In 2013, HRT Petroleum exploration drilled the first-ever deep-water wells in the offshore Walvis (Wingat-1 and Murombe-1 well) and Orange Basins (Moosehead-1 Well; Fig. 1), in Namibia.
WALVIS BASIN (WINGAT-1 and MUROMBE-1 Wells)
The Wingat-1 was drilled first with the main objective of an Albian-age prograding carbonate platform structure and Albo-Aptian turbidite sandstones interpreted to be a seismic amplitude-related prospect having an area of about 381 km2 (Fig. 1). The well was drilled in 1,004 m of water and reached a total depth of 5,000 m MD (Mello et al., 2011, 2012, 2015 and 2022). Unfortunately, the Albian carbonate reservoir presented very low reservoir permo-porosity. The presence of very large anomalies of wet gas at the top of the carbonate reservoir suggested the presence of potential deep hydrocarbon accumulation in the lower Cretaceous section. Going deeper, several thin-bedded, oil-saturated sandstone turbidites reservoirs were found in the Aptian–Barremian section showing porosities ranging from 12–15%, and good permeability. Finding light oil (>41o API), in Namibia, after almost 50 years after the Kudu gas Field discovers, definitively broke the gas paradigm that professed Offshore Namibia to be a gas prone Basin (Mello et al., 2013, 2014, 2015). However, the most important contribution of the Wingat-1 deep-water well was penetrating and sampling, for the first time, an active source rock system in the deep-water realm (the “Aptian–Barremian Kudu Formation; Fig. 2; Mello et al., 2011, 2012, 2015 and 2022).
The Murombe-1 was the second well drilled by HTR in the Walvis Basin. Its drilling was decided based on the presence of a thick well-developed, marine source rock interval, of the Aptian–Barremian Kudu, in the Wingat-1 well located 15 km east of the Murombe prospect (Fig. 1). Located in a water depth of 1,388m, the well reached a total depth of 5,729m MD. The primary target, a Barremian-age basin floor fan system was found to be comprised of non-reservoir facies (primarily volcanic) with low porosity and no hydrocarbon shows. The secondary target Cenomanian-age confined channel complex contained around 40m net sand within a 242m interval (15% N/G) with 19% average porosity. The sands were water wet with no oil/ gas shows Mello et al., 2011, 2012, 2015 and 2022).
ORANGE BASIN (MOOSEHEAD-1 Well)
The Moosehead-1 was the third well drilled, in the Orange Basin, aiming for a gigantic four-way structure, over 1,300km2, of Barremian age. The structure was penetrated on depth, at a water depth of 1,716m, reached a total depth in volcanic rocks at 4,170m MD (8m deeper than prognosis), reaching a 100-meter-thick section of microbiolite carbonate of similar depositional environment and age as the supergiant reservoirs in the Brazil Tupi, Buzios and Mero oil Fields “pre-salt” reservoirs. However, porosity and permeability conditions were poor at the well location and no hydrocarbon shows were present. Again, although no oil/ gas was encountered, the Moosehead-1 deep-water well penetrated over 120m of the Aptian–Barremian K black shale source rock system of the Kudu Formation; Fig. 3; Mello et al., 2011, 2012, 2015 and 2022).
WINGAT-1, MUROMBE-1 AND MOOSHEAD-1 SOURCE ROCK DATA
Figure 2 to 4 show the geological, geochemical and biostratigraphic data results of the upper and lower Cretaceous sections drilled in the Wingat-1, Murombe-1 and Moosehead-1 wells. As can be observed the Albian, Cenomanian–Turonian sections although present TOC some thin intervals up to 3%, they show very low hydrocarbon source potential (S2 < 5mg HC/ g of rock), characterized by hydrogen poor, TypeIII, organic-matter (HI < up to 200mg/g. Hc), deposited in oxic to dysoxic environment of deposition.
Also, the entire upper Albian to Cenomanian to Turonian sections, in the three wells, show rock eval maturity T-max data, with values below 438 o C together with Vitrinite reflectance (%Ro) data up to ~0.6% indicated the entire section to be immature, and therefore, below the oil window stage of thermal evolution to be able to generate commercial hydrocarbon quantities (Mello et al., 2011, 2012, 2015 and 2022).
As can be observed, the upper Cretaceous and the Albian sections recovered in all these deep-water although recovered dark-gray shales presenting high total organic content, their composition shows very low potential yield and hydrogen indices indicating deposition under oxic/ dysoxic conditions. Furthermore, the entire sedimentary sections are below the oil window stage of thermal evolution (e.g., immature). By contrast, the Aptian–Barremian Kudu Formation interval, in both wells, presents high total organic content, with high potential yield and hydrogen indices indicating deposition under anoxic conditions (see discussions below).
By contrast, the Aptian to upper Barremian sediments, from Kudu Formation, recovered in the Wingat-1 wells were found to consist of a thick (e.g., ~140m), marine black shale, containing TOCs ranging from 1%–2% (e.g., 4,625m to 4,4,865m). The hydrocarbon source potential (S2), shows values up to 5mg HC/g of rock), composed by type II, algal, organic matter with hydrogen index (HI), ranging from 200 to 553mg/g. Hc. This data together with, rock eval maturity T-max data, with values above 400oC together with Vitrinite reflectance (%Ro) data ranging from 0.6% to 0,82%, indicated the entire section to be mature, around peak oil generation suggesting the TOC and Rock eval data to be residual, and therefore, the interval is in the oil window stage of thermal evolution and can be considered an active source rock system (Fig. 2; Mello et al., 2011, 2012, 2015 and 2022).
On the other hand, Kudu organic-rich sediments, recovered in the Murombe-1 well were found to consist of also, a very thick (e.g., ~110m), an interval of marine anoxic black shale, containing TOCs ranging from 1.5%–3.5% (e.g., 4,573m to 4,682m). The hydrocarbon source potential (S2), shows values ranging from 15 to 23 mg HC/ g of rock), composed of type II, algal, organic matter with hydrogen index (HI), ranging from 506 to 643 mg/g. Hc. The rock eval maturity low T-max data (up to 435o C), together with Vitrinite reflectance (%Ro) data below 0.6% indicated the entire section to be below the oil window stage of thermal evolution (e.g., immature), but can be considered as very important potential source rock system, if under an adequate thermal maturity condition. (Fig. 2; Mello et al., 2011, 2012, 2015 and 2022).
Figure 3 shows the geological, geochemical and biostratigraphic data results of the upper and lower Cretaceous sections drilled in the Moosehead-1 well, Orange Basin, distant more than 300 km from the Wingat-1, Murombe-1 wells.
As can be observed the Albian, Cenomanian–Turonian sections, occurred sallower than in the Walvis wells (e.g., < 3,500 m). On the other hand, the Aptian to Barremian Kudu source rock interval, from the Moosehead-1 well, show a very rich, organic-rich, ~ 133m thick, black shale (e.g., 4,400m to 3, 533m), with excellent hydrocarbon source potential, composed of hydrogen rich algal organic matter. Vey important to mention that the entire section occurred below the oil window stage of thermal evolution (e.g., immature). Such data proved such system to be considered and overcharged, very important potential source rock system, if submitted under an adequate thermal maturity condition. (Fig. 3; Mello et al., 2011, 2012, 2015 and 2022).
Comparison of figures 1–3, shows that although separated for more than 300 km (e.g., distance from the Murombe-1 well in Walvis from Moosehead-1 well in the Orange Basin), the Aptian to Barremian Kudu source rock interval, from the Moosehead-1 well, was found to bear similar interval of a very rich, marine anoxic organic-rich, black shale (e.g., ~133m; Figs 1–3; Mello et al., 2011, 2012, 2015 and 2022). The interval contains TOCs ranging from 1.5%–5,4% (e.g., 4,400m to 3, 533m). The hydrocarbon source potential (S2), shows values up to 60mg HC/ g of rock), composed by type II, algal, organic matter with hydrogen index (HI), over up to 800 mg/g. Hc (Fig. 3). The rock eval maturity data however, presented very low T-max (up to 435o C), Vitrinite reflectance data (below 0.6 %Ro) % indicating the entire section to be below the oil window stage of thermal evolution (e.g., immature). Such data proved such system to be considered and overcharged, a very important potential source rock system if submitted under an adequate thermal maturity condition. (Fig. 3; Mello et al., 2011, 2012, 2015 and 2022).
Figure 4 illustrates the correlation of the total organic carbon (TOC), versus the potential yield (S2) and hydrogen index data among the Wingat-1, Murombe-1 and Moosehead-1 wells. As can be noted, the plot shows, very clearly, the residual character (e.g., a transformation of the original hydrocarbon source potential to hydrocarbons), of the source rocks from the Wingat-1 well, when compared to the original immature organic matter from the Murombe-1 and Moosehead-1 well. Also, the data suggested that the Kudu organic-rich facies became richer and with the best quality in the direction to the Orange Basin (Mello et al., 2022).
The Wingat-1, Murombe-1 and Mooshead-1 deep-water source rock data, offshore Namibia suggest that the Walvis, Lüderitz, and Orange Basins share almost identical overcharged, oil-prone source rock system, represented by the Aptian to Barremian Kudu Formation. The data indicate that the Kudu organic-rich facies were deposited in a marine anoxic, restricted environment of deposition, where hydrogen-rich kerogen, type II/I algal communities were developed in very high proportions. The presence of such euxinic organic-facies widespread for hundreds of kilometers, from Walvis to Lüderitz up to Orange Basin, for the entire deep to the ultra-deep offshore realm, suggests the presence of a supergiant hydrocarbon source potential for the entire Aptian to Barremian, supergiant petroleum system in the area.
We have predicted a supergiant oil-prone Basin in Namibia, since 2010, and our publications in 2011, 2012, 2015 and several others, confirmed the early data about the supercharged Kudu source rock system. The recent giant and supergiant discoveries of Venus, Graff, La Rona and this week of Jonker is just the point of a gigantic iceberg that will transform Namibia into one of the largest oil province in west Africa.
Mello, M.R., N.C. Azambuja Filho, W.U. Mohriak, A.J. Catto, and J.B. Francolin, 2011, Promising Giant New Hydrocarbon Frontier in Namibia Continental Margin: GeoExPro, 8, 64–69.
Mello, M.R., N.C. Azambuja Filho, A.A. Bender, S.M. Barbanti, W.U. Mohriak, P. Schmitt, and C.L.C. Jesus, 2012, The Namibian and Brazilian southern South Atlantic petroleum systems: are they comparable analogues? in W.U. Mohriak, A. Danforth, P.J. Post, D.E. Brown, G.C. Tari, M. Nemcok, and S.T. Sinha, eds., Conjugate Divergent Margins: Geological Society, London, Special Publications, 369, 249–266. First published online March 7, 2013, http://dx.doi.org/ 10.1144/SP369.18.
M.R. Mello, Mohriak, W.U., and W. Peres, 2015, Namibia: The Hunt for Oil and Gas Continues in the Land of Giants: 32nd Annual GCSSEPM Foundation Bob F. Perkins Research Conference, 919–963.
Mello, M.R., 2022. “Offshore Namibia: The sleeping giant deep-water hydrocarbon frontier has awakened”. Poster, IMAGES, 2022-International Meeting for Applied Geoscience & Energy, Houston, August 20–30, Control ID:3745488.