Tanzania wildcats to evaluate Jurassic Mandawa salt basin

Mamdouh Nagati
Tanganyika Oil Co.
Dubai

After 5 years of stagnant exploration in East Africa, Canadian independent Tanganyika Oil Co. of Vancouver, B.C., will drill two wildcats in Tanzania to evaluate the hydrocarbon potential of the coastal Jurassic Mandawa salt basin.

Mita-1, spudded around Oct. 1, will be drilled to about 7,000 ft. East Lika-1 will be drilled in early December 1996 to approximately 6,000 ft. The two wells will test different structures and play concepts.

The Mandawa block covers an Early Jurassic rift basin 50-70 km wide between the outcropping Masasi basement high to the west and the Coastal basement ridge to the east (Fig. 1 [105950 bytes]). The basin is defined to the south by the shallow basement Ruvuma uplift and is believed to extend northward into the unexplored hilly Rufiji block.

Three deep wells have been drilled in the 2.5 million acre Mandawa Block. Two of them penetrated thick sections of synrift euxinic, lagoonal, marginal and restricted marine shales, and salt.

Exploration history

BP obtained concession rights between 1952-64 over most of the coastal areas of Tanganyika and Zanzibar (Tanzania today). During this period the Mandawa area was covered by less than 500 gravity stations along accessible roads and tracks.

BP started testing surface features by shallow drilling in 1954. The first two holes were adjacent to the well known Wingayongo tar outcrop. Wingayongo-2 penetrated 150 ft of Early Cretaceous tar impregnated sandstone and flowed some gas for 41/2 months.

BP drilled six holes in 1956 on the 19 km long Mandawa salt cored anticline. The wells ranged in depth from 464 ft to 2,523 ft, and all bottomed in Early Jurassic salt.

BP drilled Pindiro-1 to 3,024 ft in 1957 to test another salt cored surface anticline. The well, however, failed to penetrate the pre-salt but flowed wet gas from an intrasalt thin shale bed. A number of additional shallow stratigraphic holes were then drilled in the same area, but all failed to reach top salt.

BP drilled the first deep well in the basin, Mandawa-7, to 13,336 ft in 1958. The well penetrated the pre-salt for the first time and bottomed in the Upper Mbuo formation before reaching any reservoir rocks.

Between 1971-82 Agip held most of the Mandawa area and acquired 953 km of six fold geoflex seismic. In 1975-76 Agip added 735 km of 12 fold vibroseis seismic, but data were only poor to partly fair quality.

Agip in 1979 drilled Kizimbani-1 to basement at 8,848 ft on a young (Late Tertiary) structure. Both the Early Jurassic salt and the underlying Mbuo formation were missing in the well. Seismic Shell acquired later demonstrates both sections to be present downdip to the west.

Between 1986-90, Shell held most of the Mandawa Block under PSA. In 1987-88, Shell acquired 1,685 km of 48 fold dynamite seismic and obtained 6,433 gravity readings along the seismic lines.

Shell then drilled Mbuo-1 to basement at 10,870 ft in February 1990. The well was located on the same salt anticline that was tested by BP's Pindiro-1.

Mbuo-1, which is the only well that penetrated the entire stratigraphic section, encountered 1,000 ft of nearshore and deltaic sandstone reservoir beds intercalated with organic rich black shales above the basement.

Shell, concerned about possible sandstone pinchout onto a basement high, drilled the well significantly downdip. Subsequent seismic reprocessing and inversion by Tanganyika Oil indicates reservoir continuity over the basement high and demonstrates that Mbuo-1 was indeed drilled outside closure (Fig. 2 [96834 bytes]).

Tanganyika Oil signed a PSA in July 1995 covering 3.37 million acres in Mandawa and Rufiji blocks. The PSA allowed for an 18 month study period after which Tanganyika Oil might opt to drill one well in each block. The company immediately commenced seismic reprocessing and covered two areas totaling 800 sq. km on the western margin of the Mandawa Block with 682 gravity stations to infill seismic gaps.

Source rock potential

Pyrolysis-sniff, organic-carbon determination, and microscopic analysis of a large number of shale cores available in Mandawa-7 and one core and 52 sidewall cores in Mbuo-1 reveal the presence of good to excellent Type I, II/III source rocks for oil and gas in the intrasalt shale beds and the lowermost pre-salt Mbuo formation.

TOC of up to 8.4% and hydrocarbon-generation potential of up to 88 kg/ton of rock (HI 997) were recorded in Mbuo-1 (Fig. 3 [34947 bytes]). The organic content in the two wells is composed predominantly of laminated loadbearing and partly-loadbearing SOM probably of algal origin, liptodetrinite and other type algae. A scattered occurrence of landplant matter, like telinite, detrital desmocollinite, sporinite, and semi-fusinite has been observed as well.

Based on electric log character (high uranium content, high resistivity, low transit time, and low density) calibrated by core and sidewall core samples, more than 400 ft of gross proven and potential oil and gas source shale section were identified in Mbuo-1.

Vitrinite reflectance values measured in the three deep wells and three of the shallow stratigraphic holes indicates a variety of maturity levels ranging from immature to post-mature for oil.

The pyrolysis-sniff values before extraction are generally higher than after extraction. This is indicative of the presence of migrated hydrocarbons.

Present day geothermal gradient from well data ranges between 1.8° and 2.3° C./100 m.

Hydrocarbon shows

Bright golden yellow/ white fluorescence, light cut and dull solvent fluorescence were reported in claystone and sandstone cutting and sidewall core samples in Mbuo-1. The highest chromatography reading of C1 1008, C2 910, C3 30, iC4 33, and nC4 26 ppm was recorded near top of the basal sandstone section at 9,872 ft. The well was not tested.

Potential reservoir

Reservoir was recognized by previous operators as the main exploration risk in the Mandawa basin. With only two wells penetrating the pre-salt, it is unreliable to assess risk at this stage. Erratic synrift sand distribution is normally expected, but a rift basin that totally lacks sandstone reservoirs will be a unique case.

Like most of the East African Archaean/Proterozoic shield, today's Masasi basement high was covered by massive continental pre-Triassic Karroo sandstone. Remnants of Karroo are still preserved on the metamorphic Masasi basement near the Mozambique border, and more than 5,000 m of Karroo is known to exist to the west in the Selous basin.

Paleo rivers and distributary system running from west to east following more or less today's courses could have transported reworked Karroo sands from the Masasi high to the Mandawa/Rufiji basin.

The prospects

With lack of well control and limited seismic resolution to identify sand reservoirs, one of the two prospects selected for drilling will be located as close as possible to the basement outcrop to ensure penetrating sand rich pre-salt Early Jurassic section. The East Lika-1 prospect is a 30 sq km (7,400 acre) horst block (Fig. 5 [45002 bytes]) with 2,850 acres of four way dip closure and 500 ft of structural relief on basement level. The prospect is adjacent to a major mature kitchen area to the east.

To the west, the Masasi basement outcrop is bound by a well defined 6,000-8,000 ft fault down throwing to the east with no significant surface expression.

The second prospect; Mita-1, is a 125 sq km (31,000 acre) area with over 1,500 ft of structural relief on basement level and several four way dip closures on shallower levels (Fig. 6 [32417 bytes]). Shell recognized the prospect earlier and detailed it by seismic in 1988. It is adjacent to and surrounded by three large mature kitchen areas.

The Author