This study focuses on the Central Santos Basin portion. It is based on a 3D petroleum system analysis, risks assessment and petroleum leads mapping, based on the best geological, geophysical and geochemical information available.

The tectonic framework of the Central Santos Basin comprises a shallow basement compartment, covered only by Tertiary sequence, and another compartment where complete rift, transitional and drift sequences occur. The structural framework of the rift sequence is characterized by horsts and grabens, controlled by normal faults, while in the drift sequence; halokinesis gave rise to elongated belts with distinct structural styles.

Eight stratigraphic horizons were mapped, over an area of approximately 56,378 km², using 2D seismic data. The basin was subsequently subdivided into four regional domains: 1. Seal Risk Zone, 2. Platform to Salt-Ramp; 3. Salt-Ramp to Mini-Basin, and 4. Ultra-deep area of the Mini-basin domains. Each one of them, present variable risks for the presence of lacustrine and marine source rocks and the potential for migration across salt.

High-resolution geochemical technology (HRGT) was applied in 9 selected oil samples and in 20 wells containing organic-rich sediments ranging in age from the Albian to Tertiary. The prime objectives were to map and characterize source rocks in the Central Santos Basin.

Part of the marine oils located in shallow waters show molecular features that suggest great contribution of condensates and gas from the lacustrine saline source rocks of the pre-salt Guaratiba Formation. Such data suggest a very prolific gas-prone area for all deep horizons in the platform area of the basin. This area in the Central Santos Basin is light/condensate-prone for the Guarujá-Ilha Bela (!) petroleum system and gas-prone for the Guaratiba-Ilha Bela (!) one.

In the deep-water part of the basin (Mini-basin Domain), the main phase of generation and migration of the Guaratiba (Rift) source rocks occurred during Cretaceous times but some areas are nowadays still in the oil “window”.

Full references of all images are listed in the reports

1. Introduction
2. Regional Geology and Tectonic Framework
3. Elements of the Petroleum Systems
   1. Source Rocks
      1. Lacustrine Guaratiba Formation
      2. Marine Guarujá Formation
      3. Marine-Upper Cenomanian-Turonian Itajai-Açu Formation
   2. Geochemistry of the Hydrocarbons
   3. Reservoirs
      1. Guaratiba Formation
      2. Guarujá Formation
      3. Ilhabela Member/Itajaí-Açu Formation
4. Tectono-Stratigraphic Framework
   1. Methodology
   2. Seismic Interpretation Results
5. Leads Characterization
   1. Exploratory History
   2. Leads Characterization
6. Petroleum System Modeling
   1. Introduction
   2. Geometry, Stratigraphy and Lithology
   3. Salt Geometry Through Time
   4. Calibration
   5. Source Rock Definition
   6. Boundary Conditions
      1. Paleowater Depth
      2. Surface Water Interface Temperature
      3. Lower Boundary Condition – Heat Flow
   7. Maturity and Pressure Modeling Results
      1. Evolution of Generation and expulsion of hydrocarbons
         1. Evolution of transformation ratio of each source rock
         2. Transformation Ratio and Expulsion Times
         3. Pore Pressure
      2. Accumulations – Composition and Migration Through Time
         1. First Scenario – Without Secondary cracking
         2. Second Scenario – Secondary cracking
      3. Accumulation Volumes and Migration Losses
      4. Conclusions of the Modeling Part – Final Remarks
7. Exploratory Implications and Risk Analysis
   1. Exploratory Implications
   2. Exploratory Risk Analyses
8. Integration of Central Santos and Blue Blocks Projects
9. Conclusions
10. References
11. Appendix 1 – Reports
12. Appendix 2 – Well Logs

1. Geological map of Southeastern Brazil and Southwestern Africa prior to the opening of the Atlantic Ocean (modified from De Wit et al., 1988). Onshore localities are (from southwest to northeast) Florianópolis (FL), Santos (SA), and Rio de Janeiro (RJ) in Brazil; and Luanda (LU) in Africa (Meisling et al., 2001).
2. Simplified tectonic framework and main hydrocarbon occurrences of the Santos Basin (modified from Pereira & Macedo, 1990).
3. Schematic geologic dip cross section in the Santos Basin (modified from Pereira & Macedo, 1990).
4. Stratigraphic chart of the Santos Basin showing the position of the Guarujá and Guaratiba Formations (modified from Pereira & Feijó, 1994).
5. Tectonostratigraphic events chart for the Campos and Santos basins, showing timing of regional lithostratigraphic packages relative to hotspot, rifting, and structural events.The stratigraphic columns are modified from Rangel et al. (1994) and Pereira & Feijó (1994). Dark yellow/heavy dots = coarse clastic rocks; light yellow/fine dots = fine-grained clastic rocks; brown/dashes = shale and mud rocks; blue/bricks = carbonate rocks; green/squares and green-blue hatchures = evaporites; mixed colors/mixed symbols = mixed lithology; pink/vees = volcanic rocks (Meisling et al., 2001).
6. Tectonostratigraphic events chart for the Campos and Santos basins, showing timing of hot spot, rifting and structural events (Meisling et al., 2001).
7. Map of South Atlantic and adjacent continents showing marine gravity anomalies from satellite altimetry (Sandwell & Smith, 1995), outline of onshore Paraná and Etendeka (EL) lavas, Mid- Atlantic Ridge (MAR), major fracture zones (Rio de Janeiro fracture zone = RJFZ; Florianópolis fracture zone = FFZ) , tracks of Tristão da Cunha and Trindade hot spots ( unfilled circles with ages in Ma), resulting seamounts (TR = Trindade; MV = Martin Vaz; TC = Tristão da Cunha) , and other offshore features (PB = Pelotas Basin; TA = Torres Arch; FP = Florianópolis Platform; RG = Rio Grande Rise; SB = Santos Basin; CB = Campos Basin; AP = Abrolhos Plateau; ES = Espírito Santo Basin; NB = Namib Basin; WB Walvis Basin; LB = Luderitz Basin) . The color bar shows anomaly values in mGal (Meisling et al., 2001).
8. Map of gravity anomalies, Campos and Santos basins. Anomalies are residual, after removal of a fifth-order trend surface from Bouguer-corrected data provided by Lamont- Doherty Geological Observatory.Onshore localities are (from southwest to northeast) Florianópolis (FL), Santos (SA), and Rio de Janeiro (RJ). Main anomalies have been interpreted (MU = nearshore Moho uplift; FS = failed spreading ridge). Dashed lines (TZ) identify some of the more prominent transfer zones; blue dotted lines (TF) prominent fossil ocean ridge transform faults. The color bar shows residual anomaly values in mGal (Meisling et al., 2001).
9. Geoseismic section A-A’ = across nearshore Moho uplift, Campos Basin (modified from Mohriak & Dewey, 1987; Mohriak et al., 1990a). Brasiliano structures were reactivated in oblique extension during rifting and in later far-field compression (see Cobbold et al., 2001).
10. Location Map of the wells in wich oil and rock samples were analysed aiming to understand the oil and source rock elements of the petroleum system.
11. Location map of the pre-salt oil and gas accumulations recent discovered in the deep and ultra-deep water areas of Santos Basin.
12. Schematic stratigraphic section, based on a 3D seismic line showing the pre-salt oil and gas accumulations recently discovered in the deep and ultra-deep water areas of the Santos Basin with the respective pods of generation.
13. Geochemical log of the 1-SPS-6-SP well, showing Total Organic Carbon and Pyrolysis-Rock-Eval data of the Guarujá and Itajaí-Açu Formations. Note that the sediments of both Formations present very low hydrocarbon source potential, organic carbon and hydrogen indices suggesting therefore sedimentation in an oxic environment.
14. Geochemical log of the 1-SPS-14A-SP well, showing Total Organic Carbon and Pyrolysis-Rock-Eval data of the Guarujá and Itajaí-Açu Formations. Note that the sediments of the Guaruja Formation present very low hydrocarbon source potential suggesting therefore sedimentation in an oxic environment/ residual organic carbon due to very high thermal evolution.
15. Geochemical log of the 1-SPS-39-SP well, showing Total Organic Carbon and Pyrolysis-Rock-Eval data of the Itajaí-Açu Formation. Note that the sediments analysed present very low hydrocarbon source potential suggesting therefore sedimentation in an oxic environment.
16. Natural series plot showing Total Organic Carbon and Pyrolysis-Rock-Eval data of the Guarujá and Itajaí-Açu Formations. Note that the sediments of both Formations present very low hydrocarbon source potential, organic carbon and hydrogen indices suggesting therefore sedimentation in an oxic environment. Also, they show that hydrocarbon generation start above 4600m.
17. Map showing average Total Organic Carbon data of the Itajaí-Açu Formation. Note that the there is a tendency of the Itajaí-Açu Formation to be thicker and richer in the distal parts of the basin.
18. Whole Oil gas chromatograms of typical oils from the Central Santos Basin.As could be noted, the oil from 1BSS 0074 shows a bimodal distribution which is typical of many Lacustrine derived oils from the Greater Campos Basin. None of the oils show evidence of recent biodegradation.
19. 25-Norhopane/Hopane ratio (from saturate biomarker analyses) versus nC17/pristane ratio (from the Whole Oil GC. traces). Note that this figure shows no or little recent biodegradation in the samples whereas the oils from 7MLZ 0003 and 7MLZ 0004 have suffered minor paleo biodegradation. The oil from 1BSS 0075 has suffered little “recent biodegradation” but has suffered major paleobiodegradation.
20. Mass chromatograms of m/z 191 (terpanes).Note that the oils from 1BSS 0074 shows abundant Gammacerane and TSTM (typical of a Marine derived oils).
21. Mass chromatograms of m/z 217 (steranes). Note that the oils from 1BSS 0074 shows abundant C27 steranes and low S/S+R C29 sterane ratios (typical of Lacustrine derived oils) whereas the oils from 1SPS 0031 and 1SPS 0021 show higher C28 and C29 sterane contents and higher S/S+R C29 ratios (typical of a Marine derived oils).
22. Mass chromatograms of m/z 259 (diasteranes and TPP compounds).Note that the oils from 1BSS 0074 shows more abundant TPP compounds than the C27 diasteranes (typical of Lacustrine derived oils) whereas the oils from 1SPS 0031 and 1SPS 0021 show higher C27 diasteranes contents than the TPP compounds (typical of a Marine derived oils).
23. Mass chromatograms of m/z 245 (methyl triaromatic compounds).Note that the oils from 1BSS 0074 shows more abundant 4-methyl compounds than the 3-methyl triaromatics (typical of Lacustrine derived oils) whereas the oils from 1SPS 0031 and 1SPS 0021 show higher 3-methyl contents than the 4-methyl (typical of a Marine derived oils).
24. A cross plot of Diasteranes/TPP versus Hopanes/Steranes ratio for the oils from the Central Santos Basin.
25. A cross plot of the Hopane/Sterane ratio versus 3-methyl/4-methyl triaromatic components.
26. Biomarker Sterane maturity cross plot of S/S+R versus 20R C29 steranes.
27. Oil Quality cross plot of %S versus API gravity for the oils.
28. Quantitative Diamondoid Cracking results suggesting a mixed origin for the Central Santos Basin oils.
29. Diamondoid compound specific carbon isotope data (CSAID) for the selected oils from the Central Santos Basin.
30. Compositional and methane carbon isotope gas data from the Central Santos Basin showing origing and thermal stage of generation.
31. C2/ C3 compositional and carbon isotope diagram of gas samples from the Central Santos Basin showing thermal stage of generation.
32. Stratigraphic charts of the basins encompassed with the the Great Campos area. Stratigraphic charts modified from Feijó (1994).
33. Schematic cross-section showing the entrapment of oil and gas within the porous carbonate facies of the Guarujá Formation in the Tubarão field, southern Santos Basin (modified from Moraes Júnior et al., 1989).
34. Permeability vs. porosity plot for the Guarujá Formation reservoirs in the Tubarão field (Carvalho et al., 1990).
35. Schematic cross section showing the entrapment of gas within the turbidite sandstones of the Itajaí-Açu Fm. and shelf sandstones of the Juréia Fm. in the Merluza field, central Santos Basin (modified from Riddle et al., 1995).
36. Schematic geological cross-section (not to scale) across the 1-BSS-69 heavy oil accumulation, northern Santos Basin, showing the oil entrapment within Eocene turbidites of the Marambaia Formation structured by a faulted anticline over a salt pillow.
37. Map of salt-detached structural domains, Campos and Santos basins.
38. Map showing the location of the 2D seismic lines and calibration wells.
39. Stratigraphic chart showing the mapped horizons of the Central Santos Basin.
40. Calibration seismic section of the Central Santos Basin. The main structural style is related to extensional systems, the Albian horizon is shown in red, Cenomanian level in light blue, dark blue shows the Santonian level, violet shows the Maastrichtian level and the yellow horizon represents the Middle Miocene.
41. Time/depth geometry control. At the top (left) interpreted seismic line in time domain (miliseconds);
42. Regional seismic line (Oligocene-Miocene, yellow; Maastrichtian, violet; Santonian, blue; Itanhaem top, red; salt top; pink; Guaratiba top, light brown; Rift level, brown).
43. 3D view of the top of the Rift (scale in meters). A main rift sequence is present in the NE-SW direction of Mexilhao field.
44. 3D view of the top of the Aptian Source Rocks (scale in meters). A high frequency of rift deformation is observed in the southwest portion of the map.
45. 3D view of the top of the Ariri Formation (scale in meters). Observe the limit between two structural domains along the extension of the Cabo Frio fault zone. The Salt Welt structural domain extends along shallow water and slope areas, being characterized by the widespread occurrence of salt windows (areas in blue and green colors).
46. Mini-basin configuretion in the Santos Basin. This mini-basin is formed between salt diapirs and salt walls with thick around 5 Km.
47. Lithologies of the Guaruja Formation.
48. Salt windows for Central Santos; the main salt trend direction is NE-SW with salt domes with thickness between 2 and 6 Km (in red) and salt layers with salt thickness with more than 400meters (in green).
49. Albian gap for Central Santos. Observe the presence of the Albian gap in the block 791, and in the NE-SW trend over most of the portions of the red blocks, the southeast portion of the map is out off the interpreted area.
50. Sedimentary gap of the Albian to Santonian sequences observed in Central Santos.
51. Geometry of the trap of Tubarao field, the reservoir of the Mexilhao field is defined as a turbidite bodie deformed by rollover structure.
52. 3D view of the top of the Itanhaem Sequence (scale in meters). This map shows at its east-southeast portion the salt dome domain.
53. Ilha Bela member distribution at the Central Santos Area.
54. 3D view of the top of the Structural Maastrichtian (scale in meters). The map shows a strong influence of salt tectonics, displaying anticlines.
55. 3D view of the top of the Oligocene-Miocene sequence (scale in meters). This map show low influence of salt domes.
56. 3D view of the SeaBed (meters).
57. Representative cross-section for the blocks 407, 510 and 512.
58. Representative cross-section for the block 409.
59. Representative cross-section for block 411.
60. Representative cross-section for blocks 621 and 736.
61. The main reservoirs are related to progradation areas and the exploratory play is like the Merluza gas field.
62. Representative inline and crossline showing block 730.
63. Representative inline and crossline showing block 671.
64. Representative line showing blocks 226 and 270.
65. Representative inline and crossline showing block 360.
66. Representative inline and crossline showing block 268.
67. Representative inline and crossline showing block 314.
68. Representative cross-section for block 359.
69. Representative inline and crossline showing block 731 with the exploratory play associated with salt domes.
70. Representative inline and crossline showing block 315 with the exploratory play associated with salt movement.
71. Representative inline and crossline showing block 313 with the exploratory play associated with salt movement.
72. Representative inline and crossline showing block 269 with the exploratory play associated with salt movement.
73. Representative inline and crossline showing block 792 with the exploratory play associated with salt movement.
74. Representative inline and crossline showing block 791 with the exploratory play associated with the mini-basin.
75. Representative inline and crossline showing block 915 with the exploratory play associated with the mini-basin.
76. Representative crossection showing blocks 738 and 625 as representative blocks of the South Eastern area.
77. Ranking blocks without petroleum modeling for the 8th bid round.
78. Ranking blocks without petroleum modeling for the 9th bid round.
79. Map of Ranking blocks without petroleum modeling for the 8th bid round.
80. Map of Ranking blocks without petroleum modeling for the 9th bid round.
81. Location of the Central Santos Project (light red rectangle). Offered blocks at 8th and 9th ANP Bids are displayed in light green and blue, respectively.
82. Model sequences defined by nine depth interpreted seismic horizons, showing the 4 source rock levels and main reservoir intervals, including the assigned ages.
83. Facies map of the Pleistocene (1.8 Ma).
84. Facies map of the Pleistocene (5.3 Ma).
85. Facies map of the Miocene (7.2 Ma).
86. Facies map of the Miocene (11.6 Ma).
87. Facies map of the Oligocene-Miocene (26.7 Ma).
88. Facies map of the Eocene-Oligocene (39.6 Ma).
89. Facies map of the Eocene (52.6 Ma).
90. Facies map of the Paleocene-Eocene (65.5 Ma).
91. Facies map of the Maastrictian-Paleocene (72.5 Ma).
92. Facies map of the Campanian-Maastrictian (79.5 Ma).
93. Facies map of the Cenomanian-Santonian (86.5 Ma).
94. Facies map of the Cenomanian-Santonian (93.5 Ma).
95. Facies map of the Cenomanian-Santonian (93.8 Ma).
96. Facies map of the Cenomanian-Santonian (95.1Ma).
97. Facies map of the Cenomanian Source Rock (95.3 Ma).
98. Facies map of the Cenomanian-Santonian Reservoir (96.7 Ma) and Cenomanian-Santonian (97.3Ma).
99. Facies map of the Cenomanian-Santonian (97.7 Ma, layers 1 and 2).
100. Facies map of the Cenomanian (98.3 Ma, layers 1 and 2).
101. Facies map of the Upper-Albian (98.8 Ma).
102. Facies map of the Upper-Albian (100 Ma).
103. Facies map of the Upper-Albian (103 Ma).
104. Facies map of the Lower-Albian (106 Ma).
105. Facies map of the Lower-Albian Source Rock (109 Ma).
106. Facies map of the Lower-Albian (112 Ma).
107. Facies map of the Aptian (Salt – 113 Ma).
108. Facies map of the Lower-Aptian (118 Ma).
109. Facies map of the Aptian Source Rock (121.5 Ma).
110. Facies map of the Rift (125 Ma).
111. Facies map of the Rift (128 Ma).
112. Facies map of the Talc-Stevensite Source Rock (132 Ma).
113. Facies map of the Rift (133 Ma).
114. List of the lithologies used to define the facies.
115. Salt geometry at 112 Ma. Note that the original thickness of the salt layer was not uniform.
116. Salt geometry restored for 109 Ma.
117. Salt geometry restored for 106 Ma.
118. Salt geometry restored for 103 Ma.
119. Salt geometry restored for 100 Ma.
120. Salt geometry restored for 93.5 Ma. Note that many salt windows are opened.
121. Salt geometry restored for 86.5 Ma.
122. Salt geometry restored for 65.5 Ma.
123. Salt geometry restored for 52.5 Ma.
124. Salt geometry restored for 39.6 Ma
125. Salt geometry restored for 11.6 Ma.
126. Salt geometry at present day.
127. Map view of the salt windows restored at 100 Ma. The thin white line shows the location of the cross-section displayed in the previous figures.
128. Map view of the salt windows restored at 65.5 Ma.
129. Map view of the salt windows at present day.
130. 3D view of the salt geometry at 112 Ma.
131. 3D view of the salt geometry at 100 Ma.
132. 3D view of the salt geometry at 65.5 Ma.
133. 3D view of the salt geometry at present day.
134. Calibration plots for vitrinite (%Ro) and temperature (BHT) of a well in the south portion of the basin.
135. Calibration plots for vitrinite (%Ro) and temperature (BHT) for a well in the central portion of the basin.
136. Calibration plots for vitrinite (%Ro) and temperature (BHT) for a well in the north portion of the basin.
137. Calibration plots for vitrinite (%Ro) and temperature (BHT) for another well in the north portion of the basin.
138. Total organic carbon (%) and Hydrogen Index (mg HC/gC) maps for the Talc-Stevensite SR.
139. Total organic carbon (%) and Hydrogen Index (mg HC/gC) maps for the Coquinas SR.
140. Total organic carbon (%) and Hydrogen Index (mg HC/gC) maps for the Albian SR.
141. Total organic carbon (%) and Hydrogen Index (mg HC/gC) maps for the Cenomanian-Turonian SR.
142. Primary cracking kinetics for the Talc-Stevensite source rock (IES_Alaskan_Tasmanite-BH056-4C).
143. Primary cracking kinetics for the Coquinas source rock (IES_Boghead_Coal-BH005-4C).
144. Primary cracking kinetics for the Albian source rock (IES_Toarcian_Shale-BH420-4C).
145. Primary cracking kinetics for the Albian source rock (IES_Kimmeridge_Clay-BH263-4C).
146. Waples (2000) reaction used in the secondary cracking reactions: C2-C5 to methane. The histogram shows the activation energy versus initial ratio (proportion of each activation band). The Arrhenius constant value to this reaction is 3.15e+28 m.y.-1.
147. Pepper (1995), type I reaction used in the secondary cracking reactions: C6-C14 to C2-C5 and C15+ to C6-C14. The histogram shows the activation energy versus initial ratio (proportion of each activation band). The Arrhenius constant value for this reaction is 3.15e+27 m.y.-1.
148. Pepper (1995), type II reaction used in the secondary cracking reactions: C6-C14 to C2-C5 and C15+ to C6-C14. The histogram shows the activation energy versus initial ratio (proportion of each activation band). The Arrhenius constant value for this reaction is 3.15e+27 m.y-1.
149. Paleowater depth map estimated for 100 Ma (scale in meters).
150. Paleowater depth map estimated for 93.5 Ma (scale in meters).
151. Paleowater depth map estimated for 63.5 Ma (scale in meters).
152. Paleowater depth map estimated for 11 Ma (scale in meters).
153. Paleo temperature at the surface of the model. Based on Wygrala (1989).
154. Heat flow map from 109 Ma (mW/m2).
155. Heat flow map from 98.8 Ma (mW/m2). Note the high heat flow anomaly in the western border of the model. This anomaly was added to the map in order to honor the maturation data in well 1-SPS-23.
156. Present day heat flow map (mW/m2). The orange and yellow colors are the result of changes we made in the heat flow map in order to honor temperature data of the wells near the MexilhãoField. The anomaly is about 11 mW/m2 higher than the areas in a 20 km range.
157. Generation windows for the Talc-Stevensite source rock.
158. Generation windows for the Coquinas source rock.
159. Generation windows for the Albian source rock.
160. Generation windows for the Cenomanian-Turonian source rock.
161. Salt domains: Salt Escape Zone, Salt Diapirs Zone and Salt Wall Zone. In detail a map of oil windows of the Cenomanian SR, showing the impact of salt domains over its maturation state.
162. Transformation ratio of the Talc-Stevensite source rock (present day).
163. Transformation ratio map of the Talc-Stevensite source rock (109 Ma).
164. Transformation ratio map of the Talc- Stevensite source rock (86 Ma).
165. Temperature map of the Talc- Stevensite source rock at present day.
166. Transformation ratio of the Coquinas source rock (present day).
167. Transformation ratio of the Coquinas source rock (106 Ma).
168. Transformation ratio of the Coquinas source rock (65.5 Ma).
169. Present day temperature of the Coquinas source rock.
170. Transformation ratio of the Albian source rock (present day).
171. Transformation ratio of the Albian source rock (93.5 Ma).
172. Transformation ratio of the Albian source rock (72.5 Ma).
173. Temperature of the Albian source rock (present day).
174. Transformation ratio of the Cenomanian source rock (present day).
175. Structural map of top Cenomanian source rock (present day).
176. Transformation ratio of the Cenomanian source rock (72.5 Ma).
177. Temperature map of the Cenomanian source rock (present day).
178. Sections in the northeastern portion of the model crossing the Mexilhão Field. The upper section shows the geologic framework at present day and the lower one shows the transformation ratio for the four source rock layers.
179. Sections in the southern portion of the model crossing the Merluza Field. The upper section shows the geologic framework at present day and the lower one shows the transformation ratio for the four source rock layers.
180. Southwest view of transformation ratio map of the Talc-Stevensite source rock showing the position of two 2D profiles and extraction points.
181. Expulsion peaks of the Talc-Stevensite source rock, in the northern portion of the model, based on transformation ratio of 20%. Expulsion windows range from 105 to 89 Ma. Generation rate presents values that can reach 240 mg HC/gC/My.
182. Expulsion peaks of the Talc-Stevensite source rock, in the southern portion of the model, based on transformation ratio of 20%. Expulsion windows range from 116 to 104 Ma and 99 to 94 Ma. Generation rate presents values around 120 mg HC/gC/My.
183. Expulsion peaks of the Coquinas source rock, in the southern portion of the model, based on transformation ratio of 20%. Expulsion windows range from 107 to 100 Ma and 99 to 93 Ma. Generation rate values range from 50 to 90 mg HC/gC/My.
184. Expulsion peaks of the Coquinas source rock, in the northern portion of the model, based on transformation ratio of 20%. Expulsion windows range from 100 to 88. Generation rate values are more expressive than in the southern portion, reaching 160 mg HC/gC/My.
185. Expulsion peaks of the Albian source rock, in the north portion of the model, based on transformation ratio of 20%. Expulsion windows range from 98 to 87 Ma. Generation rate values reached 40 mg HC/gC/My.
186. Expulsion peaks of the Albian source rock, in the southern portion of the model, based on transformation ratio of 20%. Expulsion windows range from 97 to 92 Ma. Generation rate values reached 50 mg HC/gC/My.
187. Expulsion peak of the Cenomanian source rock, in the northern portion of the model, based on transformation ratio of 20%. Expulsion windows range from 72 to 53 Ma. Generation rate values reached low values around 18 mg HC/gC/My.
188. Pore-pressure map of the layer immediately below the salt (present day). Pressure values range from 5 (very shallow areas – around 1500 m) to 92 MPa in the deepest parts (around 9000 m).
189. Overpressure conditions in the layer immediately below the salt (Lower Aptian 118 Ma) at present day. Excess pressure reaches 1 MPa in the deepest areas.
190. Overpressure conditions in the layer immediately above the salt (Lower Albian – 112 Ma) at present day. Overpressure values reach 1 MPa in some mini basins intra salt walls (south of the model).
191. Main reservoir groups. Their names are based on original mapped horizons. These divisions will be used to describe the main accumulations predicted by petroleum system modeling. Note that part of the upper Albian is incorporated in the Cenomanian-Santonian interval.
192. Accumulation in the Pleistocene-Miocene level, close to the Merluza Field, shows a composition based mainly on Albian source rock compounds.
193. Accumulations in the Oligocene-Eocene level, in the central northern area (top) an important gas accumulation, presenting strong contribution of Coquinas source rocks. In the central area, we see small accumulations showing contribution from Albian and Cenomanian source rocks.
194. Accumulations in the Maastrichtian-Campanian interval. Accumulations A, B and C presents a mixing of the oils coming from the Talc-Stevensite, Coquinas and Cenomanian source rocks with some contribution from the Albian source rock. Accumulation D, for example, in the southern part of the model, is filled mainly by hydrocarbons from the Cenomanian and Albian source rocks.
195. Accumulations in the Cenomanian-Santonian interval; northern part of the model. Accumulations A and B present a strong contribution of Coquinas source rock (more than 50%), whereas accumulation C shows a mixture of hydrocarbons from Coquinas and Albian source rocks. Accumulation D was filled only by hydrocarbons from the Albian source rock.
196. Details of turbiditic interval. Well information place these turbiditic lobes into Cenomanian age, in Itajaí-Açú Formation.
197. Geological framework showing vectors of hydrocarbons migrating towards the Mexilhão Field from salt windows located in the east and southeast.
198. Migration pathways in the Mexilhão field area according to a Darcy flow simulation. The arrows indicate vapor (red) and liquid phases (green). The colored cells indicate areas with high saturation.
199. Migration pathways towards the Mexilhão field area predicted by hybrid flow simulation. The vectors indicate velocities of the vapor (red) and liquid phases (green).
200. Accumulations in the Cenomanian-Santonian layers in the southern portion of the model. Note that the accumulation B, in the area of Merluza Field, is made of almost equal amounts of hydrocarbons from Albian and Coquinas source rocks. The composition of the accumulations varies substantially in short distance. Note that accumulation D was filled only by hydrocarbons from the Cenomanian and Albian source rocks, whereas accumulation C was filled mostly by hydrocarbons from the Coquinas source rock.
201. Time evolution of the Mexilhão Field accumulation since 93.8 Ma. Note that Mexilhão Field was sourced mostly from hydrocarbons moving upward across the salt windows that exist in the east and southeast parts of the figure.
202. Time evolution of the Merluza accumulation since 93.8 Ma. Note that Merluza was part of a bigger structure that extended to the southwest in the past into which large amounts of hydrocarbons migrated as one can see in figures of 65.5 and 26.7 Ma.
203. Accumulations in the Lower Albian sequences. Substantial contribution from Coquinas source rock can be recognized in accumulations B and C. In accumulation A there is a mixture of Albian (more expressive) and Coquinas components. The large circular accumulation northwest of Mexilhão Field was filled dominantly by hydrocarbons from the Coquinas and Talc-Stevensite source rocks.
204. Saturation Map of the Lower Albian sequences. Substantially high saturations exist in the area of mini-basins where commercial accumulations of petroleum might also be present.
205. Accumulations in the pre-salt interval. Accumulations A and B host a mixture of hydrocarbons that originated from Talc-Stevensite and Coquinas source rocks whereas accumulations C (below Mexilhão Field) and D host only components from the Talc-Stevensite and Coquinas source rocks, respectively. Some accumulations host pure methane.
206. Accumulation in the Pleistocene-Miocene level, close to the Merluza Field. A smooth contribution of Coquinas source rocks can be noted in this accumulation.
207. Accumulation in the Oligocene-Eocene level. In both A and B accumulations can be noted, an increase of methane amount relative to C2-C5 and other heavy compounds.
208. Accumulations in the Maastrichtian-Campanian interval. In all accumulations of this interval it is possible to recognize an increase in light compounds (methane) relative to heavy compounds (C15+, C6-C14 and C2-C5). These composition changes cause a decrease in liquid amounts and an increase in vapor phases (well evidenced in accumulation D) as well as an increase in API degree and GOR.
209. Accumulations in the Cenomanian-Santonian interval (north of the model). Accumulations A, B and C present high GOR and API degree in vapor phase and a composition based on methane (mainly coming from Coquinas SR). Liquid phases present heavy compounds (mainly from Coquinas too). Accumulation D shows only a Albian SR contribution with heavy compounds.
210. Accumulations in the Cenomanian-Santonian interval (south of the model). Accumulations A and D show contributions of pos-rift SR while accumulations B and C are rich in rift SR compounds.
211. Vapor and liquid accumulations in the Cenomanian-Santonian interval. Vapor accumulations exist mostly in the northern area, especially nearby Mexilhão field.
212. GOR values of the Cenomanian-Santonian accumulations define roughly domains liable to have liquid and vapor accumulations. The numbers refer to GOR values of the liquid phase of each accumulation. However, the numbers should not be taken as exact representations of the contents of the accumulations, but only their relative values. Three areas can be distinguished: the purple area contains accumulations with GOR between 200 and 300; the red one delimits accumulations with the highest GORs (>300 m3/m3) in the area. Only one accumulation (the one indicated by GOR = 13,722) holds vapor phase without a liquid phase.
213. Accumulations in the lower Albian Interval.
214. Accumulations in the pre-salt interval. Accumulations in this level present a mixture of hydrocarbons sourced fromthe Coquinas and Talc-Stevensite source rocks with predominance of the lowermost one.
215. Vapor and liquid accumulations in the pre-salt interval. As in the Cenomanian-Santonian interval, it is possible to verify a smooth trend of vapor accumulations to the north of the studied area, especially nearby the Mexilhão field.
216. Map of highly saturated areas (>50% of petroleum saturations) for different reservoir intervals. These areas with saturations complement the accumulations shown in previous figures. They are potential reservoirs with porosities and permeabilites not as good as the accumulations shown in red and green in previous figures.
217. Accumulated volumes in each layer of the model (First Scenario). Note the larger volumes associated with the Cenom_Santonian, Lower Albian and Pre-Salt Reservoirs. Values are expressed in billion of barrels.
218. Accumulated volumes in the model layers (Second Scenario). Note the larger volumes associated with the Cenom_Santonian, Lower Albian and Pre-Salt layers. Values are expressed in billion of barrels.
219. Compositional contribution of each source rock (Talc-Stevensite, Coquinas, Albian and Cenomanian-Turonian) to to reservoir filling (First Scenario).
220. Compositional contribution of each source rock (Talc-Stevensite, Coquinas, Albian and Cenomanian-Turonian) to reservoir filling (Second Scenario).
221. Graph showing the cumulative volumes for first scenario (left side) and second scenario (right side). Purple curve means the total generated volumes; blue curve represents the total expelled and brown curve is the total accumulated. All volumes are expressed in Bbbls.
222. Graph showing generated and expelled volumes by event for the first scenario (left side) and second scenario (right side). Purple bars mean generated volumes and blue bars represent the expelled volumes. All volumes are expressed in billion of barrels.
223. Showing (A) Gas prone Belt; (B) Belt with the Mexilhao type of hydrocarbons; (C) the rest is the most liquid prone belt.
224. The colored map represents depth in burial meters to the top Aptian reservoir. The yellow contour lines represent burial depths greater than 4500 meters. The pink lines represent salt windows. The light colored mask in the middle of the map surround areas where the Aptian reservoir is at temperatures greater than 140o Celsius.
225. Summary of the hydrocarbon exploration systems of the Santos Basin.
226. Risk map of post salt plays in the Central Santos Basin. Include the 8th and 9th bid round blocks.
227. Risk map of the pre- salt plays in the Central Santos Basin. Include the 8th and 9th bid round blocks.
228. Migration path for the Albian Cenomanian level in the Central Santos Basin, in the map the 9th bid round blocks.
229. Oil accumulation for the pre-salt play in the Central Santos Basin, in the map the 9th bid round blocks.
230. Salt map of the two projects: Central Santos in the west (large pink area) and Santos Blue Blocks (narrow purple strip in the east).
231. Horizon correlations between Central Santos (left) and Santos Blue Blocks studies (right). This division is based on initial interpreted horizons in Central Santos project.
232. Correlation between depth to base salt layer of the two projects. There are differences in the depth model of about 200 to 300m along the common border of the projects.
233. Map of the top of the Aptian source rock (scale in meters) showing that the mean difference values are about 500 m. Some portions can reach 1000 m of difference, especially in areas where the salt layer is very thick and seismic quality decreases.
234. Map of the top of Barremian source rock (scale in meters). It is important to note the coherency between the structures in both maps.
235. Map of top of the basement (scale in meters).
236. Salt windows at 100 Ma.
237. Salt windows at 89 Ma.
238. Salt windows at 72.5 Ma.
239. Salt windows at 65 Ma. The salt windows in the two projects seem coherent at this time, but note that there are already more gas accumulations in the Blue Blocks side.
240. Salt windows at 35 Ma.
241. Salt windows at 12 Ma.
242. Salt geometry at present day. Note that the Central Santos Project predicts more liquid accumulations whereas many more gas accumulations are predicted in the Blue Blocks project.
243. Heat flow and temperature histories through time for the Central Santos and Blue Blocks models.
244. Heat flow at 132 Ma.
245. Heat flow at 112 Ma.
246. Heat flow at 100 Ma.
247. Heat flow at 65 Ma.
248. Heat flow at 35 Ma.
249. Present day heat flow.
250. Transformation ratio map of the Barremian source rocks, showing consistent correlation between two projects, except in areas where the salt layer is very thick. N-S white lines near the common border the models represent the places where transformation ratio and bulk generation rate profiles were extracted.
251. Transformation ratio map of the Aptian source rocks, where the same behavior of Barremian source rocks can be seen. N-S white lines near the common border the models represent the places where transformation ratio and bulk generation rate profiles were extracted.
252. Transformation ratio map of the Albian source rock. N-S white lines near the common border the models represent the places where transformation ratio and bulk generation rate profiles were extracted.
253. Transformation ratio map of the Cenomanian source rock N-S white lines near the common border the models represent the places where transformation ratio and bulk generation rate profiles were extracted.
254. Transformation ratio and bulk generation rate of the Barremian source rocks in the border of the two models. In this region expulsion peaks (greater than 20% of transformation ratio) vary from 118 to 98 Ma in the Santos Blue Blocks models and 96 Ma in Central Santos model.
255. Transformation ratio and bulk generation rate of the Aptian source rocks in the border of the two models. A well defined expulsion peak can be seen in the Central Santos Model (around 95 Ma) whereas in the Santos Blue Blocks models a wide range of expulsion can be defined (from 115 to 70 Ma).
256. Transformation ratio and bulk generation rate of the Albian source rocks for both projects.
257. Transformation ratio and bulk generation rate of the Cenomanian source rocks in the border of the two models.
258. Accumulations in the Oligocene-Eocene interval. Vapor phase of accumulations C, D and E (inside of the Santos Blue Blocks study) presents high methane content (50 to 70%) associated with high API degree and elevated GOR, and liquid phases are composed mainly by C10+ compounds.
259. Accumulations in the Maastrichtian-Campanian interval. Accumulations E and F presents high GOR and API values and vapor phases are composed mainly by methane. Liquid accumulations are based on C10+ compounds.
260. Accumulations in the Cenomanian-Santonian interval.
261. Accumulations in the Lower-Albian interval.
262. Saturations in the Lower Albian interval. Note the saturations are high between blocks 413 and 516.
263. Saturations in the Pre-Salt layers. In blocks 413 and 516 large areas of the pre-sal layers are saturated with hydrocarbons.
264. Geological map of Southeastern Brazil and Southwestern Africa prior to the opening of the Atlantic Ocean (modified from De Wit et al., 1988). Onshore localities are (from southwest to northeast) Florianópolis (FL), Santos (SA), and Rio de Janeiro (RJ) in Brazil; and Luanda (LU) in Africa (Meisling et al., 2001).
265. Simplified tectonic framework and main hydrocarbon occurrences of the Santos Basin (modified from Pereira & Macedo, 1990).
266. Schematic geologic dip cross section in the Santos Basin (modified from Pereira & Macedo, 1990).
267. Stratigraphic chart of the Santos Basin showing the position of the Guarujá and Guaratiba Formations (modified from Pereira & Feijó, 1994).
268. Tectonostratigraphic events chart for the Campos and Santos basins, showing timing of regional lithostratigraphic packages relative to hotspot, rifting, and structural events.The stratigraphic columns are modified from Rangel et al. (1994) and Pereira & Feijó (1994). Dark yellow/heavy dots = coarse clastic rocks; light yellow/fine dots = fine-grained clastic rocks; brown/dashes = shale and mud rocks; blue/bricks = carbonate rocks; green/squares and green-blue hatchures = evaporites; mixed colors/mixed symbols = mixed lithology; pink/vees = volcanic rocks (Meisling et al., 2001).
269. Tectonostratigraphic events chart for the Campos and Santos basins, showing timing of hot spot, rifting and structural events (Meisling et al., 2001).
270. Map of South Atlantic and adjacent continents showing marine gravity anomalies from satellite altimetry (Sandwell & Smith, 1995), outline of onshore Paraná and Etendeka (EL) lavas, Mid- Atlantic Ridge (MAR), major fracture zones (Rio de Janeiro fracture zone = RJFZ; Florianópolis fracture zone = FFZ) , tracks of Tristão da Cunha and Trindade hot spots ( unfilled circles with ages in Ma), resulting seamounts (TR = Trindade; MV = Martin Vaz; TC = Tristão da Cunha) , and other offshore features (PB = Pelotas Basin; TA = Torres Arch; FP = Florianópolis Platform; RG = Rio Grande Rise; SB = Santos Basin; CB = Campos Basin; AP = Abrolhos Plateau; ES = Espírito Santo Basin; NB = Namib Basin; WB Walvis Basin; LB = Luderitz Basin) . The color bar shows anomaly values in mGal (Meisling et al., 2001).
271. Map of gravity anomalies, Campos and Santos basins. Anomalies are residual, after removal of a fifth-order trend surface from Bouguer-corrected data provided by Lamont- Doherty Geological Observatory.Onshore localities are (from southwest to northeast) Florianópolis (FL), Santos (SA), and Rio de Janeiro (RJ). Main anomalies have been interpreted (MU = nearshore Moho uplift; FS = failed spreading ridge). Dashed lines (TZ) identify some of the more prominent transfer zones; blue dotted lines (TF) prominent fossil ocean ridge transform faults. The color bar shows residual anomaly values in mGal (Meisling et al., 2001).
272. Geoseismic section A-A’ = across nearshore Moho uplift, Campos Basin (modified from Mohriak & Dewey, 1987; Mohriak et al., 1990a). Brasiliano structures were reactivated in oblique extension during rifting and in later far-field compression (see Cobbold et al., 2001).
273. Location Map of the wells in wich oil and rock samples were analysed aiming to understand the oil and source rock elements of the petroleum system.
274. Location map of the pre-salt oil and gas accumulations recent discovered in the deep and ultra-deep water areas of Santos Basin.
275. Schematic stratigraphic section, based on a 3D seismic line showing the pre-salt oil and gas accumulations recently discovered in the deep and ultra-deep water areas of the Santos Basin with the respective pods of generation.
276. Geochemical log of the 1-SPS-6-SP well, showing Total Organic Carbon and Pyrolysis-Rock-Eval data of the Guarujá and Itajaí-Açu Formations. Note that the sediments of both Formations present very low hydrocarbon source potential, organic carbon and hydrogen indices suggesting therefore sedimentation in an oxic environment.
277. Geochemical log of the 1-SPS-14A-SP well, showing Total Organic Carbon and Pyrolysis-Rock-Eval data of the Guarujá and Itajaí-Açu Formations. Note that the sediments of the Guaruja Formation present very low hydrocarbon source potential suggesting therefore sedimentation in an oxic environment/ residual organic carbon due to very high thermal evolution.
278. Geochemical log of the 1-SPS-39-SP well, showing Total Organic Carbon and Pyrolysis-Rock-Eval data of the Itajaí-Açu Formation. Note that the sediments analysed present very low hydrocarbon source potential suggesting therefore sedimentation in an oxic environment.
279. Natural series plot showing Total Organic Carbon and Pyrolysis-Rock-Eval data of the Guarujá and Itajaí-Açu Formations. Note that the sediments of both Formations present very low hydrocarbon source potential, organic carbon and hydrogen indices suggesting therefore sedimentation in an oxic environment. Also, they show that hydrocarbon generation start above 4600m.
280. Map showing average Total Organic Carbon data of the Itajaí-Açu Formation. Note that the there is a tendency of the Itajaí-Açu Formation to be thicker and richer in the distal parts of the basin.
281. Whole Oil gas chromatograms of typical oils from the Central Santos Basin.As could be noted, the oil from 1BSS 0074 shows a bimodal distribution which is typical of many Lacustrine derived oils from the Greater Campos Basin. None of the oils show evidence of recent biodegradation.
282. 25-Norhopane/Hopane ratio (from saturate biomarker analyses) versus nC17/pristane ratio (from the Whole Oil GC. traces). Note that this figure shows no or little recent biodegradation in the samples whereas the oils from 7MLZ 0003 and 7MLZ 0004 have suffered minor paleo biodegradation. The oil from 1BSS 0075 has suffered little “recent biodegradation” but has suffered major paleobiodegradation.
283. Mass chromatograms of m/z 191 (terpanes).Note that the oils from 1BSS 0074 shows abundant Gammacerane and TSTM (typical of a Marine derived oils).
284. Mass chromatograms of m/z 217 (steranes).Note that the oils from 1BSS 0074 shows abundant C27 steranes and low S/S+R C29 sterane ratios (typical of Lacustrine derived oils) whereas the oils from 1SPS 0031 and 1SPS 0021 show higher C28 and C29 sterane contents and higher S/S+R C29 ratios (typical of a Marine derived oils).
285. Mass chromatograms of m/z 259 (diasteranes and TPP compounds).Note that the oils from 1BSS 0074 shows more abundant TPP compounds than the C27 diasteranes (typical of Lacustrine derived oils) whereas the oils from 1SPS 0031 and 1SPS 0021 show higher C27 diasteranes contents than the TPP compounds (typical of a Marine derived oils).
286. Mass chromatograms of m/z 245 (methyl triaromatic compounds).Note that the oils from 1BSS 0074 shows more abundant 4-methyl compounds than the 3-methyl triaromatics (typical of Lacustrine derived oils) whereas the oils from 1SPS 0031 and 1SPS 0021 show higher 3-methyl contents than the 4-methyl (typical of a Marine derived oils).
287. A cross plot of Diasteranes/TPP versus Hopanes/Steranes ratio for the oils from the Central Santos Basin.
288. A cross plot of the Hopane/Sterane ratio versus 3-methyl/4-methyl triaromatic components.
289. Biomarker Sterane maturity cross plot of S/S+R versus 20R C29 steranes.
290. Oil Quality cross plot of %S versus API gravity for the oils.
291. Quantitative Diamondoid Cracking results suggesting a mixed origin for the Central Santos Basin oils.
292. Diamondoid compound specific carbon isotope data (CSAID) for the selected oils from the Central Santos Basin.
293. Compositional and methane carbon isotope gas data from the Central Santos Basin showing origing and thermal stage of generation.
294. C2/ C3 compositional and carbon isotope diagram of gas samples from the Central Santos Basin showing thermal stage of generation.
295. Stratigraphic charts of the basins encompassed with the the Great Campos area. Stratigraphic charts modified from Feijó (1994).
296. Schematic cross-section showing the entrapment of oil and gas within the porous carbonate facies of the Guarujá Formation in the Tubarão field, southern Santos Basin (modified from Moraes Júnior et al., 1989).
297. Permeability vs. porosity plot for the Guarujá Formation reservoirs in the Tubarão field (Carvalho et al., 1990).
298. Schematic cross section showing the entrapment of gas within the turbidite sandstones of the Itajaí-Açu Fm. and shelf sandstones of the Juréia Fm. in the Merluza field, central Santos Basin (modified from Riddle et al., 1995).
299. Schematic geological cross-section (not to scale) across the 1-BSS-69 heavy oil accumulation, northern Santos Basin, showing the oil entrapment within Eocene turbidites of the Marambaia Formation structured by a faulted anticline over a salt pillow.
300. Map of salt-detached structural domains, Campos and Santos basins.
301. Map showing the location of the 2D seismic lines and calibration wells.
302. Stratigraphic chart showing the mapped horizons of the Central Santos Basin.
303. Calibration seismic section of the Central Santos Basin. The main structural style is related to extensional systems, the Albian horizon is shown in red, Cenomanian level in light blue, dark blue shows the Santonian level, violet shows the Maastrichtian level and the yellow horizon represents the Middle Miocene.
304. Time/depth geometry control. At the top (left) interpreted seismic line in time domain (miliseconds);
305. Regional seismic line (Oligocene-Miocene, yellow; Maastrichtian, violet; Santonian, blue; Itanhaem top, red; salt top; pink; Guaratiba top, light brown; Rift level, brown).
306. 3D view of the top of the Rift (scale in meters). A main rift sequence is present in the NE-SW direction of Mexilhao field.
307. 3D view of the top of the Aptian Source Rocks (scale in meters). A high frequency of rift deformation is observed in the southwest portion of the map.
308. 3D view of the top of the Ariri Formation (scale in meters). Observe the limit between two structural domains along the extension of the Cabo Frio fault zone. The Salt Welt structural domain extends along shallow water and slope areas, being characterized by the widespread occurrence of salt windows (areas in blue and green colors).
309. Mini-basin configuretion in the Santos Basin. This mini-basin is formed between salt diapirs and salt walls with thick around 5 Km.
310. Lithologies of the Guaruja Formation.
311. Salt windows for Central Santos; the main salt trend direction is NE-SW with salt domes with thickness between 2 and 6 Km (in red) and salt layers with salt thickness with more than 400meters (in green).
312. Albian gap for Central Santos. Observe the presence of the Albian gap in the block 791, and in the NE-SW trend over most of the portions of the red blocks, the southeast portion of the map is out off the interpreted area.
313. Sedimentary gap of the Albian to Santonian sequences observed in Central Santos.
314. Geometry of the trap of Tubarao field, the reservoir of the Mexilhao field is defined as a turbidite bodie deformed by rollover structure.
315. 3D view of the top of the Itanhaem Sequence (scale in meters). This map shows at its east-southeast portion the salt dome domain.
316. Ilha Bela member distribution at the Central Santos Area.
317. 3D view of the top of the Structural Maastrichtian (scale in meters). The map shows a strong influence of salt tectonics, displaying anticlines.
318. 3D view of the top of the Oligocene-Miocene sequence (scale in meters). This map show low influence of salt domes.
319. 3D view of the SeaBed (meters).
320. Representative cross-section for the blocks 407, 510 and 512.
321. Representative cross-section for the block 409.
322. Representative cross-section for block 411.
323. Representative cross-section for blocks 621 and 736.
324. The main reservoirs are related to progradation areas and the exploratory play is like the Merluza gas field.
325. Representative inline and crossline showing block 730.
326. Representative inline and crossline showing block 671.
327. Representative line showing blocks 226 and 270.
328. Representative inline and crossline showing block 360.
329. Representative inline and crossline showing block 268.
330. Representative inline and crossline showing block 314.
331. Representative cross-section for block 359.
332. Representative inline and crossline showing block 731 with the exploratory play associated with salt domes.
333. Representative inline and crossline showing block 315 with the exploratory play associated with salt movement.
334. Representative inline and crossline showing block 313 with the exploratory play associated with salt movement.
335. Representative inline and crossline showing block 269 with the exploratory play associated with salt movement.
336. Representative inline and crossline showing block 792 with the exploratory play associated with salt movement.
337. Representative inline and crossline showing block 791 with the exploratory play associated with the mini-basin.
338. Representative inline and crossline showing block 915 with the exploratory play associated with the mini-basin.
339. Representative crossection showing blocks 738 and 625 as representative blocks of the South Eastern area.
340. Ranking blocks without petroleum modeling for the 8th bid round.
341. Ranking blocks without petroleum modeling for the 9th bid round.
342. Map of Ranking blocks without petroleum modeling for the 8th bid round.
343. Map of Ranking blocks without petroleum modeling for the 9th bid round.
344. Location of the Central Santos Project (light red rectangle). Offered blocks at 8th and 9th ANP Bids are displayed in light green and blue, respectively.
345. Model sequences defined by nine depth interpreted seismic horizons, showing the 4 source rock levels and main reservoir intervals, including the assigned ages.
346. Facies map of the Pleistocene (1.8 Ma).
347. Facies map of the Pleistocene (5.3 Ma).
348. Facies map of the Miocene (7.2 Ma).
349. Facies map of the Miocene (11.6 Ma).
350. Facies map of the Oligocene-Miocene (26.7 Ma).
351. Facies map of the Eocene-Oligocene (39.6 Ma).
352. Facies map of the Eocene (52.6 Ma).
353. Facies map of the Paleocene-Eocene (65.5 Ma).
354. Facies map of the Maastrictian-Paleocene (72.5 Ma).
355. Facies map of the Campanian-Maastrictian (79.5 Ma).
356. Facies map of the Cenomanian-Santonian (86.5 Ma).
357. Facies map of the Cenomanian-Santonian (93.5 Ma).
358. Facies map of the Cenomanian-Santonian (93.8 Ma).
359. Facies map of the Cenomanian-Santonian (95.1Ma).
360. Facies map of the Cenomanian Source Rock (95.3 Ma).
361. Facies map of the Cenomanian-Santonian Reservoir (96.7 Ma) and Cenomanian-Santonian (97.3Ma).
362. Facies map of the Cenomanian-Santonian (97.7 Ma, layers 1 and 2).
363. Facies map of the Cenomanian (98.3 Ma, layers 1 and 2).
364. Facies map of the Upper-Albian (98.8 Ma).
365. Facies map of the Upper-Albian (100 Ma).
366. Facies map of the Upper-Albian (103 Ma).
367. Facies map of the Lower-Albian (106 Ma).
368. Facies map of the Lower-Albian Source Rock (109 Ma).
369. Facies map of the Lower-Albian (112 Ma).
370. Facies map of the Aptian (Salt – 113 Ma).
371. Facies map of the Lower-Aptian (118 Ma).
372. Facies map of the Aptian Source Rock (121.5 Ma).
373. Facies map of the Rift (125 Ma).
374. Facies map of the Rift (128 Ma).
375. Facies map of the Talc-Stevensite Source Rock (132 Ma).
376. Facies map of the Rift (133 Ma).
377. List of the lithologies used to define the facies.
378. Salt geometry at 112 Ma. Note that the original thickness of the salt layer was not uniform.
379. Salt geometry restored for 109 Ma.
380. Salt geometry restored for 106 Ma.
381. Salt geometry restored for 103 Ma.
382. Salt geometry restored for 100 Ma.
383. Salt geometry restored for 93.5 Ma. Note that many salt windows are opened.
384. Salt geometry restored for 86.5 Ma.
385. Salt geometry restored for 65.5 Ma.
386. Salt geometry restored for 52.5 Ma.
387. Salt geometry restored for 39.6 Ma
388. Salt geometry restored for 11.6 Ma.
389. Salt geometry at present day.
390. Map view of the salt windows restored at 100 Ma. The thin white line shows the location of the cross-section displayed in the previous figures.
391. Map view of the salt windows restored at 65.5 Ma.
392. Map view of the salt windows at present day.
393. 3D view of the salt geometry at 112 Ma.
394. 3D view of the salt geometry at 100 Ma.
395. 3D view of the salt geometry at 65.5 Ma.
396. 3D view of the salt geometry at present day.
397. Calibration plots for vitrinite (%Ro) and temperature (BHT) of a well in the south portion of the basin.
398. Calibration plots for vitrinite (%Ro) and temperature (BHT) for a well in the central portion of the basin.
399. Calibration plots for vitrinite (%Ro) and temperature (BHT) for a well in the north portion of the basin.
400. Calibration plots for vitrinite (%Ro) and temperature (BHT) for another well in the north portion of the basin.
401. Total organic carbon (%) and Hydrogen Index (mg HC/gC) maps for the Talc-Stevensite SR.
402. Total organic carbon (%) and Hydrogen Index (mg HC/gC) maps for the Coquinas SR.
403. Total organic carbon (%) and Hydrogen Index (mg HC/gC) maps for the Albian SR.
404. Total organic carbon (%) and Hydrogen Index (mg HC/gC) maps for the Cenomanian-Turonian SR.
405. Primary cracking kinetics for the Talc-Stevensite source rock (IES_Alaskan_Tasmanite-BH056-4C).
406. Primary cracking kinetics for the Coquinas source rock (IES_Boghead_Coal-BH005-4C).
407. Primary cracking kinetics for the Albian source rock (IES_Toarcian_Shale-BH420-4C).
408. Primary cracking kinetics for the Albian source rock (IES_Kimmeridge_Clay-BH263-4C).
409. Waples (2000) reaction used in the secondary cracking reactions: C2-C5 to methane. The histogram shows the activation energy versus initial ratio (proportion of each activation band). The Arrhenius constant value to this reaction is 3.15e+28 m.y.-1.
410. Pepper (1995), type I reaction used in the secondary cracking reactions: C6-C14 to C2-C5 and C15+ to C6-C14. The histogram shows the activation energy versus initial ratio (proportion of each activation band). The Arrhenius constant value for this reaction is 3.15e+27 m.y.-1.
411. Pepper (1995), type II reaction used in the secondary cracking reactions: C6-C14 to C2-C5 and C15+ to C6-C14. The histogram shows the activation energy versus initial ratio (proportion of each activation band). The Arrhenius constant value for this reaction is 3.15e+27 m.y-1.
412. Paleowater depth map estimated for 100 Ma (scale in meters).
413. Paleowater depth map estimated for 93.5 Ma (scale in meters).
414. Paleowater depth map estimated for 63.5 Ma (scale in meters).
415. Paleowater depth map estimated for 11 Ma (scale in meters).
416. Paleo temperature at the surface of the model. Based on Wygrala (1989).
417. Heat flow map from 109 Ma (mW/m2).
418. Heat flow map from 98.8 Ma (mW/m2). Note the high heat flow anomaly in the western border of the model. This anomaly was added to the map in order to honor the maturation data in well 1-SPS-23.
419. Present day heat flow map (mW/m2). The orange and yellow colors are the result of changes we made in the heat flow map in order to honor temperature data of the wells near the MexilhãoField. The anomaly is about 11 mW/m2 higher than the areas in a 20 km range.
420. Generation windows for the Talc-Stevensite source rock.
421. Generation windows for the Coquinas source rock.
422. Generation windows for the Albian source rock.
423. Generation windows for the Cenomanian-Turonian source rock.
424. Salt domains: Salt Escape Zone, Salt Diapirs Zone and Salt Wall Zone. In detail a map of oil windows of the Cenomanian SR, showing the impact of salt domains over its maturation state.
425. Transformation ratio of the Talc-Stevensite source rock (present day).
426. Transformation ratio map of the Talc-Stevensite source rock (109 Ma).
427. Transformation ratio map of the Talc- Stevensite source rock (86 Ma).
428. Temperature map of the Talc- Stevensite source rock at present day.
429. Transformation ratio of the Coquinas source rock (present day).
430. Transformation ratio of the Coquinas source rock (106 Ma).
431. Transformation ratio of the Coquinas source rock (65.5 Ma).
432. Present day temperature of the Coquinas source rock.
433. Transformation ratio of the Albian source rock (present day).
434. Transformation ratio of the Albian source rock (93.5 Ma).
435. Transformation ratio of the Albian source rock (72.5 Ma).
436. Temperature of the Albian source rock (present day).
437. Transformation ratio of the Cenomanian source rock (present day).
438. Structural map of top Cenomanian source rock (present day).
439. Transformation ratio of the Cenomanian source rock (72.5 Ma).
440. Temperature map of the Cenomanian source rock (present day).
441. Sections in the northeastern portion of the model crossing the Mexilhão Field. The upper section shows the geologic framework at present day and the lower one shows the transformation ratio for the four source rock layers.
442. Sections in the southern portion of the model crossing the Merluza Field. The upper section shows the geologic framework at present day and the lower one shows the transformation ratio for the four source rock layers.
443. Southwest view of transformation ratio map of the Talc-Stevensite source rock showing the position of two 2D profiles and extraction points.
444. Expulsion peaks of the Talc-Stevensite source rock, in the northern portion of the model, based on transformation ratio of 20%. Expulsion windows range from 105 to 89 Ma. Generation rate presents values that can reach 240 mg HC/gC/My.
445. Expulsion peaks of the Talc-Stevensite source rock, in the southern portion of the model, based on transformation ratio of 20%. Expulsion windows range from 116 to 104 Ma and 99 to 94 Ma. Generation rate presents values around 120 mg HC/gC/My.
446. Expulsion peaks of the Coquinas source rock, in the southern portion of the model, based on transformation ratio of 20%. Expulsion windows range from 107 to 100 Ma and 99 to 93 Ma. Generation rate values range from 50 to 90 mg HC/gC/My.
447. Expulsion peaks of the Coquinas source rock, in the northern portion of the model, based on transformation ratio of 20%. Expulsion windows range from 100 to 88. Generation rate values are more expressive than in the southern portion, reaching 160 mg HC/gC/My.
448. Expulsion peaks of the Albian source rock, in the north portion of the model, based on transformation ratio of 20%. Expulsion windows range from 98 to 87 Ma. Generation rate values reached 40 mg HC/gC/My.
449. Expulsion peaks of the Albian source rock, in the southern portion of the model, based on transformation ratio of 20%. Expulsion windows range from 97 to 92 Ma. Generation rate values reached 50 mg HC/gC/My.
450. Expulsion peak of the Cenomanian source rock, in the northern portion of the model, based on transformation ratio of 20%. Expulsion windows range from 72 to 53 Ma. Generation rate values reached low values around 18 mg HC/gC/My.
451. Pore-pressure map of the layer immediately below the salt (present day). Pressure values range from 5 (very shallow areas – around 1500 m) to 92 MPa in the deepest parts (around 9000 m).
452. Overpressure conditions in the layer immediately below the salt (Lower Aptian 118 Ma) at present day. Excess pressure reaches 1 MPa in the deepest areas.
453. Overpressure conditions in the layer immediately above the salt (Lower Albian – 112 Ma) at present day. Overpressure values reach 1 MPa in some mini basins intra salt walls (south of the model).
454. Main reservoir groups. Their names are based on original mapped horizons. These divisions will be used to describe the main accumulations predicted by petroleum system modeling. Note that part of the upper Albian is incorporated in the Cenomanian-Santonian interval.
455. Accumulation in the Pleistocene-Miocene level, close to the Merluza Field, shows a composition based mainly on Albian source rock compounds.
456. Accumulations in the Oligocene-Eocene level, in the central northern area (top) an important gas accumulation, presenting strong contribution of Coquinas source rocks. In the central area, we see small accumulations showing contribution from Albian and Cenomanian source rocks.
457. Accumulations in the Maastrichtian-Campanian interval. Accumulations A, B and C presents a mixing of the oils coming from the Talc-Stevensite, Coquinas and Cenomanian source rocks with some contribution from the Albian source rock. Accumulation D, for example, in the southern part of the model, is filled mainly by hydrocarbons from the Cenomanian and Albian source rocks.
458. Accumulations in the Cenomanian-Santonian interval; northern part of the model. Accumulations A and B present a strong contribution of Coquinas source rock (more than 50%), whereas accumulation C shows a mixture of hydrocarbons from Coquinas and Albian source rocks. Accumulation D was filled only by hydrocarbons from the Albian source rock.
459. Details of turbiditic interval. Well information place these turbiditic lobes into Cenomanian age, in Itajaí-Açú Formation.
460. Geological framework showing vectors of hydrocarbons migrating towards the Mexilhão Field from salt windows located in the east and southeast.
461. Migration pathways in the Mexilhão field area according to a Darcy flow simulation. The arrows indicate vapor (red) and liquid phases (green). The colored cells indicate areas with high saturation.
462. Migration pathways towards the Mexilhão field area predicted by hybrid flow simulation. The vectors indicate velocities of the vapor (red) and liquid phases (green).
463. Accumulations in the Cenomanian-Santonian layers in the southern portion of the model. Note that the accumulation B, in the area of Merluza Field, is made of almost equal amounts of hydrocarbons from Albian and Coquinas source rocks. The composition of the accumulations varies substantially in short distance. Note that accumulation D was filled only by hydrocarbons from the Cenomanian and Albian source rocks, whereas accumulation C was filled mostly by hydrocarbons from the Coquinas source rock.
464. Time evolution of the Mexilhão Field accumulation since 93.8 Ma. Note that Mexilhão Field was sourced mostly from hydrocarbons moving upward across the salt windows that exist in the east and southeast parts of the figure.
465. Time evolution of the Merluza accumulation since 93.8 Ma. Note that Merluza was part of a bigger structure that extended to the southwest in the past into which large amounts of hydrocarbons migrated as one can see in figures of 65.5 and 26.7 Ma.
466. Accumulations in the Lower Albian sequences. Substantial contribution from Coquinas source rock can be recognized in accumulations B and C. In accumulation A there is a mixture of Albian (more expressive) and Coquinas components. The large circular accumulation northwest of Mexilhão Field was filled dominantly by hydrocarbons from the Coquinas and Talc-Stevensite source rocks.
467. Saturation Map of the Lower Albian sequences. Substantially high saturations exist in the area of mini-basins where commercial accumulations of petroleum might also be present.
468. Accumulations in the pre-salt interval. Accumulations A and B host a mixture of hydrocarbons that originated from Talc-Stevensite and Coquinas source rocks whereas accumulations C (below Mexilhão Field) and D host only components from the Talc-Stevensite and Coquinas source rocks, respectively. Some accumulations host pure methane.
469. Accumulation in the Pleistocene-Miocene level, close to the Merluza Field. A smooth contribution of Coquinas source rocks can be noted in this accumulation.
470. Accumulation in the Oligocene-Eocene level. In both A and B accumulations can be noted, an increase of methane amount relative to C2-C5 and other heavy compounds.
471. Accumulations in the Maastrichtian-Campanian interval. In all accumulations of this interval it is possible to recognize an increase in light compounds (methane) relative to heavy compounds (C15+, C6-C14 and C2-C5). These composition changes cause a decrease in liquid amounts and an increase in vapor phases (well evidenced in accumulation D) as well as an increase in API degree and GOR.
472. Accumulations in the Cenomanian-Santonian interval (north of the model). Accumulations A, B and C present high GOR and API degree in vapor phase and a composition based on methane (mainly coming from Coquinas SR). Liquid phases present heavy compounds (mainly from Coquinas too). Accumulation D shows only a Albian SR contribution with heavy compounds.
473. Accumulations in the Cenomanian-Santonian interval (south of the model). Accumulations A and D show contributions of pos-rift SR while accumulations B and C are rich in rift SR compounds.
474. Vapor and liquid accumulations in the Cenomanian-Santonian interval. Vapor accumulations exist mostly in the northern area, especially nearby Mexilhão field.
475. GOR values of the Cenomanian-Santonian accumulations define roughly domains liable to have liquid and vapor accumulations. The numbers refer to GOR values of the liquid phase of each accumulation. However, the numbers should not be taken as exact representations of the contents of the accumulations, but only their relative values. Three areas can be distinguished: the purple area contains accumulations with GOR between 200 and 300; the red one delimits accumulations with the highest GORs (>300 m3/m3) in the area. Only one accumulation (the one indicated by GOR = 13,722) holds vapor phase without a liquid phase.
476. Accumulations in the lower Albian Interval.
477. Accumulations in the pre-salt interval. Accumulations in this level present a mixture of hydrocarbons sourced fromthe Coquinas and Talc-Stevensite source rocks with predominance of the lowermost one.
478. Vapor and liquid accumulations in the pre-salt interval. As in the Cenomanian-Santonian interval, it is possible to verify a smooth trend of vapor accumulations to the north of the studied area, especially nearby the Mexilhão field.
479. Map of highly saturated areas (>50% of petroleum saturations) for different reservoir intervals. These areas with saturations complement the accumulations shown in previous figures. They are potential reservoirs with porosities and permeabilites not as good as the accumulations shown in red and green in previous figures.
480. Accumulated volumes in each layer of the model (First Scenario). Note the larger volumes associated with the Cenom_Santonian, Lower Albian and Pre-Salt Reservoirs. Values are expressed in billion of barrels.
481. Accumulated volumes in the model layers (Second Scenario). Note the larger volumes associated with the Cenom_Santonian, Lower Albian and Pre-Salt layers. Values are expressed in billion of barrels.
482. Compositional contribution of each source rock (Talc-Stevensite, Coquinas, Albian and Cenomanian-Turonian) to to reservoir filling (First Scenario).
483. Compositional contribution of each source rock (Talc-Stevensite, Coquinas, Albian and Cenomanian-Turonian) to reservoir filling (Second Scenario).
484. Graph showing the cumulative volumes for first scenario (left side) and second scenario (right side). Purple curve means the total generated volumes; blue curve represents the total expelled and brown curve is the total accumulated. All volumes are expressed in Bbbls.
485. Graph showing generated and expelled volumes by event for the first scenario (left side) and second scenario (right side). Purple bars mean generated volumes and blue bars represent the expelled volumes. All volumes are expressed in billion of barrels.
486. Showing (A) Gas prone Belt; (B) Belt with the Mexilhao type of hydrocarbons; (C) the rest is the most liquid prone belt.
487. The colored map represents depth in burial meters to the top Aptian reservoir. The yellow contour lines represent burial depths greater than 4500 meters. The pink lines represent salt windows. The light colored mask in the middle of the map surround areas where the Aptian reservoir is at temperatures greater than 140o Celsius.
488. Summary of the hydrocarbon exploration systems of the Santos Basin.
489. Risk map of post salt plays in the Central Santos Basin. Include the 8th and 9th bid round blocks.
490. Risk map of the pre- salt plays in the Central Santos Basin. Include the 8th and 9th bid round blocks.
491. Migration path for the Albian Cenomanian level in the Central Santos Basin, in the map the 9th bid round blocks.
492. Oil accumulation for the pre-salt play in the Central Santos Basin, in the map the 9th bid round blocks.
493. Salt map of the two projects: Central Santos in the west (large pink area) and Santos Blue Blocks (narrow purple strip in the east).
494. Horizon correlations between Central Santos (left) and Santos Blue Blocks studies (right). This division is based on initial interpreted horizons in Central Santos project.
495. Correlation between depth to base salt layer of the two projects. There are differences in the depth model of about 200 to 300m along the common border of the projects.
496. Map of the top of the Aptian source rock (scale in meters) showing that the mean difference values are about 500 m. Some portions can reach 1000 m of difference, especially in areas where the salt layer is very thick and seismic quality decreases.
497. Map of the top of Barremian source rock (scale in meters). It is important to note the coherency between the structures in both maps.
498. Map of top of the basement (scale in meters).
499. Salt windows at 100 Ma.
500. Salt windows at 89 Ma.
501. Salt windows at 72.5 Ma.
502. Salt windows at 65 Ma. The salt windows in the two projects seem coherent at this time, but note that there are already more gas accumulations in the Blue Blocks side.
503. Salt windows at 35 Ma.
504. Salt windows at 12 Ma.
505. Salt geometry at present day. Note that the Central Santos Project predicts more liquid accumulations whereas many more gas accumulations are predicted in the Blue Blocks project.
506. Heat flow and temperature histories through time for the Central Santos and Blue Blocks models.
507. Heat flow at 132 Ma.
508. Heat flow at 112 Ma.
509. Heat flow at 100 Ma.
510. Heat flow at 65 Ma.
511. Heat flow at 35 Ma.
512. Present day heat flow.
513. Transformation ratio map of the Barremian source rocks, showing consistent correlation between two projects, except in areas where the salt layer is very thick. N-S white lines near the common border the models represent the places where transformation ratio and bulk generation rate profiles were extracted.
514. Transformation ratio map of the Aptian source rocks, where the same behavior of Barremian source rocks can be seen. N-S white lines near the common border the models represent the places where transformation ratio and bulk generation rate profiles were extracted.
515. Transformation ratio map of the Albian source rock. N-S white lines near the common border the models represent the places where transformation ratio and bulk generation rate profiles were extracted.
516. Transformation ratio map of the Cenomanian source rock N-S white lines near the common border the models represent the places where transformation ratio and bulk generation rate profiles were extracted.
517. Transformation ratio and bulk generation rate of the Barremian source rocks in the border of the two models. In this region expulsion peaks (greater than 20% of transformation ratio) vary from 118 to 98 Ma in the Santos Blue Blocks models and 96 Ma in Central Santos model.
518. Transformation ratio and bulk generation rate of the Aptian source rocks in the border of the two models. A well defined expulsion peak can be seen in the Central Santos Model (around 95 Ma) whereas in the Santos Blue Blocks models a wide range of expulsion can be defined (from 115 to 70 Ma).
519. Transformation ratio and bulk generation rate of the Albian source rocks for both projects.
520. Transformation ratio and bulk generation rate of the Cenomanian source rocks in the border of the two models.
521. Accumulations in the Oligocene-Eocene interval. Vapor phase of accumulations C, D and E (inside of the Santos Blue Blocks study) presents high methane content (50 to 70%) associated with high API degree and elevated GOR, and liquid phases are composed mainly by C10+ compounds.
522. Accumulations in the Maastrichtian-Campanian interval. Accumulations E and F presents high GOR and API values and vapor phases are composed mainly by methane. Liquid accumulations are based on C10+ compounds.
523. Accumulations in the Cenomanian-Santonian interval.
524. Accumulations in the Lower-Albian interval.
525. Saturations in the Lower Albian interval. Note the saturations are high between blocks 413 and 516.
526. Saturations in the Pre-Salt layers. In blocks 413 and 516 large areas of the pre-sal layers are saturated with hydrocarbons.