1. Onshore - CBM, Shale gas Offshore – conventional oil and gas
18 companies and their subsidiaries
about 40 ERs
3 TCPs
about 100 applications
Offshore:
8 international and 2 local companies active in 21 concessions with 7 areas under application
Onshore - CBM, Shale gas Offshore – conventional oil and gas
PETROLEUM EXPLORATION AND PRODUCTION ACTIVITIES IN SOUTH AFRICA

2. Western Bredasdorp Basin
OPEN
ACREAGE
This open acreage covers the western extent of the mature Bredasdorp Basin
with producing oil, condensate and gas fields of Sable and Oribi/Oryx
located only 25 to 30 km to the east of the eastern boundary of this open acreage.
Only a third of the total area available for licensing ( km²) is considered prospective.
The unprospective part is a shallow basement high, the Agulhas Arch,
which consists of Table Mountain quartzitic sandstones and shales of the Bokkeveld Group,
covered by a very thin overburden of drift shelf sediments.
Jacques Roux September 2010

3. Outline Historic and geological overview
Structural evolution of open acreage
Prospects in the Southern Sub-basin
Summary of prospectivity
A summary of my presentation will kick off with a quick historic and geological overview of the area.
A schematic structural evolution will give you a break-down of geological events and stratigraphic units.
We will browse through depocentres of the Synrift II, Early Drift and Drift phases.
I will discuss selected 8 prospects.
And we will conclude with a summary of prospectivity of Western Bredasdorp Basin

4. Historic and geological overview

5. Western Bredasdorp Basin exploration opportunities
The area, previously known as Block 7, constitutes the Arniston Half-graben in the north, and the Southern Sub-basin in the south, separated by a basement high, called the Central High.
The D-A1 well drilled by Soekor in 1973 was also the first offshore well completed within the Western Bredasdorp Basin, and the second in the Bredasdorp Basin as a whole.
Subsequently three more wells were drilled up to 1987.
Three of these wells, excluding the D-C1 well, intersected fair to good quality oil to wet-gas prone source sequences, and these two wells in the Southern Sub-basin had oil shows.
Pioneer Natural Resources acquired a sub-lease for Block 7 in November 1998, and relinquished the same area in November 2002, without adding more seismic coverage to the area, which totals to km of migrated 2D data, nor did they drill a well. Their well commitment for Block 7 was transferred to Block 9 in order to speed up production within this producing area.
The Agency has reinterpreted the area and delineated several untested prospects, especially within the Southern Sub-basin. Pioneer had their focus on the Arniston half-graben in the north, and especially the Rinkhals prospects (P6), and neglected the Southern Sub-basin.
This presentation will clearly demonstrate why the Southern sub-basin is rather considered more prospective. I will briefly introduce you to eight of these prospects as highlighted with yellow stars. I will start off with Prospect P6, encircled in yellow, and the only prospect in the Arniston Half-graben discussed in my presentation. Prospect P6 was also the main reason why Pioneer was initially reluctant to relinquish this lease-area, before focusing all their exploration efforts in the adjacent Block 9.

6. Mass-flow Hauterivian structure overlying 5At1
Stratigraphic pinch-out against Central High
P50 estimate of STOIIP = 129 Mmbbl
Volumetrics based on closing contour within open acreage
PROSPECT P6: RINKHALS LEAD
Pioneer named the P6 prospect the Rinkhals Lead. This Hauterivian aged mass-flow feature is stretched over a vast area into Block 9, but its updip stratigraphic pinch-out lies within the open acreage where it is straddled against the Central High and dipping off towards the east.
The P50 estimate is calculated to be 129 MMbbl of oil in place, also supported by an AVO anomaly as highlighted below. The volumetrics are based on rock volumes derived from a closing contour which falls entirely within Western Bredasdorp Basin, as outlined by a dotted red line.

7. Structural evolution of open acreage

8. Schematic illustration of the structural evolution
of the Western Bredasdorp Basin
I Mid-Jurassic to Valanginian: SYNRIFT I PHASE
II Late Valanginian to Hauterivian: SYNRIFT II PHASE
III. Hauterivian to Aptian: TRANSITIONAL (EARLY DRIFT) PHASE
IV. Albian to Maastrichtian: DRIFT PHASE
V Paleocene to Present Day: UPPER DRIFT PHASE
The structural evolution of the Western Bredasdorp Basin has been simplified into 5 phases.
Firstly, the Synrift I phase, which marks a period between Mid-Jurassic to Valanginian. A major thick developed within the Arniston half-graben. The Southern Sub-basin only started to develop during the 1At1 unconformity, which is regarded as marking the onset of transform movement on the AFFZ and the onset of a renewed phase of rifting. Sediments consist of fluvials deposits capped by transitional sandstones towards the top. Kimmeridgian lacustrine source rocks may be present. Reservoirs are expected to be tight.
The Synrift II phase marks a rapid deepening of depositional environment. This package consists of deep water shales, and fair to good quality wet-gas to oil-prone Hauterivain age source rocks as well as reservoir rocks were intersected in both depocentres.
The Early Drift phase ranging from Hauterivian to Aptian, consists of repeated episodes of progradation and aggradation, and a generally southeastwards extension of the shelf. Slope and basin floor fans were deposited within both depocentres, the Arniston Half-graben in the north becoming less significant with time. Fair quality wet-gas source rocks are developed over the eastern extent of the open acreage, and improves in quality and thickness within Block 9. The 13Amfs marks the most important source sequence of Central Bredasdorp Basin, not developed in this proximal location.
The fourth stage is a continuation of Drift ranging from Albian to Maastrichtian, and comprises outershelf deposits.
The Upper Drift stage from Upper Cretaceous to Present Day is a period marked by three important geological events.
Firstly, the oil-prone and wet-gas prone source sequences within the Synrift II depocentres have entered the main stage of oil generation.
Then Early Tertiary alkaline intrusion activity affected the Central High.
Late tilting of the Bredasdorp basin combined with a late uplift of the northern flank result and a total removal of the Tertiary succession over this area. Erosion of up to 600 m seems evident over the Arniston Half-graben area, and far less erosion (not more than 250 m) over the Southern Sub-basin.

9. (Late-Valanginian to Early-Hauterivian succession)
Lower part of Synrift II isopach
5At1 truncates 1At1
Pinch-out of 5At1-to-6At1 sequence against 1At1
(Late-Valanginian to Early-Hauterivian succession)
The Arniston Half-graben experienced further deepening with slope deposits comprising interbedded sandstone and claystone as intersected in the D-B1 well. The Southern Sub-basin seems less developed, but several bright seismic anomalies suggest possible basin floor fan development.
Upper part of Synrift II is an interval with several bright seismic anomalies noticeable within the Southern Sub-basin.
These anomalies or bright spots suggest possible hydrocarbon accumulations within bff and channel complexes.

10. (Hauterivian succession)
Upper part of Synrift II isopach
The Arniston Half-graben as well as the Southern Sub-basin indicate major thickening resulting from subsidence of these depocentres during this Synrift II stage, which favoured the deposition of Hauterivian age oil-prone source rocks as intersected in the Arniston Half-graben.
5At1 truncates 1At1
(Hauterivian succession)
The next four slides illustrate the depocentres of the Synrift II, Early Drift and Drift phases.
It also gives an illustration of the locality of source rocks
and areas of possible bff development.
Lower part of Synrift II clearly indicates the increased development of the Southern Sub-basin,
and the depocentres of both sub-basins are expected to contain best quality oil-prone source rocks.

11. Early drift isochron (Late Hauterivian-to-Mid Aptian succession)
Proven oil to wet-gas prone source rocks and basin floor fan development in the Southern Sub-basin as was the case in producing Central Bredasdorp Basin.
(Late Hauterivian-to-Mid Aptian succession)
Base of slope
Shelf-edge
The Early Drift succession demonstrates a continued deepening of the Southern Sub-basin,
connecting it directly with the subsiding Central Bredasdorp Basin.

12. Prospects in Southern Sub-basin

13. Prospect P3: Updip potential at Mid Hauterivian level
Prospects P3, P9 and P10
illustrates the updip potential of the D-A1 well at different stratigraphic levels within the D-A1 High,
the area enclosed in the yellow circle, but also affected by intrusion activity.
Light blue circles mark areas affected by intrusion activity.
Note that this band of intrusion activity stretches from the Central high towards the D-A1 High and further southwards.

14. Updip potential of D-A1 well
The D-A1 well intersected this domal closure down-dip on the flank of the structure.
The D-A1 well was TD’ed within an alkaline intrusive sill.
Updip untested closure can be demonstrated at different targets,
each identified as good reservoir rocks, with fluorescence and cut.

15. Prospect P3: Updip potential at Mid Hauterivian level
Assumptions:
10% porosity,
15m ave net pay,
70% oil saturation
75% formation factor
Upside potential (STOIIP)
= 88 MMbbl
Depth map of Prospect P3
the depth map of Prospect P3 is the mid Hauterivian unconformity 5At1.
It illustrates an updip upside potential of up to 88 MMbbls of oil in place,
derived from an domal closure of 19 km²,
and a Most Likely estimate of 29 MMbbls.

16. Prospect P17: Hauterivian bff in Southern Sub-basin
Prospect P17 forms part of a Hauterivian age basin floor fan complex ,
and is perched on the northern flank of the Southern Sub-basin.
We will also look at a N-S line E-E’ which is located over the crest of the structure.

17. Prospect P17: Depth map to top of 5A basin floor fan
Area of bright seismic anomaly
covers 9.1 km²
Assumptions:
20% porosity
30m ave net pay
70% oil saturation
Most likely estimate STOIIP
= 62 MMbbl E E’
P17 is a Synrift II stratigraphic pinch-out with a domal component.
It is a structural high within a channel/fan complex,
and is delineated as an area of bright seismic anomaly covering 9.1 km².
A Most likely estimate of 62 MMbbl of oil in place was calculated.

18. Prospect P17: Hauterivian basin floor fan
Top of Prospect P17
Top synrift
5At1
6At1
13At1
Basement E
N-S seismic profile through P17
Normal faults flanking the Southern Sub-basin
ensure direct migration from the source kitchen, the oil-prone Hauterivian source within the Southern Sub-basin to the left on our seismic profile.
Added charge is expected from shallower wet-gas to oil-prone successions intersected within Block 9 directly adjacent to the Central High.

19. Prospects P11 & P12: Hauterivian fans within the Southern Sub-basinK K’

20. Prospects P11 and P20: Basin floor fans within the Southern Sub-basinK
Prospect P11
Prospect P20
6At1
5At1
Top synrift
Basement
Assumptions:
20% porosity,
30m ave net pay,
70% oil saturation
0.75 formation factor Areal closure of trap …= 16.9 km² (P11)
…= 4.9 km² (P20)
Most likely estimate P11:
112 MMbbl in place
Most likely estimate P20:
31 MMbbl in place K’
P11 and P20 are fans deposited at base of slope where they are expected to be effectively sealed within abyssal shales. No intrusion activity seems evident within this part of the Southern Sub-basin.

21. Source rocks and potential migration routes within the Southern Sub-basin
Hauterivian oil-prone source F’ F
Migration route
Sea floor
15At1
13At1
13Amfs
Prospect P11
Projected Prospect 4
6At1
Top synrift
Basement
5At1
The N-S dipline illustrates source rocks and potential migration routes within the Southern Sub-basin. The oil-prone Hauterivian source is the main charge for these reservoirs, and normal faults flanking the sub-basin ensure short migration routes directly into the traps.
Shallower marginal marine sandstones are also expected to be connected to these mature source rocks via the northerly bounding faults to the depocentre. Expulsion of hydrocarbons is expected to have occurred throughout the Tertiary.
The locality of Prospect P4 is highlighted in yellow.

22. Prospect P4: Barremian age closureJ’ J
P4 is a domal Barremian age closure consists of marginal marine sandstones on the northern flank of the Southern Sub-basin. These domally trapped inner shelf sandstones are equivalent to the good quality inner shelf sandstones intersected within the D-A1 well.

23. Prospect P4: Depth map to top of Barremian targetJ’
Top of target onlaps exposed Synrift I red and green claystones
Domal closure =11.9 km²
Assumptions:
20% porosity,
15m ave net pay,
70% oil saturation
0.8 formation factor
Domal closure = km²
Upside estimate of domal trap:
= 124 MMbbl in place
Most likely estimate = 41 MMbbl STOIIP
This very shallow target with spill point calculated at 1185 mbmsl, relies on the sealing capacity of overlying middle shelf claystones. Most likely estimate is calculated at 41 MMbbl of oil in place. J

24. Prospect P4: Seismic profile illustrating domal trap and charge
This seismic profile, dipline J’J’, illustrates the domal closure and charge from the depocentre of the Sub-basin.
A bright seismic reflector marks the top of the target, and the impedance contrast appears to be related to lithological changes. The prospect is not affected by intrusion activity and seal integrity is inferred to be low.
The seismic anomaly appears to intensify over the structural high as well as updip where it onlaps a tight Synrift I succession. The latter may suggest an additional stratigraphic accumulation.

25. Prospect P4: Aptian prospects
Prospects P18 and P19 are Aptian prospects at a very shallow stratigraphic level, potentially charge by drift source rocks within the Block 9.

26. Prospects P18 and P19: TWT map to top of target
Assumptions:
20% porosity,
30m ave net pay,
70% oil saturation
0.75 formation factor Areal closure of trap …= 11.7 km² (P18)
…= 7.7 km² (P19)
Most likely estimate P18:
77 MMbbl in place
Most likely estimate P19:
51 MMbbl in place
Block 9
Open acreage
Prospect P18
Prospect P19
P18 and P19 comprise stratigraphically trapped inner shelf sandstones, equivalent to the good quality, blocky shelf sandstones (Aptian) intersected within the D-D1 well.
These shallow targets with burial depth just under a 1000 metres, may be interpreted as a barrier bar parallel to the palaeo-coastline, or could also be interpreted as a shelf-edge channel leading off the shelf to a slope environment.
The next side will illustrate profile N-N’ through Prospect P18, and note the proximal location of the D-D1 well three km to the east.

27. Transitional interbeds comprising red Clsts, Sltsts and Ssts
Prospect P18: Seismic profile illustrating Aptian channel feature N N’
Channel sandstones reflects a soft seismic signal
13Amfs
13At1
Φ= 25%, good permeability assured by secondary Φ; 36m Nett Ssts
Inner shelf Ssts,
minor Clsts
Aptian unconformity
Transitional interbeds comprising red Clsts, Sltsts and Ssts
Φ= 20-25%, 24m Nett Ssts
Gamma ray
E-W seismic profile through Prospect P18 and D-D1 well
The 13Amfs shales of the overlying transgressive systems tract cap these traps. This provides an effective regional top seal, but the underlying foot-seal is considered a higher geological risk factor, as it comprises interbedded shelf deposits.
The area is also affected by intrusion activity, which may have further affected the seals. Bright seismic anomalies appear to be soft signals, indicative of porous reservoir rock, possibly hydrocarbon saturated.

28. Summary of prospectivity

29. Summary of prospectivity
21 prospects delineated
Proven oil & wet-gas prone source rocks
Short migration routes and effective charge
Oil expulsion throughout the Tertiary
Geological risk low on all aspects except seal
Central High area affected by intrusion activity 55 million years ago
Proven reservoir rocks
Potential hydrocarbon accumulations associated with bright spots
Many prospects remain untested.
We have proven oil & wet-gas prone source rocks, and oil expulsion throughout Tertiary.
Geological risk low on all aspects except seal.
Central High area was affected by intrusion activity around 55million year ago.
Great reservoir rocks associated with bright spots which may be an indication of hydrocarbons i.e. oil with some gas.
Thank you for your attention. That leaves approximately 3 minutes for questioning.