Hydrocarbon Potentiality, Thermal Maturation and Generation Modeling of the Abu Gabra Formation in Heglig, Bamboo and Azraq Fields, Muglad Basin, Sudan

Abstract

Abstract A lateral geochemical evaluation of the Abu Gabra Formation in Azraq, Bamboo and Heglig fields in the Muglad rift basin has been carried out. The study was based on several analyses of 401 samples selected from eight wells in addition a one dimensional models for representative wells in the three field have been generated. The stratigraphic correlation model of the studied wells showed a huge depth contrast along the continuity of all the formations through the three studied field. Whereas the top Abu Gabra Formation ranges between I084 to 1450 m in Azraq field, 2030 to 2379 m in Bamboo field and between 3077 to 3396 m in Heglig field. The correlation model shows a general increase of the thickness from the north towards the south of the study area which emphasized on the faulting system as a result of tectonic rifting of the Muglad basin. The Rock-Eval pyrolysis results of 303 samples selected from the studied wells indicate that the hydrocarbon potentiality of the Abu Gabra Formation decreases from the north to the south of the study area whereas the average Total Organic Carbon (TOC) values in Azraq, Bamboo and Heglig fields are 2.34, 0.45 and 1.22% respectively. The average values of the Potential Hydrocarbons (S2), Hydrogen Index (HI) and Petroleum Potential (PP) support the TOC results. The average HI values in Azraq, Bamboo and Heglig fields are 488, 70 and I36 mg/gTOC respectively which indicate that the source rock in Azraq field has potentiality for mainly oil, whereas the expected hydrocarbon product is mainly gas in Heglig field. Bamboo field has none generated source rock. The microscopic investigation of 21 Kerogen slides supported by the Hydrogen Index (HI) and Oxygen Index (OI) data suggest that the main Kerogen type of the Abu Gabra Formation in Azraq field is Kerogen type I (mainly Amorphous Organic Matter) mixed with tiny ratio of Kerogen type II, Bamboo and Heglig fields are characterized by phytoclasts organic matter (Kerogen type III). Thes variation in the Kerogen type explains the difference in the expected hydrocarbons types. Results of Vitrinite Reflectance (Ro), Spore Colour Index (SCI), the Maximum Temperature (Tmax), and the Production Index (PI) indicate that the Abu Gabra Formation in the studied fields is generally a mature source rock (oil window) but proportionally the O Azraq’s source rock has the lowest level of maturity (Ro: 0.65 /0; SCI: 7) whereas Heglig’s source rock has the highest level of maturity (R0: 0.93%; SCI: 9.5) which could be

attributed to the huge sedimentary rock thickness in Heglig field compared with the other two fields. The obtained biomarkers from the Gas Chromatography (GC) and Gas Chromatography Mass Spectrometer (GCMS) analyses of three crude oil samples from Azraq SW-1 well suggest that the source rock in Azraq field is mature and the oil is indigenous, whereas the values of the Carbon Preference Index (CPI) vary from 1.06 to 1.12. The pristine (Pr/n- C17) and phytane (Ph/n-C18) results indicate that the source rock in Azraq field is characterized by mixed organic matter. Other biomarkers such as trisnorhopane ratio (Ts/Tm), C30 moretane/hopane, 29Ts/C29 hopane, sterane isomerization ([313/0iu+]3[3 BB C29 ster) and isosterane fraction (ow. S/S+R C29 ster) proved that the source rock accessed the oil window. Burial history curves of four representative wells show that the Abu Gabra Formation has entered the oil window during the Early Cretaceous at the ages; 133 Ma, 135 Ma, 1 14.7 Ma and 134.5 Ma in Seyal-1, Jamouse NW-1, Bamboo AG-1 and Garad AG-1 wells respectively. The peak of oil generation was reached during the ages between 127 to 111 Ma in Seyal-1, 130 to 125 Ma in Jamouse NW-1 and between 128.3 to 116 Ma in Garad AG-1 well. The 1D models showed that the oils were expelled from the middle and lower parts of the Abu Gabra Formation in the study area at different ratios whereas the expulsion ratio exceeds 80 % in Seyal-1 well, and ranges from 50 to 80 % and from 10 to 50 % in Jamouse NW-1 and Garad AG-1 respectively. In Bamboo AG-1 well the 1D model indicates that oil expulsion has not taken place. The models reflect that the oil expulsion decreases from the noithem part toward the southern part of the study area and the oil accumulations in Bamboo AG-1 well is non-indigenous, therefor the exploration in some areas in Bamboo field is recommended to be reviewed. More prospecting work in Azraq field is recommended because this research proved the high hydrocarbon potentiality in this area. More Ro data from neighbor Wells are required to generate a regional maturity map to redirect the oil prospecting in the northern part of the Muglad basin. Investment of the approved gas accumulations in Heglig field by this research is recommended after canying out the reserve estimation and economic studies.