Petroleum System of Melut Basin G2 Assignment .pptx

Petroleum system of Melut Basins describe more about the source rock, reservoir rock, trap, seal and hydrocarbon oil and gas. Describe more about portable, reserve source and resources

1. Petroleum System Of Melut Basin Prepared By Group 2 Petroleum Geology s 17/07/2024 17/07/2024

2. Group Two (2) Members S/NO NAMES INDEX NUMBERS 1 RONALD MUBARAK BONA 17-CN-290 2 EMMANUEL TOBI ADOK 17-CN-104 3 EMMANUELLA LUKUDU ALHAJ 17-CN-106 4 GABRIEL DENG CHUEI 17-CN-112 5 JOHN MANYANG DHAL 17-CN-156 6 AKOT AKOT MAWIEN 16-CN-024 7 RING JUSTIN BOL 17-CN-273

3. Contents Introduction Geological setting Depositional environments Source rocks Oil generation Reservoir rocks Migrations Seal Traps Conclusion References

4. Introduction The west and central African rift system is an intracontinental cretaceous-tertiary rift system where both stike -slip and extensional basin where formed mainly by mechanical separation of African crustal block during early cretaceous (BROWNE and FAIRHEAD, 1983) During 1970s and 1980s, this area was widely explore by Exxon, Chevron, and Conoco among others. Only giant oil field was found during 1975-2000s, i.e., Unity Field in Muglad Basin of Sudan discovered in 1980 in the figure below with the ultimate recoverable reserves of 900 million barrels (Paul et al., 2003).

5. Geological Setting The M elut basin is located to the south of CASZ (fig. 1 above). Its an intracontinental cretaceous-tertiary rift basin formed due to the strike-slip and associate pull-apart along the CASZ ( Guiraud and Maurin , 1992; McHargue et al ., 1992) during the early cretaceous on the consolidated craton (Binks and Fairhead, 1992): .The basin appear to be passive rifts generated by crustal extensional and lithologic thinning ( Wilson and Guriaud , 1992) .The Melut rift basin extends across atleast 33,000square kilometers, is upto 100 kilometer wide, 310 kilometer long and locally upto 10 kilometer of Cretaceous – tertiary sediment. It may coalesce southward and link up with the Anza rift in Kenya. Based on the interpreted regional bouger gravity and aeromagnetic data , six subbasin can be identified: Northern subbasin , Southern subbasin , Central subbasin , Western subbasin , Eastern subbasin and Central high. .Three major episodes of extensional tectonism are recognized in the Melut Basin: “Early Cretaceous”, approximately 140-95 Ma; “Late Cretaceous”, 95-65 Ma; “Paleogene”, 65-30 Ma, similar to Muglad Basin.

6. Depositional Environment The outcrops surrounding the M elut basin are predominantly Pre-Cambrian schist, gneiss and Cambrain granite (Schull, 1988). They were the main provenance for sediment in the basin. The basement of the basin id inferred to be similar to the outcrops, and has been confirmed by the drilling in the basin. In Melut basin only one exploration well, Fal -, penetrated the basement, which consist of quartzite of unknown age. In the Ruat Basin, north to the Melut basin, Taka-1 well also penetrated a plagiogranite basement. The cretaceous and Tertairy strata have been confirmed to be present in the Melut basin, but the stratigraphy and nomination of strata are less studied and the useful information and data are lack in references. Four major stratigraghic sequences, separated by unconformities, are determined by seismic, drilling and paleontological data: namely Lower Cretaceous, Upper Cretaceous, Paleogene and Neogene Quaternary. The stratigraphic column of Melut basin is summarized in figure 4 as shown

7. Source Rock Source rock is the types of rock that contain organic matter that can generate hydrocarbons through heat and pressure over geologic time. These are typically fine-grained sediment such as shale, mudstones, or limestone that have accumulated and preserved organic material from ancient plants and animals. When sources are buried deep enough, the organic matter in the rock begin to undergo a process called thermal maturation, where its converted into hydrocarbon such as oil and natural gas. Drilling indicated that three intervals of dark lacustrine shale occur in the basin: Lower Cretaceous, upper Cretaceous and Paleogene, each associate with rifting stage. The routine geochemical analyses of cutting and crude oil, including TOC, whole-rock pyrolysis, GC-MS and carbon isotopes, and sources-oil correlation the black organic-rich shales in the upper Al Gayger formation are the main source rocks with good-excellent hydrocarbon generation potential in the basin.

8. Cont …. The Al G ayger sources rocks have total organic carbon (TOC) content that range from 0.32% to 3.24% (2.08% average), chloroform-extract bitumen contents that range from 83 to 7667 ppm. The thickness of good-excellent source rock is about 63 m in the Fal-1well, hydrogen index (HI) of good source rock from the Al Gayger formation with TOC of more than 0.6% ranges from 273 to 579mg HC/g TOC and oxygen index ranges from 40 to 181 mg CO/g TOC (93 mg CO/g TOC average) The upper Cretaceous lacustrine shale of the Ghalhak Formation have a low content of organic matter, showing poor to fair quality for hydrocarbon source rocks.

9. Oil generation The thermal gradient should be relatively lower, it was inferred to be 26 c=km. To the paleogene time the eas had more and more influence on the melut basin, volcanic activities became more widespread from northern subbasin toward southeast. The present thermal gradient is about 46:5 c=km calculated from RFT testing results, very closeto that of the active rift basins in the east china ( hu et al., 1991). The argodeed-1 well is drilled in the basin center. Its bottom depth is 3800 m and only upper cretaceous strata are penetrated.

10. The vitrinite reflectance and the maximum temperature analyses of geological cuttings from argorded-1 well indicate that the present top oil widow is 2500 m (corresponding to 0.6% ro ), and oil peak generation depth (at a ro level around 0.8–1%) is 3300–3400 m (Fig. 7) indicate that source rocks in the upper al gayger formation began to generate oil at the end late cretaceous in the depocenter , but most part of the basin reached the oil peak generation at approximately 23 ma ( i.E. End oligocene after lau formation)

11. Reservoir Rocks Reservoir rock, refer to the of sedimentary rock that has the ability to store the significant amount of hydrocarbon such as oil and natural gas. These rocks have pores and fracture that allow hydrocarbon to flow and accumulate within them. e .g Sandstone, Limestone and Dolomite. The primary reservoirs of the Melut Basin are the Paleogene and Upper Cretaceous sandstones where commercial oil flows hsve been tasted from. The crystalline and metamorphic rock basement of lower relief after long-period and more intense weathering before Cretaceous decided the quartz contribution to the sandstones in the Melut Basin is more higher than those of active basin in east China, such as Bohai Bay and Songliao Basin (Hu et al., 199; Kuykendall et al., 2003). And the sandstone exhibit good reservoir quality (porosity and permeability) at the depth in Melut Basin.

12. Cont …. However, the difference of location and tectonic evolution hidtory resulted in the major pay zones and features changes with times and space in Sudan. The major pay zones in the Muglad basin are the Bentiu Formation of the lower Cretaceous, the shales of Aredeiba deposited during the second rifting episode provide good regional seal for the underlying Bentiu Formation (Schull, 1988; Giedt , 1990; Tong et al., 2004). In the Melut Basin, about 95% of oil reserves are accumulated in the Yabus and Samma sandstones (Dou, 2004). the relatively weak rifting episode during the cretaceous resulted in sand dominant sediments. No thick shales can provide good regional seal within the cretaceous strata. As resulted, oil and gas generated and expelled from the Lower Cretaceous Al Gayger source rocks migrated to and accumulated in the Yabus and Samma sandstones.

13. Migrations During the late Paleogene, the lower cretaceous source rocks in the basin center entered the oil generation peak stage, oil and gas were expelled to the upper cretaceous strata first, and then further migrated through very thick sandstones of the upper cretaceous vertically along the faults and horizontally upwards, and finally accumulated in the Paleogene reservoirs under the A dar regional seal, and occasionally accumulated in the antithetic fault-blocks of the upper cretaceous if the fault sealing is available. As a result, oil and gas generated and expelled from the lower cretaceous al gayger source rocks migrated to and accumulated in the yabus and samma sandstones.

14. Seal and Charge System Seal is the layer of impermeable rock or sediment that prevent the upward or horizontal migration of hydrocarbon from the reservoir rock. Its act as barrier, trapping the hydrocarbon within the reservoir and preventing them from escaping into the surrounding formations. E.g of seal are shale, claystone, and sandstone. The Adar Formation has a sand net-to-gross ratio of less than 20%. The accumulated thickness of mudstones penetrated by exploration wells is 128-507 m and upto 900 m in basin depocenter as interpreted in seismic profiles, acting as regional seal for the underlying Yabus and Samma Formations. In spite of the tectonic movements, the Adar seal contributed as strong fault sealing capacity for juxtaposition of fault-blocks and lithological column.

15. Cont … The Yabus-Samma sandstones in the footwall face the Adar thick mudstones. Providing exc3ellent fault-sealing conditions for the oil accumulation. In addition, the mudstones within Melut Formation can serves as local top seal and fault sealing for the antithetic fault-blocks, for examples, at the Palogue South-2 well commercial oil flow was obtained from the Melut Reservoirs. But it is difficult to find the CSP threshold for oil accumulation because few oil pool have been found by now. During the Late Paleogene, the Lower Cretaceous sources rock in the basin center entered the oil generation peak stage, oil and gas were expelled to the Upper Cretaceous strata first, and then migrated through very thick sandstone of the Upper Cretaceous vertically along the fault and horizontally upwards, and finally accumulated in the Paleogene reservoirs under the Adar regional seal and occasionally accumulated in the antithetic fault-blocks of the Upper Cretaceous if the fault sealing is available.

16. Trap Trap is th geological structure that contains and preserves hydrocarbon within reservoir rock that can be formed by various mechanism such as faults, folds and stratigraphic pinchouts . The act as storage spaces for hydrocarbon, which are typically generated from the source rock and migrated through the reservoir rock before becoming trapped. In the Muglad Basin antithetic fault-blocks of the Bentiu-Aradeiba Formation of the Cretaceous are the major types ofb traps for hydrocarbon accumulation (Schull, 1988; Tong et al., 2004). In the Muglad basin the major types of traps and the age of the core pay zones are faulted anticline and Paleogene res[ pectively .

17. Faulted anticline During the Early Cretaceous the steep planar boundary faults resulted in the few large rollover anticlines on the hanging-wall of the boundary faults. Half graben frame-work decides that the several normal faults dipping to the basin the center are developed on the slopes. The sand dominant the sequence of the Upper Cretaceous could not generate large-scale drape-anticlines. Rifting during the Paleogene reactivated the underlying structures, fragmenting the anticline formed during Cretaceous into several fault-blocks and faulted anticline, increasing the fault thrown and decreasing the fault sealing capacity formed by intraformational mudstones of the Melut Formation. During the Paleogene rifting stage some large-scale drape-anticlines were well developed on the paleo-highs. Faulted anticlinal oil fields found up to now include Palogue-Fal drape-anticline, Jamous-1 faulted-anticline, Longyang-1 collapse-anticline, Bong West faulted anticline and Adar –Yale faulted anticline (see Fig. 2). The anticline developed during Paleogene rifting stages account for about 95% of proven oil reserves.

18. Antithetic tilted-blocks Tilted-blocks are formed by simple block rotation along the normal plane. When the dip of the fault plane is contrary to the dip of the formations, which is called the antithetic tilted-block, the shale at and across-fault will act as a seal for the closure of the footwalls. For instance the Adar Formation, acting as the regional seal, provided a good top seal and fault sealing capacity for the Yabus and Samma Formations. This types of structure is very throughout the basin, similar to Muglad basin (Schull, 1988). By the end of 2005, the proven oil-in-place volume in this types account for 5% of the oil in place in the basin, e.g Lui and Agordeed Fields. (see Fig. 2).

19. The Great Palogue Field Exploration History After acquiring infill 2D seismic lines, the Palogue anticlinal structure was found on the east side of the Northern subbasin . The first wild-cat, Palogue-1, was drilled in September 2002, and 72.3 m thick oil pay zone were penetrated in Samma-Yabus and Upper Cretaceous strata. After the successful testing Palogue-1 (1312-1333 m) and obtaining the production of 810 m3/d, Fal-1 well was drilled immediately 2.7 km to the northeast of the palogue-1 well in a separate fault block in January 2003 based on the updated 2D seismic interpretation result. The net pay zones of the Fal-1 well in Y abus and S amma formations is 79.7 m thick and the tested daily production is 520 m3 /d. Then a 3D seismic acquisition of 309 km2 over the whole structure was finished in may 2003. As of end 2005, more Than 20 appraisal wells were drilled to prove the oil reserves. The proven recoverable oil reserves are about 900 million barrels.

20. Conclusions The polyphased geologic evolution of the M elut rift basin during the cretaceous and tertiary has resulted in the superimposed tectonic episodes, with stronger extension and more shales sediments during the early cretaceous and paleogene and relatively weaker tectonism and sandy sediments during the late cretaceous. The discovery of a world-class giant hydrocarbon accumulation characterized by a large gross hydrocarbon interval and good- to excellent-quality lacustrine-fluvial reservoir sands on a large, highly faulted anticline, i.e., The great P alogue field, indicates that the major exploration objectives are the paleogene pay zone, which is significantly different from the Muglad basin where the bentiu of the lower cretaceous is the major pay zone

21. References Binks, R.M., Fairhead, J.D., 1992. A Plate Tectonic Setting For The Mesozoic Rifts Of Western And Central Africa. In: Ziegler, P.A. (Ed.), Geodynamics Of Rifting, Volume II. Case History Studies On Rifts North And South America, Tectonophysics 213, 141–151. Bosworth, W., 1992. Mesozoic And Early Tertiary Rift Tectonics In East Africa. Tectonophysics 209, 115–137. Browne, S.E., Fairhead, J.D., 1983. Gravity Study Of The Central Africa Rift System: A Model Of Continental Disruption. 1. The Ngaoundere And Abu Gabra Rifts. Tectonophysics 94, 187–203. Dou, L., 2004. Formation Style Of Petroleum Accumulations In Interior Rift Basins. Petroleum Exploration And Development 31 (2), 29–31 (In Chinese With English Abstract)