Chivil areas the reservoir corresponds to the volcanic conglomerates of the Cretaceous Palmar Largo formation.
Areas in the Paleozoic Tarija basin were also included. Ipaguazu and Agua Blanca fields contain reservoirs of Carboniferous and Devonian age. Except for the Agua Blanca and Caimancito areas, the rest of the blocks have acreage for supplementary exploration. An average of $3.02/bbl was paid for the oil reserves.
CUYO BASIN
The areas located in the Cuyo basin had reserves of 3.83 million bbl of oil, the lowest amount put up for bidding.
Originally six areas were offered for bidding, but only four received bids and three of them contained reserves (Fig. 4). The six areas brought a total of $13.755 million.
Production is here recovered from continental sandstones and tuffaceous sandstones of the jurassic Barrancas and Triassic Rio Blanco, Potrerillos, and Las Cabras formations. The oil is sourced in the shales of the Triassic Cacheuta formation and probably in shaly intercalations of the upper part of the Potrerillos formation. In areas with reserves, an average of $3.23/bbl was paid.
NEUQUEN BASIN
All the areas within the Neuquen basin were awarded for a total of $196.1 million. Seventy seven fields with reserves and 17 without reserves were grouped into 40 areas (Fig. 5).
The Neuquen basin is the second most prolific basin in Argentina with production obtained from clastic and carbonate reservoirs of Jurassic, Cretaceous, and Tertiary age. The proven source rocks correspond to the shales of the Jurassic Vaca Muerta formation, the shaly section of the Cretaceous Agrio formation, and the Jurassic Los Molles formation.
The highest exploitation fee paid for an area with a single field corresponded to the Estacion Fernandez Oro (Fig. 5). For remaining reserves of 2.75 million bbl of oil and condensate and 123.55 bcf of gas, a total of $33.6 million was paid.
The field was discovered in 1969 by YPF's 1X Estacion Fernandez Oro well, which flowed 756 b/d of oil from calcareous sandstone levels of the Cretaceous Quintuco formation. In addition, gas and condensate were recovered from jurassic Tordillo formation clastic reservoirs.
A total of 65 wells were drilled with 11 oil and nine gas wells presently producing. Average depth to the reservoir is 7,708 ft; net pay thickness is 56 ft, porosity 12.4%, and permeability 5 md. Water saturation is 47.5%, oil gravity 35.
The Tordillo reservoir is at 8,200 ft; the oil gas contact is at 6,937 ft below sea level, and the oil water contact is at 7,101 ft below sea level. Average water saturation is 36% and condensate gravity is 58.
The 331 sq km Fortin de Piedra area drew an offer of $6.66 million, the highest exploitation fee paid for an area without reserves in the basin.
Only one of the four wells drilled recovered 12,398 bbl of oil and 24.1 MMcf of gas from Quintuco. The reservoir lithology corresponds to limestones with a net pay of 19.7 ft, 10% porosity, and 35% water saturation.
The existence of oil and the location of the area between Aguada Pichana gas field to the west, Aguada del Rodeo gas field to the northwest, La Calera oil and gas field to the north, and giant Loma la Lata gas field to the east, encouraged the successful company to bid for the Fortin de Piedra area. In addition, the area is located within the Vaca Muerta formation maturation zone. Thermal alteration index values range between 3 to 3, and total organic carbon values vary between 3 and 5%.2
The Malargue sub basin has been explored only since 1973. The sub basin is within the fold and thrust belt.
One year later, Puesto Rojas field was discovered. At the time of the bidding, the field had a cumulative production of 22.8 million bbl of 30 gravity oil and 29.44 bcf of gas with reserves of 2.49 million bbl of oil and 20.1 bcf of gas. Four wells produced out of 70 wells drilled.
The reservoir corresponds mainly to carbonates of the Cretaceous Chachao formation. The trap is a north-northeast trending asymmetric anticline, 0.5 to 1 km wide and 10 km long, faulted on both flanks by reverse faults. Towards the southeast, three wells delimited an independent culmination. Value paid was $8.88/bbl of oil.
GULF OF SAN JORGE BASIN
The Gulf of San Jorge is Argentina's most prolific basin. It can be divided into three tectonic sectors: a tensional to the east, a compressional to the west, and near the border with Chile another tensional sector (Fig. 6).
The fields are located within the eastern tensional sector and to the north and south of the basin axis.
Only two out of 24 areas are located in the sector affected by middle Tertiary compressional tectonics. The remaining 22 areas are distributed along the north and south flanks. Only 19 areas received offers for a total of $158.85 million.
The oil sourced in the lacustrine shales of the Cretaceous D 129 formation has vertically migrated along graben faults and is accumulated in stratigraphic and combination traps. The area with largest reserves is Caadon Minerales and received a bid of $50.8 million, the highest exploitation fee paid in three rounds of bids.
Reserves of 8.98 million bbl of oil and 1.16 bcf of gas are contained in continental lenticular sandstones of the Cretaceous Caadon Seco formation (Chubut group) with thicknesses of 19.6 45 ft, porosity 28%, and water saturation 42 47%.
As of December 1989, 438 wells were drilled and 105 were productive.
The Barranca Yankowski area obtained the highest exploitation fee for an area without reserves.
A total of $1.1 million was paid for 418 sq km with five wells drilled. YPF's 1X Barranca Yankowski well recovered 529 Mcfd of gas from sandstone intervals of the Cretaceous Bajo Barreal formation (Chubut group) at a depth of 1,640 2,689 ft.
An average $6.59/bbl of oil was paid for areas with reserves.
AUSTRAL BASIN
During 1949 YPF drilled the 1X TF well as the first commercial discovery in the Austral basin (Tierra del Fuego island), with an initial combined production of 340,000 cu m/d of gas and condensate.
Three years later YPF spudded the 1 Palermo Aike well in the continental Santa Cruz province; oil was also found in the sandstones of the Upper Jurassic Cretaceous Springhill formation. A year later La Sara field, one of the basin's largest, was discovered.
Most fields were found during the 1960s and 1970s. Campo Boleadoras field was discovered in the late 1980s with production from Tertiary sandstones of the Magallanes formation.
The 14 areas located in the basin contain 48 fields with reserves. All the blocks were offered and awarded in the first two rounds of bids (Figs. 7, 8).
A total of $80.013 million was collected for the sale of reserves of 7.89 million bbl of oil and 271.8 bcf of gas. More than 50% of the amount collected corresponded to the Faro Virgenes area.
The $45,054,121 paid for 460, 000 bbl of oil and 25.3 bcf of gas reserves was the highest exploitation fee paid for an area in the Austral basin and the second highest after the $50 million paid for the Caadon Minerales area located in the Gulf of San Jorge basin.
The Faro Virgenes area is located in the southernmost tip of the Santa Cruz province (Fig. 7), where most of the hydrocarbons are recovered with directional wells.
The field was discovered in 1977 and put on production during 1979. As of June 1991, Faro Virgenes field has produced 716,940 bbl of 54 gravity oil and 74.13 bcf of gas from sandstones of the Springhill formation at 1,610 m. The average pay zone thickness is 19.7 ft, and porosity averages 23%. Water saturation is 52%.
Fifteen wells were drilled, and nine are producing.
One of the lowest bids corresponded to the San Cristobal area. A total of $217,410 was paid for 50,400 bbl of oil and 6.35 MMcf of gas reserves. This bid was for exploration possibilities in the Tertiary Lower Magallanes play.
YPF'S CENTRAL FIELDS
During 1990, YPF offered association contracts in four of Argentina's largest oil fields: Vizcacheras (Cuyo basin, Puesto Hernandez (Neuquen basin), and El Tordillo and El Huemul Koluel Kaike (Gulf of San Jorge basin).
All fields in the Cuyo basin are located in two trends known as the eastern and western alignment. However, Vizcacheras field (Fig. 4) is the only hydrocarbon accumulation found in the basin which, separated by a fault, is located to the east of the eastern alignment. Therefore it is postulated that the fault places the field into a sub basin with an independent sedimentary sequence.3
Vizcacheras field covers 67.1 sq km. At yearend 1989 it contained reserves of 57.44 million bbl of oil accumulated in two reservoirs, the Jurassic Barrancas and Tertiary Papagayos formations.
The trap for the Barrancas reservoir is formed by a structural nose; it is limited to the north and east by the water table, while to the west and south the reservoir sandstones are replaced by claystones. Oil was discovered by the 1X Las Juntas well in 1962. At the end of 1989 a total of 128 wells were drilled for the Barrancas formation, 79 of which were producing in 1990.
In the zone where the Barrancas and Papagayos formations are superimposed, 14 wells were drilled.
The oil bearing Barrancas reservoir occupies an area of 37.63 sq km with an average net pay 32.8 ft thick, average porosity 22.6%, and average permeability 485 md.
The oil is 29.1 gravity, viscosity 7.2 cp, and water saturation is 43%. At yearend 1989 Barrancas oil reserves were 19.8 million bbl.
Oil in the Papagayos formation was discovered in July 1963 by YPF's 3X Vizcacheras well. Of the 135 wells drilled for the Papagayos formation, 90 were productive as of December 1989.
The trap for the Papagayos formation is formed by the culmination of the reservoir combined with the sandstones pinchout in the southwesternmost part of the alluvial fan and the additional closure provided by the aquifer located to the east and northeast part of the deposit. The overlying shaly Divisadero Largo formation has a wider distribution; it is the seal rock of the accumulation.
Net pay is 10.13 m thick with average porosity of 26% and permeability of 1,000 md. Water saturation is 23%. An oil gravity of 29 and 6.35 cp viscosity have been reported.
Papagayos reserves were 37.6 million bbl of oil in 1989. Both reservoirs consist of conglomeratic sandstones with a common water table at 1,050 m below sea level, The 90% share of the association brought $97.976 million.
Puesto Hernandez field is the Neuquen basin's largest oil accumulation, covering 87 sq km (Fig. 5).
YPF discovered the field in 1969 with the 1X Puesto Hernandez well, and at the end of June 1991 the field had produced 163.8 million bbl of 34.3 gravity oil; reserves were 84.1 million bbl.
Development drilling showed that the oil is trapped on a gentle monocline dipping south.
The main reservoir, the sandy Avile member of the Agrio formation, is limited downdip by the oil water contact at a depth of 432 m below sea level, rising to the west probably due to hydrodynamic pressure. The updip seal is provided by facies changes and permeability variations of the Avile sandstones.
The Avile member is a calcareous sandstone located at average depths between 2,952 3,936 ft, with an average net pay of 20 m thick, porosity values between 1620%, and permeabilities of 75 150 md. The water saturation averages 37%; oil gravity is 34.3, and viscosity is 3.24 cp.
About 83% of the production is obtained from the Avile sandstone. About 16% comes from the upper section of the Agrio formation and from eight Cretaceous Lower Huitrin formation intervals at 2,460 2,952 ft. Huitrin is made up of a sequence of evaporitic, clastic, and carbonate sediments.
Cretaceous Rayoso formation clastics at 1,968 2,296 ft produce 1% of the oil.
At end June 1991 a total of 535 wells were drilled, with 373 wells producing 38,209 b/d of oil.
The successful bidder paid $260.8 million for a 60% participation.
Two of the largest fields in the Gulf of San Jorge basin were offered by YPF (Fig. 6).
El Tordillo field is on the north flank of the basin, and El Huemul Koluel Kaike field lies on the south flank of the basin. Both should be included in the two clusters of somewhat interrelated fields that could be integrated as two giant oil fields.4
However, the traps in the basin are mainly isolated accumulations with independent water tables; the trapping is due to fault geometry and associated rollovers and flexures, reservoir discontinuity, and an irregular fluid distribution.
El Tordillo field was discovered in 1935 and at the time of the bidding had produced 131.6 million bbl of 23 33 gravity oil; recoverable remaining reserves were 47.9 million bbl. Production of 12,695 b/d was obtained from 376 wells. Since the start of exploitation 848 wells have been drilled.
The field covers 96.84 sq km. The reservoir corresponds to Cretaceous continental sandstones of the Chubut group with a varying net pay of 33 82 ft. Average porosity values range between 18 26%; permeability 75 200 md.
Water saturation (45 50%) and oil viscosity (1.72 25.0 cp) are variable. Depth to reservoir is 4,592 9,840 ft. The oil accumulated in combination traps.
A total of $107.6 million was paid for 90% of the association.
El Huemul Koluel Kaike field, discovered in 1957, covers 17 sq km.
The reservoir consists of sandstones and tuffaceous claystones of the Caadon Seco formation (Chubut group) at about 5,753 ft. Net pay is about 23 ft thick with porosities of 18 27% and permeabilities of 47 485 md. Water saturation is 52%. The oil gravity range is 25 39; viscosity is 1.0 4.2 cp.
At bidding cumulative production was 132.2 million bbl of oil. A total of 1,299 wells were drilled with about 477 wells producing 16,317 b/d.
For 43.7 million bbl of oil reserves, a total of $134.4 million was paid for 80% of the association.
ASSOCIATION CONTRACTS
During 1990, under YPF transformation and privatization program (Decree No. 2778), the company offered for competitive bid an association contract for the exploitation, development, and exploration of about 46,136 sq km of three areas located in the Austral basin.
The basin was divided into three areas that included the exploitation of more than 15 oil and gas fields containing 24% of the oil and 55% of the gas reserves of the basin.
Two areas are in Santa Cruz province and are named Santa Cruz I and II; the third, on Tierra del Fuego island, is known as Tierra del Fuego (Figs. 7, 8).
Terms of the association are similar to those established for the central fields: a 25 year association with an optional extension of 10 years more. Companies are allowed to freely dispose of their production according to their participation. In addition, an exploration program is mandatory.
The Austral basin has a total surface area onshore of 117,000 sq km and contained 198.4 million bbl of oil and 3 tcf of gas reserves as of December 1991.
Since the start of exploration through 1991 some 67,050 line km of seismic lines have been recorded onshore and 2,278 wells have been drilled, 865 of which were wildcats.
The Austral basin is an asymmetric depocenter tectonically framed by the Andean cordillera to the west and south and the Springhill platform to the east. Whereas the western flank of the Springhill platform is a gentle unbroken slope, the eastern edge corresponds to the Dungeness or Rio Chico high, submerged on the shelf and separating Austral from the Malvinas basin.
Sediments in the Austral basin range in age from Upper jurassic to Pliocene with a veneer of Pleistocene glacial till. Total sedimentary thickness exceeds 26,240 ft in the western part.
In the platform zone, the basement is overlain by silicic volcanic and nonmarine volcaniclastic rocks known as the Jurassic Bahia Laura group, Lemaire, or Tobifera formations; they form a complex paleotopography.
Subsidence associated with block fracturing generated the deposition or fluvio deltaic, shoreline, and shallow marine sandstones of the Springhill formation. The uppermost parts of the paleorelief show very limited Springhill thickness or even total absence of sediments (bald highs).
The shales of the Palermo Aike group and equivalents overlie the Springhill sandstones; they form a prograding wedge that onlaps the Dungeness or Rio Chico high to the east and thickens basinward to the west and southwest.
The Palermo Aike group unconformably underlies the clastic Magallanes group, which includes the lower marine Campo Bola formation followed unconformably by the continental Rio Leona formation and capped by the marine Patagonia formation.
The Santa Cruz I area covers 31,247 sq km and contains six fields with total reserves of 11.8 million bbl of oil and 356 bcf of gas.
The largest reserves are in Estancia La Maggie field with 5 million bbl of oil and 10.9 bcf of gas and Campo Boleadoras with 3.95 million bbl of oil and 243.6 bcf.
Estancia La Maggie field was discovered in 1988 by YPF's 1X SC.AELM well; it had an initial production of 977 b/d of oil and 229.5 Mcfd of gas from continental and marine sandstones of the Springhill formation at 5,114 ft. The well was bottomed at 5,425 ft.
The field is bounded by Campo Bola gas field (1 oil well) to the west, Ototel Aike gas/condensate field to the south, and Laguna Los Capones oil gas condensate field to the southeast.
The second wildcat, 2X ELM, flowed 314 Mcfd of gas and 42 b/d of condensate from two intervals at 4,871 ft and 4,910 ft corresponding to quartziferous tuffs of the Bahia Laura group.
The field was developed with two additional wildcats, a confirmation well, four outposts, and one exploitation well.
During 1990 YPF tested a separated anomaly located north of Estancia La Maggie field. The Estancia La Maggie Norte wildcat recovered 315 b/d of oil from the Springhill reservoir.
In 1985 YPF discovered Campo Boleadoras field. The 1X Campo Boleadoras well flowed 1.9 MMcfd of gag from partly conglomeratic sandstones from the Lower Magallanes group; the field became the first commercial discovery from Tertiary sediments. The reservoir at 4,648 ft has porosity values of 32%. The field corresponds to a stratigraphic trap.
The extension well, CBo e-2, had an initial production of 7.85 MMcfd of gas and 69 b/d of condensate, also from the Tertiary Magallanes group. In 1990 YPF's 7XP Campo Boleadoras deeper pool test recovered hydrocarbons from the Springhill formation and thus established additional production.
By yearend 1991 the probable reserves of the field were estimated as 6.96 million bbl of oil and 173 bcf of gas. Nine wells were drilled with one on production.
In 1990 YPF's Puesto Peter well was drilled south of Campo Boleadoras field and flowed 410 b/d of 51 gravity condensate at 5,438 ft; it confirmed the commercial occurrence of hydrocarbons in the lower member of the Magallanes group. In addition oil was recovered from fractured carbonate levels in the interval 9,876 96 ft.
At yearend 1991 Puesto Peter field contained recoverable remaining reserves of 523,000 bbl of OH and 1.06 bcf of gas. Probable reserves were estimated at 3.02 million bbl of oil and 6.1 bcf of gas. Additional possible reserves were also established at 12 million bbl of oil and 31.7 bcf of gas.
A 70% association stake brought $55.011 million.
The Santa Cruz II area has a surface extension of about 14,000 sq km and includes four fields with total reserves of 7.59 million bbl of liquids and additional 1.02 million bbl from five minor accumulations.
The main fields were discovered in the 1960s; presently Chimen Aike field is the largest in remaining reserves. Placed on production during 1974, its reserves totaled 4.57 minion bbl of condensate and 127 bcf of gas as of December 1991.
From a total of 14 wells drilled, only four are presently producing from the Springhill sandstones. Average depth to reservoir is 5,195 ft, net pay thickness 39 ft, porosity 13 28%, water saturation 34%, and condensate gravity 63.
Both fields were discovered in 1962; Condor and Cerro Redondo fields had original recoverable reserves of 44.3 million bbl of oil and condensate and about 1.76 bcf of gas.
Exploitation began during 1966; by June 1991 cumulative production was 36.8 million bbl of oil and condensate and 1.45 tcf of gas with 67 wells producing 2,129 b/d of oil condensate and 129 MMcfd of gas. The fields occupy 227 sq km.
The hydrocarbons are accumulated in structural traps due to reactivation of faults and sealed by a thick shaly sequence.
Condor field extends into Chilean territory; since the beginning of exploitation, YPF and Chile's state owned Empresa Nacional del Petroleo (ENAP) have an agreement for joint determination and rational exploitation of the reserves. The 70% of the association in the Santa Cruz II area was sold for $141.56 million.
The Tierra del Fuego area, covering 889 sq km, is the smallest of three tracts offered for association with YPF.
The area contains five fields with total liquid reserves of 27.5 million bbl and 367 bcf of gas.
La Sara and San Sebastian fields were discovered in 1959 and 1962 respectively; they are two of the largest fields in original recoverable reserves in the region.
La Sara field had original recoverable reserves of 44.86 million bbl of liquids and 30.7 bcf of gas. By June 1991 the cumulative production was 42.4 million bbl of oil and condensate and 28.56 bcf of gas. Reserves were 2.4 million bbl of oil and condensate and 1.84 bcf of gas at December 1991.
The trap is a faulted anticline 8 km long by 2 km wide with an average drilling depth of 6,724 ft.
The reservoir corresponds to Springhill sandstones; net pay thickness varies between 82 295 ft. Porosity averages 20%, permeability 250 md, oil gravity varies between 38 41, and water saturation is 30%.
A total of 65 wells were drilled and during 1991 an average of 14 wells were producing 649 b/d of oil and 395 Mcfd of gas.
San Sebastian field contained original recoverable reserves of 31.5 million bbl of oil and about 1.4 tcf of gas. The hydrocarbons accumulated in a combination trap where, in a fault controlled structure, the Springhill sandstone does not cover the entire area of the structural high (bald high).
The reservoir, mainly at 5,412 ft, has eight pay zones averaging 98 ft in thickness, occasionally reaching 492 ft. Average porosity is 24%, water saturation 40%.
San Sebastian field had remaining reserves of 14.6 million bbl of oil and 784 bcf of gps at yearend 1991; 34 wells out of 81 drilled produced an average of 1,682 b/d of liquids and 159 MMcfd of gas.
Cumulative production was 688 bcf of gas and 12.6 million bbl of oil by July 1991.
Cabo Nombre, Caadon Piedras, and Cabeza de Leon fields have combined remaining reserves of 10.48 million bbl of oil and condensate and 144.7 bcf of gas with a total of 91 wells producing an average of 2,614 b/d of oil and condensate and 28.6 MMcfd of gas.
The successful bidder paid $143.54 million for 70% of the association.
Next: Future exploration potential in exploitation/exploration association contract areas.
MAURITANIA
Mauritania is offering nine offshore blocks in its Coastal basin and three blocks in the Taoudeni land basin under an updated model production sharing contract that includes negotiable terms.
Block sizes range from 5,000 16,000 sq km offshore in the Atlantic Ocean and 20,000 29,000 sq km on land. The blocks straddle the sheer edge and extend to the slope area.
A large deepsea fan is present off Cape Ras el Baida and constitutes an attractive petroleum system, says Mauritania's Direction of Mines & Geology and Beicip Franlab Petroleum Consultants, Rueil Malmaison, France, which is assisting Mauritania with arrangements.
Seismic reprocessing by Spectrum Geophysical Corp. allowed the identification of new prospects in the Cape Timiris area.
Recent exploration off Nouakchott has confirmed the presence of a thick carbonate platform with prominent prospects at accessible depth. Rift series with potential source rocks are clearly identified on the most recent seismic sections, Beicip noted.
This new information confirms similarities of the Mauritania Coastal basin with other basins of this class where oil is being produced, such as Congo, Gabon, and Brazil.
The parties have prepared and updated a comprehensive technical database that includes 11 wells and 33,000 line km of seismic in the Coastal basin, and two wells and 6,000 line km of seismic in the Taoudeni basin.
