Agbor, Fritz Ako (University of Western Cape) | Mhlambi, Sanelisiwe (University of Western Cape) | Teumahji, Nimuno Achu (Schlumberger Limited) | Sonibare, Wasiu Adedayo (Schlumberger Limited) | Van Bever Donker, Johannes Marinus (University of Western Cape) | Chatterjee, Tapas Kumar (University of Western Cape)
Despite the undergoing exploration and research for hydrocarbons during the recent decades, the hydrocarbon potentials of existing source rock(s) in the Pletmos basin still remain enigmatic. The basin has undergone rifting and transforms processes during its evolution in a manner that its present-day architecture and geodynamic evolution can only be better understood through the application of a multidisciplinary and multi-scale geo-modelling procedure.
In the study, thermal modelling and reconstruction of burial history of the source rocks in the southern depocenter of the Pletmos Basin has been investigated through an integration of data and methods.
Through geohistory Modelling, an integration of the acquired multidisciplinary dataset allowed us to reconstruct the burial history, basement subsidence, vertical fluid flow, and the changes in rock properties (i.e. porosity, permeability, pressure and fluid flow rate) both in time and depth, as well as established a reliable tectonostratigraphic framework of the Mesozoic sedimentary infill. Then based on the reconstructed burial history, thermal history was reconstructed by modifying the paleoheat flux to minimize variances, and comparing between measured borehole and predicted vitrinite reflectance and Tmax (thermal indicator) values. These enable us to achieve an improved understanding of the subsurface controlling processes that might have led to the sedimentary infill and resulted to the heat-flow distribution and present-day thermal maturity of the source rocks in the Basin. The approach gives us the opportunity to considered the geodynamic evolution events from Mesozoic (Upper Jurassic) rifting to Cenozoic (including major uplifts, erosion and subsidence, and the Shona Buvet hot spots). Here we present some selected results, from the burial and thermal history modelling reconstructions of the sedimentary geothermal evolution and thermal maturity levels of the source rocks at selected well locations within the area. Likewise, this study has provided supplementary information that aids towards understanding the Petroleum System(s) of the Basin.
The area evaluated has similar structural styles and settings as the producing neighboring fields of F-A and E-M in the adjacent Bredasdorp basin Offshore South Africa. The main objective of this study is to create a 3-D-static model and estimate hydrocarbon reserves. Based on log signatures, petrophysical properties and structural configurations, the reservoirs were divided vertically into three reservoir units in order to be properly modelled in 3-D space. The thicknesses of the layers were determined based on the vertical heterogeneity in the reservoir properties. Facies interpretation was performed based on log signatures, core description and previous geological studies. The volume of clay and porosity was used to classify facies into five units of sand, shaly sand, silt, and clay. From petrophysical interpretation, a synthetic permeability log was generated in the wells which ties closely with core data. The J-function water saturation model was adopted because it produced better results in the clean sandstone sections of the reservoirs. A high uncertainty in the basement formation was observed due to very few wells drilled in the area and fault impact and thus resulted in evaluation of uncertainty of each zone separately. The uncertainty workflow was run using 100 trials and the base case P50 estimated 277 Bcf of Gas from the 1At1.
Pletmos basin is one of five sub-basins of the Outeniqua basin, of which the later, is the largest basin in South Africa. Pletmos is located in the South African continental shelf between Cape St. Francis and Mossel Bay. The Basin is positioned offshore south of South Africa, southwest of Port Elizabeth and southeast of Cape Town and covers about 18000 km2. Strong strike-slip movement from the Late-Jurassic up to Early Cretaceous is evident in the Basin and also shows a history of the split up of Gondwana (Roux, 2010). It is made up of two overlapping depocenters, namely, the Plettenberg Graben and the Superior Graben which are separated by a 4000m high prominent transfer arch (PASA, 2010). The transfer arch is the central point for high energy sand channels crossing between adjacent basins. The transfer arch is the central point for high energy sand channels crossing between adjacent basins. Pletmos Basin underwent rifting during the Middle-Late Jurassic. Brown et al. (1996) noted that the resulting dextral trans- tensional stress exerted north of the Agulhas-Falkland Fracture Zone initiated normal faulting along the northwest to southeast striking Plettenberg and Superior grabens. The Outeniqua Basin has been largely described according to its major regional unconformities (Broad et al., 2006).
This paper will focus on the vast deepwater areas of offshore South Africa; areas which require a challenging and expensive exploration effort. Latest exploration activities of Offshore South Africa, combined with a bit of exploration history will be discussed. This would then be compared with worldwide trends concerning deepwater exploration. Africa's important role within this new drive to exploit the world's deepwater hydrocarbon resources is also emphasized. General geology of the offshore basins will briefly be summarized, and the talk will coclude with the latest resource estimates of South Africa's deepwater areas.
During the past 30 years, exploration of the Mesozoic basins of offshore South Africa was generally restricted landwards of the 200m isobath, with only a few wells exploring the Orange Basin on the West Coast in water depths deeper than 400m. Off the South Coast these rigs could only manage in water depths of up to 300m maximum. The strong Agulhas current and adverse weather conditions imposed restrictions on the use of the existing semisubmersibles.
The first offshore well in 1968 discovered the Superior gas field in the Pletmos Basin, which is a sub-basin of the Outeniqua Basin off the South Coast. Subsequently, most of the offshore exploration was then focussed in the Bredasdorp Basin, which led to production of the F-A, EM and satellite gas fields in 1992, which have been feeding the synfuel plant at Mossel Bay. First oil production from the Oribi oilfield followed in May 1997, a deep marine basin floor channel and fan complex (bff complex), and production was increased when the Sable oil, gas and condensate field came onstream in mid-2003.
The Orange Basin is defined by the extent of a sedimentary wedge that occupies about 150 000 km2 off the southwestern coast of Africa, and is more than 8 km thick in places. Although the basin is sparsely drilled with only 40 wells, most of which tested the shallow water areas, results thus far have been extremely encouraging. Two gas fields (Ibhubesi in South Africa, and Kudu in Namibia) with multi-TCF potential have been discovered within the younger geology, while the A-J1 well yielded an oil discovery in some of the oldest sedimentary fill.
The Ibhubesi gas field has recently been defined by Forest Exploration International, through appraisal drilling in the area of the original A-K1 discovery well. The tested wells in this field yielded a high combined flow rate of dry gas and condensate. Analysis of 2D and 3D seismic surveys in the area has defined many new prospects and justifies the extension of this play for some distance to the north.
The Durban Basin remains under-explored with only 4 wells testing the offshore areas close to shore, all of which were non-commercial.
Studies of oil discoveries made during the nineties indicate that giant oil discoveries are more frequently found in the deepwater areas of the world compared with the shallower water regions.
The application of sequence stratigraphic concepts has led to both successes and failures in petroleum exploration. A broad spectrum of reservoir occurrences are predicted in siliciclastic sequence stratigraphic models. The most successful applications have been in turbidite systems (lowstand systems tract) and incised valley-fills (lowstand and transgressive systems tracts). We analyze one example from each of these depositional settings which helps point out the successes and limitations of sequence stratigraphy in exploration of both frontier and mature basins.
The first example is from the Lower Cretaceous turbidite systems of the Bredasdorp and Pletmos basins of offshore South Africa. Exploration in these basins by Soekor (Ltd.) Pty demonstrates the frontier exploration applications of sequence stratigraphy. Basin-floor fans and basin-floor channel fill targets had 30% (14 wells) success ratio, whereas slope fan and prograding complexes had only one success. Drilling in the adjacent Pletmos basin had no success in five wells that targeted lowstand turbidite systems.
The Pennsylvanian Morrow Formation of eastern Colorado is the second example analyzed and demonstrates the application of sequence stratigraphic concepts in a mature basin. This is an incised valley-fill play that produces from several different valley-fill systems. Of the 181 wells drilled along a single valley-fill trend, 41.4% of the wells penetrated the valley (75 wells), 19.3% of the wells found reservoir quality sandstone (35 wells), and 9 new fields were discovered (5% rate of success). Since 1985, when the play was interpreted as an incised valley-fill, drilling statistics indicate that there was no significant increase in the success rate of discoveries, even though a greater percentage of wells penetrated valley-fill facies. This case study indicates that the major problems in valley-fill exploration were 1) locating the valley, 2) locating reservoir sandstone within the valley, and 3) finding a trap for the reservoir.
These drilling results indicate that sequence stratigraphy helps in exploration by defining play boundaries and prospects. However, they also suggest that the application of sequence stratigraphic concepts may not directly result in an increase in the rate of success of individual prospects. Sequence stratigraphic analysis only addresses the reservoir, source, and seal components of the petroleum system. Trapping mechanisms still remain a significant source of risk.