10B. Petroleum Occurrences in Basins Analogous to the East African Rift System Robert Kasande Principal Geologist Petroleum Exploration and Production Department, Ministry of Energy and Mineral Development, Uganda.
TABLE OF CONTENTS Abstract...iii 1.0 INTRODUCTION... 1 2.0 BASIN ARCHITECTURE AND STRUCTURE OF EARS... 3 3.0 THE PETROLEUM SYSTEM... 3 3.1 Source rock... 3 3.2 Reservoir rocks... 5 3.2.1 Basement rock reservoirs... 5 3.2.2 Clastic reservoirs... 6 3.3 Traps and seals... 7 4.0 THE YI-SHU GRABEN OF CHINA... 8 4.1 Regional geology and basin structure... 9 4.2 The petroleum system... 10 4.3.1 Source rocks... 10 4.3.2 Reservoir rocks... 11 4.3.3 Oil field characteristics... 11 5.0 OTHER TERTIARY RIFT BASINS THAT ARE ANALOGOUS TO THE EARS13 5.1 The Central Sumatra Basin in Indonesia... 13 5.2. Phetchabun Basin, Thailand Graben... 14 5.3 Cambay Basin, Western India... 15 6.0 CONCLUSION... 17 SELECTED REFERENCES... 19 ii
Abstract The East African Rift System (EARS) is in a very immature exploration stage. Using databases of analogues, particularly similarities in age of rift formation, environments of deposition, source and seal, reservoir and trapping mechanisms, the EARS has been compared to the Yi-Shu Graben of China, the Central Sumatra Basin of Indonesia, and to a smaller extent to Cambay basin of India and the Phetchabun basin of northern Thailand. The four above are prolific Lower Tertiary lacustrine basins mostly made up of halfgrabens that started forming during Eocene - Oligocene. While evolution history may be same for half-grabens in a basin and therefore structure, the different half-grabens tend to have different source rock types and therefore different potential. It is very important that explorationists investigate the individual half grabens separately. Some of the basins of the EARS have excellent source rock, reservoir, trap and seal potential. The Lokichar and Semliki basin of the Turkana Region in Kenya and the Albertine Graben in Uganda respectively have exhibited good source and trapping potential similar to the basins discussed in this paper. The Semliki Basin appears to have more than one source rocks. Based on the analogues, it can be concluded that some basins in the EARS have good potential for petroleum. What may be lacking might be an improvement in the level of exploration and resources that have been committed in East Africa. iii
1. INTRODUCTION Basin analogy is a common methodology during early exploration stages of a basin. The prerequisites for a successful petroleum system are present in the East African Rift although no success in exploration has been achieved yet. The East African Rift System (EARS) forms a narrow (50 150 km wide) elongate system of normal faults stretching for about 3500 km. EARS bifurcates around the Tanganyika shield into the Eastern and Western Branches (Figure 1). The Eastern Branch is composed of Kenya and Ethiopian rift zones. Much of the structure of the Eastern Branch is buried beneath and probably modified by voluminous outpouring of volcanic rocks. The Western Branch consists of the Malawi, Rukwa, Tanganyika and Kivu- Edward-Albert and West Nile rift zones. Lacking significant volcanic fill, the zone along the Western Branch is filled by long, narrow and deep plateau lakes and thick piles of sediments. This paper looks at the EARS and compares its petroleum system mostly to that of the Yi-Shu Graben of China and to other tertiary rift basins like the Central Sumatra Basin of Indonesia, the Phetchabun Basin of northern Thailand and the Cambay Basin of western onshore India. The Yi-Shu Graben is located in the oil producing east China region. Two oil fields have been discovered following 20 years of exploration. The graben is 140 km long and 10-20 km wide, covering an area of 2200 km 2. The first seismic was acquired in 1984 and by the end of 2000, 3729 km of 2D seismics, 1572 km 2 of 3D seismics had been acquired and 124 exploration wells had been drilled, with 30 wells encountering commercial oil and gas. This represents a drilling success rate of 25%. The Central Sumatra Basin has reserves of 25 billion bbls of oil in place from an Eocene Oligocene source rock and in Lower Miocene marine reservoirs. 1
The Phetchabun Basin of northern Thailand is a Late Oligocene series of grabens formed as a result of northwest southeast dextral and northeast southwest wrench tectonics. The Cambay Basin is a north south rift sag onshore western India. Source and reservoir rocks were deposited during Paleogene Middle Eocene. Oil accumulations are found along axial depressions and along eastern and western basin margins. L. Albert Figure 1 East African Rift showing oil shows in the different basins (adopted from Morley, 1999) 2
2. BASIN ARCHITECTURE AND STRUCTURE OF EARS Along the 3000-km-length western rift, 100-km-long en echelon border-fault segments are linked by oblique-slip transfer faults and relay ramps within comparatively high-strain accommodation zones. The average water-depth in Lake Tanganyika is about 700 m, with the deepest point at 1400m. While in Lake Albert, the deepest point is 58m. The western branch of the rift contains half graben basins characterized by large boundary faults which produce asymmetrical half grabens. Fault scarps rise up to 1700 m and have been responsible for 6-7 km of sediments deposited in the basins. Basically, the East African basins are typical intracontinental rift basins, filled with Mesozoic and Cenozoic sediments. 3. THE PETROLEUM SYSTEM 3.1 Source rock Lacustrine source rocks are prevalent in the EARS (Figure 1). Hydrocarbon reserves associated with lacustrine source rocks can be in the billions e.g. as documented by Williams and Eubank, 1995, the Central Sumatra Basin, Indonesia has 25 billion bbls from syn-rift source rocks. The nature of a source rock may change within a rift system. For example, analysis of oil seepages in the Albertine Graben has shown the hydrocarbons to be from different sources and with different characteristics (Figure 2). Source and maturity parameters reveal that the source of the Paraa and Kibiro oil seepages differs from that of the Kibuku oil seepage which was probably derived from different source kitchen of the same source rocks. Oil-prone source rocks could have formed in some of the sub-basins while gas-prone source rocks in others. 3
Differences in relative rates of subsidence and sedimentation could be responsible for the different types of source rocks. Two depocentres, one in the southwest and another in the northwest separated by northwest southeast highs help to explain the different types of oils sampled in the Semliki basin, Albertine Graben (Figure 3). Figure 2 Gas chromatograms of oil seeps from the Albertine Graben 4
SW Gravity profile NE Depth profile Scale: 1: 50,000 Figure 3 - Depocentres in the southwest and northeast in the Semliki basin The Lochichar Basin of NE Kenya was found to have abundant source rock. The thick shales recovered in the Laperot-1, in the order of hundreds of metres had TOC averaging 4.5% and could have been deposited during the Eocene - early Oligocene. 3.2 Reservoir rocks Generally like most Meso-Cenozoic basins in Africa, the EARS is rich in reservoir rocks. Two potential reservoirs exist, one of which is the basement complex (and the other is sandstones of fluvio-deltaic systems that prograde over lacustrine sediments. 3.2.1 Basement rock reservoirs In the eastern part of the Albertine Graben, basement rocks occur widely in outcrop along rift escarpment, comprising mainly of gneiss, granite gneiss and quartzite. As a result of dynamic tectonic forces, these rocks have generated fractures while weathering and solution by organic acid has resulted into pores and cavities. In Kibuku area of the Semliki Basin, two 5
groups of tectonic fractures developed in the outcrop basement rocks, some of which had been infilled with quartz veins (Plate 1 & 2). Plate 1 Fractured basement showing two fracture directions Plate 2 A quartz vein in fractured basement 3.2.2 Clastic reservoirs Fluvial deltaic sandstone reservoirs dominate. These are mostly very fine coarse grained, moderately sorted with angular subrounded quartz arenites to subarkoses. These sands represent alluvial fans associated with steep faulted highs, point bars, deltas, shoreline and lacustrine turbidites. The quality of the sands varies from sub-basin to subbasin. For example, the sandstones of the Semliki basin have excellent porosities and permeablility as evidenced from samples taken from the Kibuku outcrop (Plate 3). 6
Plate 3 - Kisegi bituminous sandstone, Kibuku outcrop 3.3 Traps and seals Several gravity highs in the eastern part of the Semliki basin of the Albertine Graben are favourable areas for oil and gas accumulation. A great variety of traps such as flower structures, drape anticlines, faulted blocks and buried hills exist on these gravity highs. NW Gravity Magnetic SE Depth profile Scale: 1:50,000 Figure 3 - A seismic section from the Albertine Graben showing the different trap types 7
A number of authors have doubted the presence of effective seals in the basins of the EARS. Thick clay beds outcropping in the Semliki and Kaiso- Tonya areas of the Albertine Graben show potential for being effective seals. This has also been shown in a well drilled in the Albertine Graben. 0s W Possible seal 0 2 km E 1s 2s Figure 4 Seismic section from the Lokichar Basin showing a sequence that could be a seal on top of structure below. 4. THE YI-SHU GRABEN OF CHINA The Yi-Shu Graben is located in the oil producing east China region (Figure 5). Two oil fields have been discovered following 20 years of exploration. The graben is 140 km long and 10-20 km wide, covering an area of 2200 km 2. The first seismic was acquired in 1984 and by the end of 2000, 3729 km of 2D seismics, 1572 km 2 of 3D seismics had been acquired and 124 exploration wells had been drilled as well, with 30 wells encountering commercial oil and gas. 8
4.1 Regional geology and basin structure The Yi-Shu Graben is the northern extension of the Tancheng Lujiang Fault System in East China. It is bounded by a group of NE-trending normal faults in the southeast. The northwest boundary of the basin consists of high-angle thrust faults, normal faults and vertical faults. The basement rocks are mostly granites related to Yanshan Oregeny, and low grade metamorphic Paleozoic rocks. The Yi-Shu Graben consists of the Moliging rift depression, the Yidan uplift, Luxiang rift depression and Chaluhe rift depression. The area went through an early uplift stage, syn-rift and post-rift stages. Figure 5 Location of the Yi-Shu Graben in China 9
4.2 The petroleum system Non-marine clastics of the Lower Tertiary, Upper Tertiary and Quaternary overlie the basement complex. A half-graben framework resulted into the development of two sedimentary systems in the eastern and western parts of the basin. The sedimentary column is divided into the Shuangyang Formation, the Sheling Formation and the Yongji Formation. The Shuangyang Formation started deposition during the early stages of rifting. At this time, water level was relatively shallow, and thin red and grey-green mudtones were deposited as well as alluvial fan sand bodies. Most of the sediments of the Shuangyang Formation are syn-rift. The Sheling and the Yongji Formations were deposited during the late stages of rifting. The main depositional environment in the basin is semi-deep lacustrine where thick dark shales were deposited in the depocentre with fan delta sand bodies deposited around the two flanks of the basin. Due to a regional strike-slip effect during the Late Tertiary, the water level had greatly reduced resulting into the deposition of alluvial fan systems. 4.3.1 Source rocks Geochemical analysis of cores and cuttings shows that Lower Tertiary dark shales, which developed primarily in the central portion of the riftdepressions, were formed under warm, humid conditions of semitropical - tropical climate in slightly oxidising to slightly reducing freshwater. The source rock occurs mainly in the Sheling and Shuangyang Formations showing high organic matter with TOC greater than 1.0%. Total hydrocarbon contents (SI value) are higher than 0.021%. The Yongji 10
Formation has TOC varying from 0.678% to 0.736%. It is relatively higher in case of Moliging depression (1.24%). Element, carbon isotopes, pyrolysis and gas chromatography analyses of kerogen in the source rocks show that organic matter in the Sheling and Shuangyang Formations is mainly of type II 2 and type III, with more continental organic matter. The oil generation threshold is 2200m below the earth surface while the peak of oil generation is at 3000m. Hydrocarbons generated are mainly light oil, with density varying from 0.76g/cm 3 to 0.80g/cm 3. Gas-oil ratio is relatively high. 4.3.2 Reservoir rocks There are four pay zones in the basin. From bottom to top these are; the Paleozoic granitic buried-hills, Member 1 of the basal conglomerate of the Shuangyang Formation, Member 2 of the fan delta sand bodies of the Shuangyang Formation, and delta and turbidite sandstones of the Sheling Formation. The porosity and permeability of these sandstones vary markedly because they were deposited rapidly near the source. 4.3.3 Oil field characteristics Two oil fields have been discovered in the basin so far, i.e., Changchun oilfield and Moliging oilfield. The former, covering an area of 4.9 km 2, contains 77.35 million bbls of oil in-place and 2.4 billion cubic meters of solution gas in-place. It is located on a rollover anticline complicated by faults, and consists of oil pools of faulted-blocks, stratigraphic unconformity, stratigraphic-lithological and buried-hills (Figure 6). The Shuangyang Formation is the main oil-bearing formation, with 3 members of sandstones. The quartz content is 52.3%, feldspar 6.5% and debris 15%. The sandstone porosity is 14% on average, permeability is 16.78-172.40 10-3 µm 2. It has produced 15.47 million bbls of oil cumulatively, with residual recoverable reserves of 7 million bbls of oil in the ground. The oil is characterized by low density (0.8280-0.8417 g/cm 3 ), low viscosity (3.93-11
7.12 mpas), low initial boiling point (61-117ºC) and high set point (27-29ºC). Moliqing oilfield covers an area of 32.3km 2, with 154.84 million bbls of oil in-place, of which 30.97 million bbls is recoverable. Solution gas reserves are 1 billion cubic meters in-place. It is trapped in a roll-over anticline complicated by faults. Hydrocarbon traps include faulted-blocks, stratigraphic unconformity, stratigraphic-lithological and buried-hills. So far the field has not been put into production. The total oil and gas resources are 876.54 million bbls and 31.8 billion cubic meters, respectively, suggesting the resources abundance of 196-546 thousand bbls per square kilometre in different rift depressions in the graben. Oil Gas Water Figure 6 The Changchun Oil Field, Yi-Shu Graben 12
5. OTHER TERTIARY RIFT BASINS THAT ARE ANALOGOUS TO THE EARS 5.1 The Central Sumatra Basin in Indonesia This basin is situated between the Bila River to the north and the Kampar river to the south in central Indonesia (Figure 7). This early Tertiary (Eocene - Oligocene) basin is a series of sub-parallel north to northwest trending half-grabens separated by horst blocks. Figure 7 Location of the Central Sumatra basin (adopted from Lambiase, 1995). The half-graben structures were filled with synrift sediments of the Pematang Group that serves as an excellent source rock. The source rocks have Type I and II Kerogen. Ostracods associated gastropods with 13
in the Brown Shale Formation and the lacustrine algae suggest freshwater lacustrine environment. Following uplift, folding and faulting, there was regional subsidence. During Early Miocene, marine clastics of the Sihapas Group were deposited. These have proved to be excellent reservoirs and seals. The reservoirs have average porosities ranging from 22-25% and permeability ranging from 0.01 122md (Lambiase, 1995). Also, there is production in pre-tertiary fractured granites and metaquartizites. These basement rocks have secondary fracture porosities of 10-15%. Early to Middle Miocene deformation was responsible for the trapping of the 25 billion barrels proven reserves in the Central Sumatra Basin. Drape structures over palaeo-highs, drag folds and inversion structures similar to those in Semliki Basin, Albertine Graben are common. 5.2. Phetchabun Basin, Thailand Graben The Phetchabun Basin is an onshore north south trending rift system consisting of five small grabens and half-grabens (Figure 8). Rifting started in the Late Oligocene as a result of associated dextral and sinstral wrench tectonics. The grabens range from 1100 2500 m in depth and are bounded by steep normal and listric faults. The individual grabens are separated by strike slip accommodation zones with wrench fault structures. A discovery was made in a tilted fault block similar to those seen in the Semliki Basin of the Albertine Graben. Igneous intrusions in the basin might be responsible for local generation of hydrocarbons. During Late Oligocene Early Miocene, organic-rich shales and thin deltaic sands were deposited. The source rocks are dominantly of Type I and II Kerogen, although most of the samples were found to be 14
immature. There is a high geothermal gradient (5.7ºC/100m) probably related to intrusives in the graben. Figure 8 Location of the Phetchabun basin (adopted from Lambiase, 1995) 5.3 Cambay Basin, Western India The Cambay Basin is a north south rift sag basin onshore western India Figure 9. Source and reservoir rocks were deposited during Paleogene Middle Eocene. The source rocks contain types II and III kerogen. Oil accumulations are found along axial depressions and along eastern and western margins. 15
Figure 9 - Location of the Cambay Basin (adopted from Banerjee et al, 2001). 16
6. CONCLUSION Table - Summary and comparison of the Yi-Shu Graben, the Albertine Graben and Central Sumatra Basin Parameters Yi-Shu Central Sumatra Albertine Graben Graben Basin Area (km 2 ) 2200 > 10,000 >90,000 Length (km) 140 570 450 Width (km) 10-20 45 150-220 Thickness of sediments ~ 5000 > 6000 > 5000 (m) Framework Full-graben Full graben Volcanics Time (Ma) 7.73-23.6 < 12 Source rocks Reservoirs Seals Traps Distribution Along boundary faults None Middle Tertiary, Geological Lower Jurassic- Age Tertiary Cretaceous (?) Lower Tertiary TOC > 1% >1% 1-10% Type II 1 and I in Kerogen I, II type 2 EA 2 Type I and II Type III in EA 3 Environment Lacustrine Lacustrine Lacustrine Type Petrophysical property Mainly sandstones, also basement rocks Lithic sandstone, mainly secondary porosity Quartzose sandstone, primary porosity may be preserved well Delta front sandstones, also fractured basement Conglomeratic medium fine grained sandstones Lithology Shale Shale In central portion of the In central portion Distribution basin of the basin Varying types including drape Paleo highs, drag anticline, faulted-block, folds and inversion Type unconformity, stratigraphic structures and buried-hill Timing Favorable Unknown Favourable Petroleum System Proven Speculative Proven Resource Total Resource 876.54 million bbls unknown 25 billion bbls 17
Basin analogy relates under explored basins to similar producing basins. The EARS is a series of half grabens bounded by normal faults. The individual half grabens vary in character and therefore potential. They should thoroughly be explored individually. There are high TOC source rocks and excellent reservoirs in the EARS: Clastic reservoirs have high primary porosity and permeability while secondary porosity resulting from fracturing is present in basement rocks. A great variety of structures exist in the EARS. Flower structures, drape anticlines, buried hills and fault blocks. Similarly, the Yi-Shu graben and the Central Sumatra basin have quality lacustrine source rock, quality reservoirs and effective traps. The Yi-Shu graben has 876 million bbls of oil while the Central Sumatra has 25 billion bbls. No discovery yet has been made in the EARS The difference might just be in the resources that have been committed to these basins and therefore the level of exploration. 18
SELECTED REFERENCES Morley C.K.W.; A Wescott; D. M. Stone; R.M Harpe; S.T. Wigger; R.A. Day; and F.M. Karanja; 1999, Geology and Geophysics of the Western Turkana Basins, Kenya, AAPG Studies in Geology 44, pp 19-65 AAPG, Tulsa Oklahoma, USA. Morley C.K; 1999 comparison of hydrocarbon prospectivity in Rift Systems, AAPG Studies in Geology 44, pp 233-242. AAPG Tulsa, Oklahoma, USA. Lambiase J.J; 1995, Hydrocarbon Habitat in Rift Basins, Geological Society special Publication No. 80 pp 241-282 Lambiase J.J; 1995, Hydrocarbon Habitat in Rift Basins, Geological Society special Publication No. 80 pp 331-371 Banerjee A. S. Pahari; M. Jha; A.K. Sinha; A.K. Jain; N. Kumar; N.J. Thomas: K.N. Misra; and K. Chandra; 1999. The effective source rocks in the Cambay basin, India, AAPG Bulletin, V.86, No.3 pp 433-456. Kasande R; Rubondo E.N.T; 1996, The Geology of the Semliki Basin, unpublished report, Petroleum Exploration and Production Department. 19