The 3D model area is located in the Cabo Frio High region, which separates the Campos from the Santos basin. It incorporates several oil fields (Peregrino, Para-Terra, Maromba, Polvo and Carataí) and the exploration blocks offered by ANP in the previous 9th BID round.

The model was built based on structural depth maps, facies maps, well data and on well logs. The calibration of the modeled results was based on geochemistry data, temperature data and on oils shows of the wells.

Nine distinct depth maps were utilized to build the 3-dimensional model. The initial mapped horizons were used to create 24 individual layers derived from an analysis of the relative thicknesses of selected wells. Absolute ages were based on well data and on the stratigraphic chart of the Campos Basin.

1. INTRODUCTION
2. REGIONAL CONTEXT: THE GREAT CAMPOS BASIN
   1. TECTONIC-SEDIMENTARY EVOLUTION
      1. TECTONIC EVOLUTION
      2. MAIN SEDIMENTARY EVOLUTION
   2. PETROLEUM SYSTEMS
3. GEOLOGIC ASSESSMENT OF THE STUDY AREA
   1. TECTONIC FRAMEWORK
   2. STRATIGRAPHIC ASSESSMENT AND SEISMIC MAPPING
   3. MAGMATISM
4. SOURCE ROCKS, OILS AND CONDENSATES
   1. INTRODUCTION
   2. HYDROCARBONS SOURCE ROCKS
   3. OIL CHARACTERIZATION
   4. OIL QUALITY ASSESSMENT IN THE CABO FRIO AREA
5. ACCUMULATION MODELS AND LEADS CHARACTERIZATION
   1. ACCUMULATION MODELS
   2. LEADS CHARACTERIZATION
6. 3D PETROLEUM SYSTEM MODELLING
   1. INTRODUCTION
   2. BUILDING THE MODEL
      1. GEOMETRY, STRATIGRAPHY AND LITHOLOGIES
      2. SALT DISTRIBUTION
      3. SOURCE ROCK LAYERS
      4. BOUNDARY CONDITIONS
   3. TEMPERATURE AND MATURITY MODELING RESULTS
   4. GENERATION MODELING RESULTS
   5. PETROLEUM MIGRATION AND ACCUMULATION
      1. ACCUMULATIONS IN THE STROMATOLITE RESERVOIRS
      2. ACCUMULATION IN THE APTIAN RESERVOIRS
      3. ACCUMULATION IN THE BARREMIAN RESERVOIRS
      4. ACCUMULATIONS IN POST-SALT LAYERS
      5. PETROLEUM SYSTEM MASS BALANCE
7. EXPLORATORY RISK ANALYSES
8. GENERAL CONCLUSIONS
9. REFERENCE

1. Bathymetry map of the Santos, Campos and Espírito Santo basins (“Great Campos Basin” petroleum province) showing the location of oil field ring fences.
2. Tectonic framework of the “Great Campos” region.
3. Stratigraphic correlation among the basins of the “Great Campos” petroleum province. Stratigraphic charts modified from Feijo (1994).
4. Location map of the study area.
5. Free-air gravity map (a) of the northern Santos and southern Campos basins region and adjoining onshore area, and the respective structural interpretation (b).
6. Total magnetic intensity map (a) of the northern Santos and southern Campos basins region and adjoining basement area, and its structural interpretation (b).
7. Regional tectonic framework of the northern Santos and southern Campos basins region and adjoining onshore area. Tertiary alkaline igneous intrusions are represented by small green circles.
8. Location map of studied wells and stratigraphic sections (S1 to S6) performed in the study area.
9. Strike stratigraphic section number 2 (S2 in the map of Fig. 3.5).
10. Dip stratigraphic section number 3 (S3 in the map of Fig. 3.5).
11. Stratigraphic columns showing the position of mapped stratigraphic horizons.
12. Location map of the study area showing the seismic lines and wells used.
13. Interpreted seismic section illustrating traced horizons in the Cabo Frio project. (a) Time migrated seismic section. (b) Geologic interpretation based on seismic section, demonstrating stratigraphic and structural relations in the area.
14. Interpreted seismic section, illustrating tracked horizons in Cabo Frio project. (a) time migrated seismic section. (b) geologic interpretation based on seismic section, demonstrating stratigraphic and structural relations in the area. Note in this figure the complex arrangement of horsts and grabens of rift section. In the grabens occur the Lagoa Feia source rocks, and in the highs, stromatolites and coquinas reservoirs from the same play. Other peculiarity of this section is in demonstrating features imposed by halo-kinesis in the post-rift section of Campos Basin, such as huge anticlines (rollovers), mini-basins, listric faults and salt diapirs.
15. interpreted seismic section in NE-SW direction, illustrating horizons tracked in the Cabo Frio project. (a) Time migrated seismic section. (b) Geologic interpretation based on seismic section, demonstrating stratigraphic and structural relations in the area. The grey square in (b) limits a volcanic cone from the Eocene, which was drilled by the well 1-RJS-125RJ.
16. interpreted seismic section, in NW-SE direction, illustrating tracked horizons in the deep water of the Cabo Frio project. (a) time migrated seismic section. (b) geologic interpretation based on seismic section demonstrating stratigraphic and structural relations in the area. Note the impedance contrasts producing strong amplitude anomalies(a). Those anomalies are associated with volcanic rocks from Upper Cretaceous, which were drilled by well 1-RJS-567-RJ.
17. Bathymetry map of the study area in the Cabo Frio High region.
18. Structural depth map of the Mid Miocene horizon in the study area of the Cabo Frio High region.
19. Structural depth map of the Blue Marker horizon in the study area of the Cabo Frio High region.
20. Structural depth map of the Mid Eocene (Pebbly) horizon in the study area of the Cabo Frio High region.
21. Structural depth map of the top of “seismic” Cretaceous horizon in the study area of the Cabo Frio High region.
22. Structural depth map of the top of Macaé Formation horizon in the study area of the Cabo Frio High region.
23. Structural depth map of the top of evaporites horizon in the study area of the Cabo Frio High region.
24. Structural depth map of the base of evaporites horizon in the study area of the Cabo Frio High region.
25. Structural depth map of the top of Buracica horizon in the study area of the Cabo Frio High region.
26. Diagram showing the methodology applied in the time to depth conversion of the seismic maps in the study area
27. Diagram showing the methodology applied in the time to depth conversion of the seismic maps in the study area.
28. Structural Map of distributions of volcanics Clastic in the Cabo Frio High study area.
29. Location map of the Cabo Frio Cluster area showing the oil field discovered up to now, seismic lines used, oil and rock wells used in this study.
30. Biomarker plot of the oils studied from the Cabo Frio area suggesting the dominance of lacustrine saline oils and the presence of the 1-RJS-155 oil considered to be a mixture of lacustrine saline with marine.
31. Schematic sedimentary column of the Lagoa Feia Formation (Modified from Dias et al.,1988). The best organic-rich sections of the Lagoa Feia Formation are the Coquinas and the Talc-Stevensite sequences.
32. Geochemical log typical of Campos Basin (3-BD-2 well) showing the stratigraphic position of the two very rich organic-rich layers of the Lagoa Feia Formation: the Upper Barremian Coquinas (C) and the Lower Barremian Talc-Stevensite (TS) sequences (Trindade et al., 1995).
33. Geochemical log of the 1-RJS-181B well from the Cabo Frio area, Southern Campos Basin showing the stratigraphic position of two very thin organic-rich layers of the Lagoa Feia Formation. These organic-rich sediments were deposited in lacustrine saline water during the Barremian time.
34. Geochemical log of the 1-RJS-231 well from the Cabo Frio area, Southern Campos Basin showing the presence of organic-poor layers of the Lagoa Feia Formation in the proximal areas of the paleolake.
35. Natural series of the organic-rich sediments of the Lagoa Feia Formation, in the study area showing two separate organic intervals of the potential source rocks of the Campos Basin. As can be noted, the organic-rich section belongs to the marine source rocks of the Cabo Frio Formation. By contrast, all the Lagoa Feia sediments are organic-poor, and therefore cannot be considered as source rock.
36. Coquinas source rock – Present day transformation ratio map.
37. Maturation map of the Coquinas source rock (%Ro)
38. Talc-Stevensite source rock – Transformation ratio map at present day.
39. Maturation map of the Talc-Stevensite source rock (%Ro).
40. Isopach map of the Albian source rock.
41. Transformation ratio map of the Albian source rock.
42. Maturation map of the Albian source rock (%Ro).
43. Oil sample location and oil type distribution in the Cabo Frio High Region of the Campos Basin for the present study. The typical lacustrine oils occur widespread in the area. The mixed oils (marine black oil mixed with lacustrine oils) are associated with the well 1RJS 0555 and show a high level of both recent and paleo biodegradation.
44. Gas chromatograms of oils of the Cabo Frio High Region of the Campos Basin for the present study, showing bimodal n-alkane distributions typical of the lacustrine oils. The oils that present preserved n-alkane distributions are mixture of biodegraded and non biodegraded oils, derived from more than one migration pulse. The mixed oil from 1RJS 0555 shows a high level both recent and paleo biodegradation.
45. M/z 191 mass fragmentograms (terpanes) of oils representative of the oil types present in the Cabo Frio High region. Note that the lacustrine oils show very similar distributions of both tricyclic and pentacyclic terpanes. The mixed oil from 1RJS 0555 shows high tricyclic terpane concentrations (from the extensive biodegradation) and a higher Ts/Tm value. However, it also shows a high gammacerane value, suggesting an important lacustrine contribution.
46. M/z 217 mass fragmentograms (steranes) of oils representative of the oil types present in the Cabo Frio High region. Note that the lacustrine oils show very similar distributions (i.e. low diasteranes/regular steranes, very high C27/C29 steranes and a high abundance of methyl steranes). The mixed oil from 1RJS 0555 shows a lower C27/C29 sterane ratio and a higher diasteranes/regular ratio and much lower abundance of methyl steranes). However, it does show a minor methyl sterane abundance, suggesting an important lacustrine contribution
47. M/z 259 mass fragmentograms of oils showing the correlation between the TPP polyprenoids with the C27 diasteranes. In lacustrine oils the TPP compounds are much higher than in the mixed ones. As can be observed in the oils from 1RJS 0555 the ratio has an intermediate value suggesting that it is mixed.
48. M/z 231 mass fragmentograms showing the differences, in the C29 Triaromatic compound distributions among the lacustrine and the mixed oils. Note that the lacustrine oil present high abundance of C29 Triaromatic compounds when compared with the mixed oil from 1RJS 0555.
49. M/z 245 mass fragmentograms of oils, showing the differences, in the triaromatic distributions among the lacustrine and the mixed, oils. Note that the lacustrine oil present very low 3 Methyl/4 Methyl ratios. On the other hand, the oils from 1RJS 0555 present higher 3 Methyl/4 Methyl ratios that suggests a mixed contribution. It is important to mention that the Triaromatic steranes are very resistant to biodegradation and thermal evolution and therefore are present in light oils and condensates.
50. Plot of Hopane/ Sterane ratio versus TPP polyprenoids index for oils from the Cabo Frio High region. Note the good separation among the lacustrine and marine oil types. The oils from 1RJS 0555 fall into the mixed source region of the cross plot. The Hopane/ sterane ratio is a good biomarker parameter for distinguish lacustrine from marine oils.
51. Plot of Hopane/sterane ratio versus 3 / 4 Methyl Triaromatic ratios for oils from the Cabo Frio High region. Note the differences among the lacustrine versus the marine oils and the presence of the mixed oils. As can be noted, the oils from 1RJS 0555 are in the mixed source area.
52. Whole oil gas chromatograms showing different degree of biodegradation. In general, the varying degrees of alteration by bacteria reduce the API gravity, increase the oil viscosity, change the ratio n-C17/ Pr and reduce the concentration of oil paraffin. Note that the Pr/Ph ratio is very similar throughout the oils, and it is very resistant to biodegradation when compared to the n-alkanes (Taken from Peters & Moldowan, 1992).
53. Diagram showing the extent of petroleum biodegradation ranked using biological markers. Observe that the 25 Norhopane are formed after all the destruction of the n and iso-alkanes. Also, the most resistant biomarkers are the terpanes and the aromatics (Taken from Peters & Moldowan, 1992).
54. Oils from Campos Basin showing different stages of biodegradation and oil mixing. As can be observed the oil from 7-RO-8-RJS (3209m) was severely biodegraded but it has received recent charges of fresh light n-alkanes. The oil from 7-RO-8-RJS (3426m) was severely biodegraded then mixed with fresh oil giving oil with a bimodal feature. By contrast, the oil from RJS-312D is a severe pale biodegraded mixed oil, which suffered recent biodegradation (Soldan et al., 1993).
55. Map showing the oil biodegradation distribution using the ratio 25-norhpane/30hopane in Campos Basin. The distribution suggests a complex migration history with multiple charges from the same source rock. The final composition of the oils from Campos Basin represents a mixture of pulses of oil generated at the early and late stages of the oil window (Taken from HRT Multiclient Project).
56. Whole oil GC traces of oils from the Cabo Frio study area, showing different levels of recent biodegradation. Note that the oil from 1RJS 0104 is the most biodegraded followed by 1RJS 0529D and 1RJS 0455 shows the least biodegradation.
57. m/z 191 (terpanes) chromatograms of oils from the Cabo Frio study area, showing different levels of paleo biodegradation. Note that the oil from 1RJS 0529D exhibits the most paleo biodegradation followed by 1RJS 0104 and 1RJS 0455.
58. m/z 217 (steranes) chromatograms of oils from the Cabo Frio study area, showing different levels of thermal evolution, using the C27 (S/S+R) and C27 /R ratios. Note that the oil from 1RJS 0455 exhibits the highest thermal evolution followed by 1RJS 0104 and 1RJS 0529D.
59. C27 αββ/ (ααα+αββ) versus C27 20S/(20S + 20R) steranes for oils from the Cabo Frio High region. Note the low thermal maturity of oils such as 3RJS 0614 and 3RJS 0613 and the much higher thermal maturity of the oils from 1RJS 0555.
60. Contour map of the C27 (S/S+R) sterane ratios in the study area. As can be seen the oils which show the highest thermal evolution and highest quality are in the north east (i.e. 1RJS 0365) and in the deep water parts of the area (i.e. 1RJS 0555).
61. 25-norhopane/Hopane versus nC17/pristane content of the Cabo Frio High region. Most oils show minor to major levels of Recent biodegradation (nC17/pristine values of 1 or less) and minor to high levels of paleobiodegradation (25-norhopane/hopane values of 1 or higher). The most highly degraded oils (both recent and paleobiodegradation) are the oils from 1-TFE-1RJS and 1RJS 0555.
62. API Gravity versus %S content of the Cabo Frio High region oils. Note that many of the lacustrine oils are biodegraded and show API gravities of less than 25o. The oils from 1RJS 0555 show API valuesf >25o.
63. Contour map of the API gravity of oils in the Cabo Frio area. As can be seen the oils which show the highest quality are in the north east (i.e. 1RJS 0365) and in the deep water parts of the area (1RJS 0555).
64. Contour map of the %S in the oils in the Cabo Frio study area. As can be seen the oils which show the highest quality are in the north east (i.e. 1RJS 0365) and in the deep water parts of the area (1RJS 0555).
65. Cross plot of the ratio of 25norhopane/Hopane versus depth for the Cabo Frio oils. Note that the highest levels of paleobiodegradation were observed in the oils from 1RJS 0555 and 1RJS 0365. However, these oils show the highest quality from API values and %S contents.
66. Cross plot of the ratio of nC17/Pristane versus depth for the Cabo Frio oils. Note that there is no correlation in the level of recent biodegradation with depth. For example, some oils with a lower reservoir depth (1RJS 0433) show higher levels of recent biodegradation than samples at a lower reservoir depth (1RJS 0104).
67. Plot of diamondoids and sterane data from condensate and oils from the Greater Campos Basin. As can be observed the oils 3RJS 0613, 1RJS 0492, 1-ENC-1 and 3-ENC-2 from the Cabo Frio High region are typical non cracked lacustrine derived oils. As can be noted, the studied oils do not present evidence of oil cracking, and its last migration pulse was expelled before peak stage of generation. In the area, this is equivalent for a pod of generation buried at least to 5,000m (See, Mello et al., 2003; Petroleum System of Campos Basin).
68. Seismic expression of Papa Terra field
69. Schematic model of Tubarão Field
70. Seismic line over the block 594, with structural trap like Tubarão Field
71. Schematic model of Merluza Field
72. Seismic line over the block 532, with structural trap like Merluza Field
73. Leads characterization of the blocks 622, 651
74. Leads characterization of the blocks 620,591, 560, 528
75. Leads characterization of the blocks 592
76. Leads characterization of the blocks 649, 594, 533
77. Leads characterization of the blocks 621, 593
78. Leads Characterization of the blocks 497, 465, 432, 498
79. Leads characterization of the blocks 529, 530
80. Leads characterization of the blocks 466 and 431
81. Leads characterization of the blocks 564 and 596
82. Leads characterization of the block 532
83. Leads characterization of the block 467
84. Leads characterization of the block 499
85. Geological ranking blocks for Cabo Frio area
86. Ranking of the blocks without Petroleum Modelling
87. The large rectangle is the modeled area. The oil fields are located within the irregularly shaped blocks and blocks offered in 9th ANP Bid Round are in red.
88. Stratigraphic column showing the original nine (white lines) mapped horizons used to build the model.
89. General SW view of the 3D model, depicting the geometry of the stratigraphic layers cross the study area.
90. Facies distribution assigned to the Lower Barremian and Barremian source rocks.
91. Facies distribution assigned to the Aptian, Aptian source rocks, Coquinas reservoir and upper Aptian layer.
92. Facies distribution assigned to the Stromatolite, Salt, Lower Albian, and Albian source rocks layers.
93. Facies distribution assigned to the Upper Albian, Cenomanian-Turonian source Rocks and Upper Cenomanian-Turonian layer.
94. Facies distribution assigned to the Upper Cenomanian-Turonian, Coniacian, Lower Maastrichtian and Upper Maastrichtian layer.
95. Facies distribution assigned to the Cretaceous Seal, Paleocene, Eocene and Oligocene-Miocene layer.
96. Distribution of the Eocene and Late Cretaceous volcanic rocks.
97. 3D image of the salt layer at the end of the salt deposition (112 Ma).
98. 3D image of the salt layer at present day (0 Ma).
99. Maps of the salt geometry from 112 Ma to 65.5 Ma.
100. Maps of the salt geometry from 32 Ma to 0 Ma.
101. General view of the model at present day showing the stratigraphic distribution of the four source rocks layers.
102. Heat flow maps at 112 Ma and at present day. They were generated by the Crustal Heat Flow Tool available in PetroMod 10 that also calculates tectonic subsidence, crustal and mantle extension factors across the study area.
103. The continuous lines are temperature and vitrinite reflectance estimated by the model. The circles, with uncertainty bars, represent the measured values in the wells. The good match between observed and measured values is an assurance that the thermal boundary conditions applied in the model are valid for Cabo Frio area.
104. Present-day temperature field in the 3D model of southern Campos Basin.
105. Present-day maturity map of the Cenomanian-Turonian source rock.
106. Present-day maturity map of the Albian “Bota” source rock.
107. Present-day maturity map (%Ro) of the Aptian “Coquinas” source rock.
108. Present-day maturity map of the Barremian “Talc-Stevensite” source rock.
109. Present-day transformation ratio map of the Cenomanian-Turonian source rock.
110. Present-day transformation ratio map of the Albian “Bota” source rock.
111. Present-day transformation ratio map of the Aptian “Coquinas” source rock.
112. Present-day transformation ratio of the Barremian “Talc-Stevensite” source rock.
113. Vapor and liquid accumulations of the stromatolites reservoirs at present day.
114. Vapour and liquid accumulations of the stromatolites reservoirs at present day, overlapped with the salt layer.
115. Vapor and liquid accumulations within the Aptian reservoirs at present day.
116. Vapour and liquid accumulations at present day.
117. Bulk composition of the vapor and the liquid accumulations of the Barremian reservoirs at present day.
118. Migration flow paths and accumulations at 96.6 Ma.
119. Migration flow paths and accumulations at 93 Ma.
120. Migration flow paths and accumulations at 91.5 Ma.
121. Migration flow paths and accumulations at 83 Ma.
122. Migration flow paths and accumulations at 70 Ma.
123. Migration flow paths and accumulations at 66 Ma.
124. Migration flow paths and accumulations at 65.5 Ma.
125. Migration flow paths and accumulations at 48 Ma.
126. Migration flow paths and accumulations at 32 Ma.
127. Migration flow paths and accumulations at 11.7 Ma.
128. Migration flow paths and accumulations at present day.
129. Accumulations in the Maastrichtian Reservoir at 66Ma.
130. Accumulations in the Maastrichtian Reservoir at 65.5 Ma.
131. Accumulations at 48 Ma (on the left). The figure on the right represents a snapshot at 40 Ma of an alternative scenario in which we introduced some sealing facies along the slope.
132. Accumulations at 32 Ma. Note that some accumulations formed in the north part of the area.
133. Accumulations at 15 Ma (on the left). The pink line indicates the border of the salt layer during most of the history of the studied area. The figure on the right represents a snapshot at 11.7 Ma of an alternative scenario in which we introduced some sealing facies along the slope.
134. Accumulations formed at 7.5 Ma. Note that only small stratigraphic traps remained along the western border of the area.
135. Accumulations predicted for the present day (on the left). The figure on the right represents a snapshot for the present day of an alternative scenario in which we introduced some sealing facies along the slope. Note that some accumulations formed in Blocks 649 and 564.
136. Accumulations formed at 68 Ma. Note the high convergence of hydrocarbons towards the area of Peregrino Field.
137. Accumulations formed at 48 Ma. Note that the most important accumulations are located nearby Block 529 and in Block 533.
138. Accumulations that formed and remained in the present day.
139. The accumulation in Xerelete Field (see inset) was not predicted by the model because it requires a highly effective vertical migration in order to get petroleum into the upper Cretaceous reservoirs. The petroleum did not reach the upper Cretaceous reservoirs in Xerelete Field even though there are salt windows and petroleum accumulations in the pre-salt reservoirs in the area (see the green accumulations in the enlarged figure).
140. Another view (from the side) of the Xerelete Field. The vertical arrows (in the right picture) indicate the dominant migration mechanism in the area.
141. History of reservoir filling of the Maastrichtian and Cenomanian-Turonian reservoirs.
142. Reservoir filling history of Albian reservoirs
143. Table with the results of the risk analyses for all blocks of the 9th Bid round of the Cabo Frio area. The analysis includes all plays of the area. The values on the rightmost column (“success”) result from the multiplication of the other columns, which represent each element of the petroleum system.
144. . Map of exploratory risk analyses for Cabo Frio area. (A) Ranking based only on the presence of the elements of the petroleum systems. (B) Ranking based on risk analyses but it is not integrated with petroleum modelling results.
145. Map of exploratory risk analyses integrated with petroleum modeling for Cabo Frio area. This figure represents the blocks that show petroleum accumulations at the Albian and Upper Cretaceous level
146. Map of exploratory risk analyses integrated with petroleum modeling for Cabo Frio area. This figure represents the blocks that show petroleum accumulation at the Barremian level
147. Map of exploratory risk analyses integrated with petroleum modelling for Cabo Frio area. This figure represents the blocks that show petroleum accumulation at the Upper Cretaceous level