The tectonic stratigraphic record of offshore Ceará and Potiguar basins stacks the complete stages of a basin margin development (Rift, Transitional and Drift sequences). The evolution of these basins show significant horizontal tectonic movements during the rift phase associated with expressive volcanic activity during several periods. Igneous activities, many erosive events during the Drift phase, generated a basin with a very complex structural and stratigraphic configuration, and also created oil and gas exploratory opportunities.

This multiclient study is an example of an assessment of the risks linked to hydrocarbon accumulations in offshore area of Ceará and Potiguar Basins by the intricate process of hydrocarbons generation and migration from source to trap. This assessment has been highlighted by the application of full 3D Petroleum System Modeling of a large 3D geological framework built with intense use of seismic interpretation of dip and strike lines, well and geochemical data.

Integrated Petroleum Systems Modeling is considered today a core strategic technology for exploration risk assessments and exploratory decision support at all major petroleum E&P companies. This project is one of the most advanced and integrated petroleum system evaluation study ever performed in the Brazilian petroleum industry for the Equatorial Margin area.

Full references of all images are listed in the reports

1. Geology-Seismic-Geochemistry
   1. Regional Geology
      1. Introduction
      2. Tectonic and Stratigraphic Framework
         1. Rift Phase (Neocomian/Early Aptian)
         2. Transitional Phase (Late Aptian/Early Albian)
         3. Drift Phase (Early Albian to Recent)
   2. Exploration History of Offshore Ceará and Potiguar Basins – Efforts and Results
      1. Potiguar Basin
      2. Ceará Basin (Mundaú sub basin)
   3. Some Characteristics of Potiguar and Ceará Petroleum Fields
   4. Seismic Interpretation and Geological Characterization
      1. Rift Sequence
      2. Post-Rift Sequence
   5. Location of the Main Igneous Features in the Potiguar and Ceará Basins using Seismic and Potential Methods
      1. Original Data
      2. Processing and Interpretation
      3. Remarks
   6. Petroleum System Overview through Geochemistry of Source Rocks and Oils From Offshore Ceará and Potiguar Basins
   7. Source Rock Characterization
      1. Offshore Potiguar Basin Source Rocks
         1. Lacustrine Fresh to Brackish Water Pendência Source Rock System
         2. Lacustrine Brackish to Saline, Marine Hypersaline and Marine Anoxic Alagamar Source Rock System
      2. Ceará Basin (Mundaú Sub-basin) Source Rocks
         1. Lacustrine Fresh to Brackish Water Mundaú Source Rock System
         2. Marine Hypersaline Paracuru Source Rock System
         3. Marine Anoxic Ubarana Source Rock System
   8. Oil Characterization Overview
      1. Offshore Potiguar Oil Systems
         1. Characterization of the Oil Systems
         2. Biodegradation and Oil Quality
         3. Carbon Isotopic Signatures and n-alkanes distribution of the Oils
         4. Assignment of Oil Origin through Biomarkers Distribution
         5. Maturity Parameters and Oil Cracking
      2. Ceará Basin Oil Systems
         1. Characterization of the Oil Systems
         2. Biodegradation and Oil Quality
         3. Carbon Isotopic Signatures and n-Alkanes Distribution of the Oils
         4. Assignment of Oil Origin through Biomarkers Distribution
         5. Maturity Parameters and Oil Cracking
2. Modeling
   1. Introduction
   2. Objectives
   3. Model Input
      1. Geometry, Stratigraphy and Lithology
      2. Geological Dip and Strike Sections
      3. Faults
   4. Source Rocks
      1. Characteristics
      2. Kinetic Parameters
   5. Boundary Conditions
      1. Temperature at the Top of the Sediments
      2. Basal Heat Flow
   6. Calibration
   7. Maturity Results of the Source Rock
      1. Outline of the Petroleum Generation Kitchens – Based on Burial Maps
      2. Maturation of the Source Rocks
      3. Transformation Ratio of the Source Rocks
   8. Timing
   9. Temperature at the Top of the Main Reservoirs
      1. Campanian Reservoir
      2. Paracurú and Alagamar Reservoirs
   10. Porosity
       1. Campanian Reservoir
       2. Paracurú Reservoir
   11. Migration History and Accumulations in the Ceará Basin
       1. Campanian Reservoir
       2. Paracurú Reservoir
       3. Rift Reservoirs
   12. Migration History and Accumulations in the Ceará Basin Accumulations in the Potiguar Basin
       1. Cenomanian-Campanian Reservoirs
       2. Alagamar Reservoir
       3. Rift Reservoirs
   13. API Predicted in Oil Accumulations of the Campanian and Paracuru Reservoirs
   14. Calibration of the Predicted Hydrocarbon Properties in the Atum and Xaréu Fields
   15. Migration Paths of the Campanian and Paracuru Reservoir Levels
   16. Significance of Electromagnetic Anomalies (EM)
   17. Oil and Gas Volumes in the Main Reservoirs
       1. Lower Eocene-Maastrichtian Reservoir
       2. Campanian Reservoir
       3. Paracurú and Alagamar Reservoirs
   18. Integration of the Modeling Results with the Geochemistry Data
   19. Integration of the Modeling Predictions with Oil Slicks Results
   20. Mass Balance of the Petroleum System
   21. Detailed Evaluation of the Petroleum Systems by Means of the 2D Modeling
   22. Conclusions
   23. References

1. Location of the Ceará_Mundaú and Potiguar basins in the Brazilian Equatorial Margin
2. Ceará Basin and Sub-Basins – Location map and Structural Framework.
3. Brazilian Equatorial Margin Tectonic Evolution Phases – Conceptual model showing the dominant tectonic efforts through time.
4. Location of the seismic dataset (2D) and petroleum fields used in the study.
5. Stratigraphic Charts of Ceará and Potiguar basins – (Source Petrobras).
6. Tectonic and volcanism eventsin the Ceará-Mundaú and Potiguar Basins – (Source Petrobras).
7. Geological cross section (based on seismic and well data) in the proximal portions of the Ceará and Potiguar basins. The color scheme also allows clear correspondence of the formations between the two basins.
8. Geological cross section showing the rift, transitional and drift stratigraphic sections along Ceará (left) and Potiguar (right) basins in the distal portions.
9. Schematic geological cross section showing the Neocomian rift style and Pendência Fm in the Potiguar Basin..
10. Seismic cross section showing the rift style in deep water area of Potiguar Basin. The vertical scale is in depth (meters).
11. Geological cross section showing the Aptian rift style and sedimentary sequences of Mundaú Fm in the shallow water area of Ceará-Mundaú Basin
12. Seismic cross section showing the rift style in deep water area of the Ceará Basin.
13. Onshore portion of Potiguar Basin: Rift sedimentation model and structural style.
14. – Ubarana Field (in the center of the figure) – Geological cross section showing the Alagamar Petroleum System.
15. Depositional environment and facies distribution in the onshore and near shore Potiguar Basin areas, during the Transitional Phase. This model is considered valid for the offshore areas.
16. Ceará Basin – Seismic line illustrating the structural style (example: anticline feature limited by fault) and sedimentary characteristics of the Drift Sequence (turbidite distribution in the dominantly slope and basin shale sequences).
17. Depositional models during the Drift Phase of Potiguar Basins. The same model is valid for the Ceará Basin.
18. Location of all wells in Potiguar and Ceará basins.
19. Onshore and Offshore Potiguar Basin efforts in exploratory wells from 1956 until Oct/2017
20. History of the number of wells drilled in the Potiguar Basin (onshore + offshore) until 2017. Source: ANP/BDEP.
21. Number of exploratory wells drilled in offshore Potiguar Basin from 1956 until Oct/2017.
22. Ceará Basin efforts in exploratory wells from 1956 until Oct./2017.
23. Graphic of all wells drilled in the Ceará Basins (Mundaú; Icaraí, Acaraú and Piaui-Camocim sub-basins). Source: BrazilGeodata
24. Offshore petroleum fields: Xaréu, Atum, Espada and Curimã in Ceará-Mundaú Basin; and Dentão, Guaiuba, Pescada, Arabaiana, Salema Branca, Guajá, Biquara, Ubarana Oeste, Ubarana, Agulha, Cioba, Aratum e Siri fields in Potiguar Basin.
25. Xaréu Field historical data.
26. Atum Field historical data.
27. Espada Field historical data.
28. Curimã Field historical data. .
29. Pescada/Arabaiana and Ubarana Fields geological context (rift faults and canyons)
30. Schematic geological cross section showing the accumulation models for Pendência, Alagamar and Ubarana formations
31. Arabaiana Field – Structural geological section showing gas and oil accumulations in the Pendência, Pescada and Alagamar formations.
32. Ubarana Field – Detailed Structural Geological Section showing a rift fault and the Ubarana canyon (shales) providing updip trapping of the oil in the Alagamar Fm.
33. Dentão Field historical data.
34. Guaiuba Field historical data.
35. Pescada Field historical data.
36. Arabaiana Field historical data.
37. Salema Branca Field historical data.
38. Guajá Field historical data.
39. Biquara Field historical data.
40. Ubarana Field historical data.
41. Agulha Field historical data.
42. Siri Field historical data.
43. Aratum Field historical data.
44. Location of 2D seismic lines offshore Ceará and Potiguar Basins, in the states of Ceará and Rio Grande do Norte.
45. Stratigraphic chart of the Ceará Basin with identification of the mapped horizons to the left of the lithologic column.
46. Stratigraphic chart of the Potiguar Basin with identification of the mapped horizons at the left of the lithological column.
47. SW-NE Section in the Potiguar Basin individualizing the mapped sequences and the igneous-sedimentary high, Ceará Guyot at the extreme NE of the line. Note the tying well 1-CES-9-CE.
48. SW-NE seismic section at the central portion of the Potiguar Basin with the tying wells 1-CES-10-CE and 1-BRSA-69A.’
49. Seismic section of the Ceará-Mundaú Basin showing the rift style characterized by grabens and asymmetric half-grabens controlled by synthetic and antithetic faults. The thick sedimentary package present between the mapped basement and rift horizons suggests that the sin-rift section may be older then Barremian Age.
50. Structural contour map of the basement. The features of the rift-fault system are well marked in the map. The tectonic forces related to the Gondwana breakup created rotated blocks, grabens and horsts elongated NW/SE blocks of Ceará and Potiguar basins.
51. Characterization of the rift sequence in the Ceará Basin, where seismic facies show interbedded sedimentary and volcanic rocks. The synthetic and antithetic normal faults control the geometry of the horsts and grabens, with main strike to NE.
52. Depth map of the basement indicating five main structural compartments.
53. Isopach map of the rift section, showing how depocenters are restricted to troughs. Maximum thickness of the rift isopach is 6000m and it is locally thicker in the Ceará than in the Potiguar Basin.
54. The SW-NE Section of the Potiguar Basin, cutting the NW segment of the Ceará Guyot.
55. The SW-NE of the Potiguar Basin, cutting the SE segment of the Ceará Guyot.
56. The SW-NE Section to the extreme SE of the study area, the Potiguar Basin.
57. Characterization of the fluvial-deltaic deposits of the sequence II, with cuts by dykes and sills.
58. The top of the transitional sequence reveals the paleogeography of the Lower Albian forming en echelon pattern, indicating the active border tectonics.
59. Top of the rift structural map with input of volcanic highs (in brown). In the seaward low Northeast of Mundaú the transitional sequence reaches its maximum depths up to 9000m.
60. Thickness map between the Top of the Rift and the Albian horizons. Note the thickening of the sequence in the Potiguar and Mundaú Lows, southeast and northwest of the Ceará Guyot.
61. Albian-Cenomanian structural map. Note the greatest base depth of this sequence in the Mundaú Sub-basin, reaching 7000m, while the depocenter in the Potiguar Basin is at about 5500m.
62. Albian to Campanian thickness map. Note the thickening of this sequence to extreme northeast of the study area.
63. Campanian structural map reveals, as it was observed for the previous sequences, greater depths in the Mundaú Low, where it reaches 5,300m. Note the prominent excavations on the shelf edge and slope, especially in the Mundaú Sub-basin
64. Comparative chrono-stratigraphic chart between the sedimentary sequences and evolution history of the Ceará and Potiguar Basins.
65. Notice the sigmoidal- oblique clinoform that took place from the Maastrichtian from the Upper Oligocene the strata pattern is replaced by a prominent agradational component, moving into sigmoidal clinoforms.
66. The thickness map between the Campanian and Mid Eocene mapped horizons reveals the depocenters in the Mundaú and Potiguar Lows. Note the sedimentation filling canyons, observed in the base of this sequence (Figure 61) with the thickening in the troughs.
67. Seismic Dip Line SW-NE passing through the Ceará Guyot presenting an intense magmatic activity with a massive presence of dykes, sills and basalt flows.
68. Satellite image of the study area, from which, the bathymetry reveals the aligned highs present in the Brazilian equatorial margin. This lineament may have fracture opening, as suggested by the W-E lineaments in the oceanic bathymetry, or might related to the presence of hotspots. The lineament characterizes the relative movement of the South America Plate.
69. Middle Eocene structural map presents depths up to 4400m for deposition of the Oligocene-Eocene sequence in the Mundaú and Potiguar Lows. Observe several digs in the self edge and slope especially of the Mundaú Sub-basin.
70. The thickness map between the Middle Eocene and Upper Oligocene horizons reveals, as observed in previous sequences, that the greatest thicknesses are found in the depocenter of the Mundaú Sub-basin.
71. Tectonic evolution of the South Atlantic opening highlighting the location of the major transtensional faulting zones.
72. Intense transtensional faulting zones in the NW portion of the Potiguar Basin, where it is observed a hydrocarbon loss of the system (oil slicks).
73. Intense transtensional faulting zones become preferential zones of incisive canyons in the SE portion of the Ceará Basin, with hydrocarbon loss of the system (oil slicks).
74. The Upper Oligocene structural map showing depth up to 4000m from the Miocene sequence in the Mundaú and Potiguar Lows.
75. The thickness map between the Upper Oligocene and Lower Miocene mapped horizons reveals major thicknesses of the Miocene sequence reaching up to 1400 m.
76. Basalt flow present in the Albian-Campanian sequence fed by dykes that cut the overlapping sequences. This feature is located to the SE of the study area close to the CES-29 well, within the Petrobras blocks.
77. SW-NE geologic section in deep water to the NW of the Ceará Guyot, thus still in the igneous complex that originated this volcanic-sedimentary building. Note the cut features caused by the intrusion of several feeder dykes of expressive Eocene basalt flow.
78. SW to NE geologic section of the Ceará Guyot still in the igneous complex that originated this volcanic-hypabyssal-sedimentary building. Note slight basalt flows elongated to the SW of the major complex.
79. Lower Miocene structural map showing depositional depths up to 3500m of the Miocene sequence.
80. The thickness map between the Lower Miocene and Sea Bottom reveals intense accumulations in front of the igneous-sedimentary highs in both basins.
81. Present day – canyon associated with transtensional fault zones.
82. Bathymetry map showing water depth variation from few meters to 3000m in the study area. The depth in the Ceará Guyot does not overcome 200m. Note the incisive canyons in the slope in the whole extent of the study area.
83. Cut feature and canyon fill of the Miocene. Observe the amplitude anomaly in the basal portion of the canyon fill, likely associated with the sand deposition during the low standing system tract.
84. Schematic diagram of the erosional features observed in the study area, highlighting the deposition of fans rich in sand (cf. Richards et al., 1998).
85. Example of submarine canyon fill, as observed in Erro! Fonte de referência não encontrada., with two other common examples of autóctone slopes with spatial and temporal relation, as well as general architectures of facies. See Figure 83 (mod. de Galloway ,1998).
86. Example of deposition and processes observed in the slope. A) deposition pattern in offlap (TSNA/TSNB); B) deposition pattern in onlap (TSNB); C) diagram of processes which deposition is in onlap. See these features in Figure 83 (Rangel, 1984).
87. Progradational feature in offlap observed from the Campanian to Lower Miocene and the depositional pattern in onlap from the Lower Miocene to Recent. Patterns observed in small scale. In the detail, it is possible to visualize the stacking of these patterns within the mapped sequences.
88. Variation of the layer dips just by variation in the direction of the canyon fill. Note intense current incisive canyons.
89. Intense cut and filling features, with zoom (1) highlighting the channel stacking in the fault zones (black arrows)
90. Diagram block with distribution of the turbidite system elements: slide scar, mass movement deposits, submarine canyon, abandoned channel, deposit areas of overbank and lobes (cf. Normark et al., 1993).
91. Evolution of the sedimentary deposits produced by gravitational processes (cf. Selley, 1988).
92. Contour currents where the volcanic highs traps the currents to between themselves and the shelf. The current acceleration produces intense erosion.
93. Currents reworking the basin sediments to the slope, producing thin sedimentary deposits with major wavy stratification.
94. Map locating the position of dykes, sills, basalt flows and volcanic complexes. Where the incidence of dykes and volcanics are very intense, occur the constructions of igneous-sedimentary buildings (e. g. Ceará Guyot). The scale of colors defines the depth of the mapped dykes and sills (700 a 7000m). Note the intense igneous activity present in the whole extension of the study area, as well as in varied depths.
95. . Location map of the Potiguar and Ceará Offshore rock samples analysed in this study.
96. Geochemical Well Log exemplifying the Pendência offshore source rock characteristics (see Figure 95 to assess the well location). Note the complete transformation and expulsion of hydrocarbons below 2700m and the organic rich interval (TOC averaging 4%), corresponding to the overlying Camadas Ponta do Tubarão Member of Alagamar Fm.
97. Van Krevelen diagram of the Pendência Formation displaying the organic matter type
98. Thickness map (in meters) of the Pendência Source Interval. In this map, it was considered only the sum of shale intervals with TOC>1%.
99. Total Organic Carbon (TOC) Content Map of the Pendência Source Interval. Note that the TOC variation is considered as the most frequent average values for TOC >1% in each analyzed Pendência Interval .
100. Hydrogen Index (HI – mgHC/gTOC) Map of the Pendência Source Interval. Note that the HI is considered as the average values that occur in larger distribution in each analyzed well.
101. Generation Potential (S2 – mgHC/gRock) Map of the Pendência Source Interval. Note that the S2 variation is considered as the average values that occur in larger distribution in each analyzed well.
102. Natural Series Plot of the Offshore Pendência samples. Potiguar Basin
103. Map of the TMAX values for the Pendencia Fm samples. It is considered the most frequent average values for the source intervals (COT>1%) within each analyzed well.
104. Geochemical log of the 1CES 0121CE well (see Figure 95 to assess the well location) showing the organic-rich sediments of the Alagamar Formation composed of CPT and Upanema Members. Observe the distinction between the Camadas Ponta do Tubarão (upper part) and Upanema organic-rich sediments (lower part).
105. Van Krevelen diagram of the Alagamar Formation displaying the organic matter type of these source rocks.
106. Thickness map(in meters) of the Alagamar Source Interval. In this map, it was considered only the sum of shale intervals with TOC >1%.
107. Total Organic Carbon (TOC) Content Map of the Alagamar Source Interval. Note that the TOC variation is considered as the most frequent average values for TOC >1% in the considered Alagamar interval.
108. Hydrogen Index (HI – mgHC/gTOC) Map of the Alagamar Source Interval. Note that the HI variation is considered as the most frequent average values for TOC >1% in the considered Alagamar interval
109. Hydrocarbon Potential (S2– mgHC/gRock) of the Alagamar Source Interval.
110. Natural series Plot of the Offshore Alagamar samples. Potiguar Basin.
111. Map of the TMAX values for the Alagamar Fm samples.
112. Geochemical Log of the 1CES 0015CE well (see Figure 95 to assess well location) highlighting the source characteritics of the Mundaú Fm.
113. Van Krevelen diagram of the Mundaú Formation displaying the organic matter type of this source unit.
114. Natural series Plot of Offshore Mundaú rock samples. Mundaú Sub-basin of the Ceará Basin.
115. Source Rock extract of a Mundaú shale (After Mello 1988).
116. Van Krevelen diagram of the Paracuru Formation displaying the organic matter type of this source unit.
117. Geochemical Log of the 1CES 0008 CE well (see Figure 95 to assess well location) highlighting the source characteritics of the Paracuru Fm.
118. Geochemical Log of the 1CES 0042A CE well (see Figure 95 to assess well location) highlighting the source characteritics of the Paracuru Fm.
119. Thickness map of the Paracuru Source Interval. In this map it was considered only the sum of shale intervals with TOC >1%.
120. Total Organic Carbon (TOC) Content Map of the Paracuru Source Interval. Note that the geochemical characteristics of the Paracuru source rocks seem to be inversely proportional to its thickness. Since it can be observed a TOC variation within each well according to the depth and facies overlapping. Here it is considered the most frequent average values for TOC >1% in the considered Paracuru interval.
121. Hydrogen Index (HI) Map of the Paracuru Source Interval. Note that the geochemical characteristics of the Paracuru source rocks seem to be inversely proportional to its thickness. Note that the HI variation is considered as the average values that occur in larger distribution in each analyzed well.
122. Map of the TMAX values for the Paracuru Fm samples. Here it is considered only the most frequent average values for the source intervals (TOC >1%) within each analyzed well.
123. Natural series Plot of Offshore Paracuru samples. Mundaú Sub-basin of the Ceará Basin
124. Source rock extract of the Paracuru Fm.(After Mello 1988)
125. Geochemical Log of the 1CES 0050 CE well (see Figure 95 to assess well location) highlighting the geochemical characteritics of the Ubarana Fm
126. Van Krevelen diagram of the Ubarana Formation displaying the organic matter type of these source rocks.
127. Natural Series Plot of Offshore Ubarana Fm. Mundaú Sub-basin of the Ceará Basin
128. Location map of the Potiguar and Ceará Offshore oil samples used in this study.
129. Oil Types and Reservoir Intervals around the Potiguar Basin. Observe the widespread occurrence of the marine hypersaline sourced oils.
130. API gravity map of the analyzed oils distributed along the offshore portion of Potiguar basin. In the presented zoom of the area of the Ubarana field can be easily identified a decrease of API values towards the shallow platform area, as a result of the long distance migration and biodegradation processes.
131. Sulfur content of the analyzed oils along the offshore portion of Potiguar basin. Note the consistency between the sulphur content and the API values shown in the Figure 134.
132. API gravity versus Reservoir Depth. Note that that there is a continuous increase in the oil quality (linked to the API values) according the increasing depth.
133. Sulfur Content versus reservoir depth. Note that that there is a continuous decrease of the Sulfur content according the increasing depth. This is consistent with the paleobiodegradation and recent biodegradation diagrams versus depths of the Figure 138 and Figure 139.
134. Oil Quality Diagram for the Potiguar Oil Samples. In a general way, the oil quality in Potiguar oils is not a major problem in the basin. The lacustrine freshwater oils (sourced by Pendência Source rocks) and the marine anoxic oils (sourced by Galinhos Source rocks) present better quality in relation to the marine hypersaline ones. Lacustrine/marine oil mixtures present a wider range of oil quality according the end members oil that represents the major contribution to the mixture. Note that the marine hypersaline oils that present low sulphur contents and API higher than 30 possibly can be faced as oil mixtures of the Alagamar source rock members.
135. Biodegradation Assessment Diagram of the Potiguar Oil Samples. Note that most of the Potiguar oils have suffered different levels of paleobiodegradation and that the the lower biodegradation degrees are associated to the marine anoxic oils.
136. Potiguar Basin paleobiodegradation Map (measured by the ratio 25norhopane/hopane). Note the relation between the biodegradation and the oil quality maps shown in the Figure 130 and Figure 131. The more biodegraded oils are located in the shallower reservoirs in most proximal areas making a decrease in the oil quality.
137. Potiguar Basin Recent Biodegradation Map (measured by the ratio between the isoprenoid Pristane over nC17). The tendency of the increase of the biodegradation towards the northwest and shalllower areas.
138. Degree of Paleobiodegradation according the reservoir depth (25-norhopane/hopane versus depth). Note that shallower reservoirs present a major degree of paleobiodegradation.
139. Degree of Recent biodegradation (Pri/nC17) according the reservoir depth. It can be observed that bellow 2000m all reservoirs have been preserved from recent biodegradation, presenting good quality oil (see Figure 132 and Figure 133). On the other side, the presence of very high Pri/nC17 in the samples 1CES 0125 CE and 1CES 140 CE indicates that the biodegradation are still in course.
140. Whole oil and terpane traces (m/z 191) of the well 3RNS 0074RN exemplifying an marine hypersaline and Lacustrine freshwater oil mixture that have experienced different levels of biodegradation. This is indicated by the preservation of the n-alkanes, presence of very high UCM compounds, high pristane/ n-C17 ratios and high abundances of nuclear demethylated hopanes (25-norhopanes).
141. Plots of δC13 of the whole oil versus the Pristane over Phytane ratio. The lacustrine freshwater oils sourced by Pendência Fm. can readly be identified by light dC13 values whereas some marine anoxic oils are very heavy. Pristane over phytane ratio is also very useful in oil origin assessment. Note that most of the marine hypersaline oils present Pri/Phy ratio lower than 1, the lacustrine freshwater oils present the Pri/Phy higher than 2, whereas greater part of the oil mixes present intermediary values ranging from 1.5 to 2.5.
142. Gas chromatograms of the oil types of the Potiguar Basin. Keep in mind that biodegradation, thermal evolution and oil mixing can alter the GC profile.
143. Plots of Hopane/ Sterane versus Pristane/ Phytane ratios from the oils analyzed of the Potiguar basin. Note that the lacustrine oils, as reported by Mello (1988), present the highest pristane/phytane and hopane/steranes ratios when compared with the marine hypersaline ones that agglutinate themselves characterizing a very distinct oil family. A few mixed oils show intermediate values that can be close to the observed in marine oils or not, this could indicate a larger lacustrine fresh to Brackish or marine or “marine hypersaline” effects in those particular oils.
144. δC13 of the whole oil versus the Ts/Tm ratio of the Potiguar oil samples. Observe that in all marine samples, conversely to lacustrine oils, there is a dominance of Tm (C27 18α-trisnorhopane) over Ts(C27 17α-trisnorhopane).
145. Gammacerane Index versus Hopane/Sterane ratio. Interestingly, the oils from the wells 1RNS 0077RN, 1 RNS 0013RN, 4 RNS 0081RN, 3RNS 0047 RN and 7UB 0023D RN appear to represent a lacustrine source environment, although they gammacerane index higher than 0.4 and the oils from the wells 1RNS 0071 RN and 1RNS 0137 RN appear to be marine even with low gammacerane index. These features are a result of oil mixing (lacustrine plus marine) and thermal stress affecting the molecular ratios. Indeed such mixtures are present in most of the oils analyzed in this study, since it is common the superposition of their three petroleum systems in most part of the basin.
146. Gammacerane index versus C34/C35 hopanes from the analyzed oils in Potiguar Basin. Note that the lacustrine oils and marine anoxic oils present low gammacerane/Hopane ratios when compared with the marine hypersaline oils. Therefore, the gammacerane index is very effective in differentiating most marine hypersaline CPT oils from those marine oils derived from the Galinhos source rocks. Also The C34/C35 hopanes, allows a good the separation among Marine anoxic oils and Lacustrine oils. Indeed it is clear the individualization of three oil families (the lacustrine, the marine anoxic and the marine hypersaline). Nevertheless, the mixed oils present common characteristics of these three families according the major contribution of each end member oil.
147. Diasteranes/ TPP versus 3-Methyl / 4-Methyl triaromatics from the oils analyzed for the Potiguar basin. Note that the Aptian marine hypersaline oils, as reported by Mello (1988) present the higher diasterane/TPP and 3-Methyl / 4-Methyl triaromatics ratios when compared with other oil types.
148. C24 tetracyclic/ C26 tricyclic terpanes versus Hopane/Sterane ratio. As can be noticed, the C24 tetracyclic/ C26 tricyclic terpanes can be very suitable in determining the marine oils, since most of them presents high ratio values in relation to lacustrine and mixed oils (note that the C24Tet/C26Tri for the marine oils ranges from 0.37 to 1.09 whereas it varies from 0.05 to 0.45 for the lacustrines and mixed oils). In addition, very low values for Hopane/Sterane were shown to be diagnostic of marine oils even though lacustrine freshwater oils, as those recovered in the well 1 RNS 0027, also present low Hopane/sterane ratio because of the the elevated thermal evolution.
149. Hopane/Sterane ratio versus C27/C29 steranes. Note that most of the lacustrine oils present the C27/C29 sterane ratio close to 1 wheras the marine ols present higher ratios.
150. Plot of Gammacerane index versus diasteranes/TPP from the oils analyzed for the Potiguar basin. The ratio of TPP/ diasteranes has been used to differentiate lacustrine from marine oils. High values of this ratio are indicative of lacustrine environments. This parameter is also seen to be effective in differentiating most lacustrine and mixed oils from those oils derived from typical marine source rocks. Some of the mixed oils are near in value to the marine oils, which could indicate a larger marine effect in those particular mixed oil. However care must be taken regarding the use of this source parameter in the marine hypersaline oils from the CPT since this type of oil presents very low concentrations of C27 diasteranes. Such fact can modify the ratio and mislead the oil classification.
151. m/z 191 Fragmentograms of oils from Potiguar Basin. Observe that the Mixed Marine/Lacustrine oils present biomarkers representative of both end member oils that have contributed to the mix as for example high relative abundance of gammacerane (typical of hypersaline environments), Ts higher than Tm and high relative abundance of tricycli terpanes (typical of lacustrine freshwater environment)
152. M/Z 217 Fragmentograms of oils from Potiguar Basin. Note the differences in the distribution of C27 against C29 steranes regarding marine and lacustrine oils. Marine oils commonly present higher abundance of C27 steranes in relateion to the C29 steranes when compared with marine oils.
153. M/Z 259 Fragmentograms of the analyzed oils from Potiguar Basin showing the high relative abundance of lacustrine biomarker TPP polyprenoids over the C27 diasteranes in lacustrine freshwater oils assimetric to the predominance of the C27 diasteranes over the TPP polyprenoids in the marine oils. The m/z 259 of the ol mix recovered in the well 7UB 0023D RNS indicates a major contribution of the Lacustrine oils in the biomarker signature. Note that the HI variation is considered as the most frequent average values for TOC >1% in the considered Alagamar interval.
154. M/Z 245 Fragmentograms of oils from Potiguar Basin. The marine hypersaline oil from the CPT Member show higher abundances of C29 4methyl triaromatic steranes than the oil from the Galinhos Member (marine anoxic).
155. Mass chromatograms from metastable ion monitoring of C26 to C30 steranes compounds of a Pendência sourced oil recovered from the well 1RNS 0079 RN.
156. . Mass chromatograms from metastable ion monitoring of C26 to C30 steranes compounds of a marine oil sourced by CPT source rocks from Potiguar Basin recovered in the well 4RNS 0127 RN. Note the presence, although in low amounts of C30 steranes in this marine hypersaline oil
157. . Mass chromatograms from metastable ion monitoring of C26 to C30 steranes compounds of a marine oil sourced by Galinhos source rocks from Potiguar Basin recovered from the well 1 RNS 0125 RN. Note the absence of C30 steranes in this marine anoxic oil.
158. . Plot of C29 αββ/(αββ + ααα) steranes versus Ts/(Ts+Tm) from the oils analyzed of the Potiguar Basin.
159. . Plot of C29 αββ/(αββ + ααα) steranes versus S/(S+R). The narrow indicates the thermal evolution of the oil samples.
160. . Map of Ts/(Ts+Tm)of the oils analyzed for the Potiguar basin. Note that there is a good correlation between this map with the steranes maturity one (Figure 161). Both maps show the increase of the thermal evolution of the oils towards the deep offshore Lows, where the active pods of generation are located.
161. . Map of C29 αββ/ (αββ + ααα) steranes from the oils analyzed for the Potiguar basin As can be noted the oils close to the coast and more distant from the pods present the lowest thermal evolution data.
162. . Oil cracking map of Potiguar basin. Highly cracked oils commonly occur as mixtures of intensely cracked and non-cracked oil members, increasing the final oil quality.
163. . Oil Cracking diagram of the Potiguar oil samples.
164. . Oil Types and reservoir intervals around the Mundaú sub basin of Ceará Basin.
165. . API gravity map of the analyzed oils distributed along the Mundaú sub-basin of Ceará basin. Note that the lacustrine oils sourced by the Mundaú shales display the highest API values. In contrast, the low API values are linked to a higher extention of the paleo biodegradation and recent biodegradation in Marine hypersaline oils (see 25-norhopane/hopane ratio map in Figure 170 and the recent biodegradation map in the Figure 171).
166. . Sulfur content of the analyzed oils along the Mundaú sub-basin of Ceará basin. Low sulphur contents are a characteristic of the greater part of the analyzed oils.
167. . API gravity versus depth of the Ceará oils. Differently of the oils from Potiguar basin, it seems that, in Mundaú Sub basin of Ceará basin, the oil quality is not directly linked to the reservoir depth although it is strictly associated to the oil origin and recent biodegradation represented by the ratio Pri/nC17 (compare the values associated to the well 1CES 0061D CE displayed in this diagram with its values inFigure 173).
168. . Sulphur content versus depth of the Ceará oils. Differently of the oils from Potiguar basin, it seems that, in Mundaú Sub basin of Ceará basin, the oil quality is not directly linked to the reservoir depth.
169. . Oil Quality Diagram for the Ceará Oil Samples. Just like in Potiguar, the oils recovered in the Mundaú sub-basin of Ceará basin, present good quality, specially the lacustrine ones that present high API and low sulphur content. Therefore oil quality must not be a major problem in the basin.
170. . Paleobiodegradation Map of the Mundaú sub-basin of Ceará basin (measured by the ratio 25norhopane/hopane). Note the relation between the biodegradation and the oil quality maps shown in the Figure 165.
171. . Recent Biodegradation Map of the Mundaú sub-basin of Ceará basin (measured by the between the isoprenoid pristatane over nC17). Note the relation between the biodegradation and the oil quality maps shown in the Figure 165.
172. . Degree of Paleobiodegradation according the reservoir depth. (25-norhopane/hopane versus depth). There is a slight tendency to the increase of the paleobidegradation with the decrease of the reservoir depth. Note that the lacustrine oils, although it presents a wide vertical distribution, are non biodegraded or mildly biodegraded.
173. . Degree of Recent biodegradation according the reservoir depth. Most of the analyzed oil samples (including all lacustrine samples) present a predominance of nC17 over pristane, indicanting the absence of recent biodegradation. In a general way, the oil samples of Mundaú sub-basin present a lower biodegradation degree related to the Potiguar samples.
174. . Biodegradation Assessment Diagram of the Ceará (Mundaú sub basin) Oil samples. Note that part of the analyzed oils of hypersaline origin present high ratios of 25-norhopane/hopane (>1) indicating the occurrence of minor and major degrees of paleobiodegradation (as in the wells 3CES 0063D CE and 4 CES 0143 CE).
175. . Whole oil and terpane traces (m/z 191) of the well 4CES 0143CE exemplifying a marine hypersaline oil of Mundaú sub basin that is composed of a mixture of oils from different generation pulses. This is indicated by the preservation of n-alkanes, presence of very high UCM compounds and high abundances of nuclear demethylated hopanes (25-norhopanes).
176. . Whole ol and terpane traces (m/z 191) of Mundaú sourced oils that have experimented different biodegradation stages. The oil sample recovered from the well 1CES 0008 CE present no biodegradation. The oil samples recovered from the wells 3 CES 0061D CE and 4 CES 0014 CE have experienced light biodegradation. Finally, the oil recovered from the well 1 CES 0066 CE corresponds to an oil mix sourced by the same source rock at different charging pulses.
177. . Plots of δC13 of the whole oil versus the Pristane over Phytane ratio. The lacustrine freshwater oils sourced by Mundaú Fm. can readly be identified by light dC13 values and the dominance of Pristane over Phytane differently from the marine hypersaline oils in which dC13 values are above -28‰ and the phytane predomines over the pristane.
178. . Whole oil traces as distinctive geochemical features of Lacustrine and marine oils from Mundaú sub basin.
179. Plots of Hopane/ Sterane versus Pristane/ Phytane ratios from the oils analyzed for the Potiguar basin. Note that the lacustrine oils, as reported by Mello, 1988, present the highest Pristane/Phytane and Hopane/Steraneratios when compared with the marine ones that agglutinate themselves showing similar values. The high pristane/Phytane ratio of the oil sample from the well 1 CES 0079 CE is linked to the high thermal evolution of the sample, since the pristane is more resistant to the thermal alteration than phytane.
180. m/z 259 Fragmentograms of a marine (upper fragmentogram – well 1CES 0079 CE) and a lacustrine (bellow – well 3CES 0061D CE) oils from Ceará Basin showing the high relative abundance of lacustrine biomarker TPP polyprenoids over the C27 diasteranes in lacustrine freshwater and brackish water oils. In the marine oils the C27 diasteranes predominates over the TPP polyprenoids.
181. Gammacerane Index versus Hopane/Sterane ratio diagram of the samples from Mundaú Sub basin of Ceará basin. These ratiso have been used to differentiate lacustrine fresh from saline and also from marine hypersaline and siliciclastic oils in the Brazilian Marginal Basins (Mello, 1988 and Mello el al., 1988). High values for Hopane/ Sterane (above 10), and low values of gammacerane/ hopane ratios (below 4), have shown to indicate lacustrine fresh to brackish to saline water environments.
182. Plot of Gammacerane index versus diasteranes/TPP from the oils analyzed for the Mundaú Sub basin of Ceará basin. Observe that the Diasterane/TPP ratio is very effective in differentiating marine oils(in which there is a predominance of diasterane over TPP) from lacustrine ones (in which the TPP prevail over the diasteranes).
183. Gammacerane index versus C34/C35 hopanes from the oils analyzed for the Mundaú Sub basin of Ceará Basin. The Gammacerane index is a indicative feature of the salinity conditions in which the source rock was deposited. This diagram allows a good separation among all oil types.It is also possible to observe that there is a tendency of the lacustrine sourced oils fall in the H35/H34 range of 0.2 to 0.6, whereas the marine hypersaline oils are higher than 1.
184. δC13 of the whole oil versus the Ts/Tm ratio of the Ceará oil samples. Note that both geochemical features are very suitable in the assessment of oil origin. In lacustrine oils, the C27 17α-trisnorhopane (Tm) dominates over the C27 18α-trisnorhopane (Ts) present light values of δC13, differently of the Marine (hypersaline) oils in which such features are inverse.
185. Diasteranes/ TPP versus 3Me/ 4Me triaromatics from the oils analyzed for the Ceará basin. Note that the Aptian marine hypersaline oils, as reported by Mello, 1988, present the highest 3Me/ 4Me triaromatics ratios when compared with the oil types.
186. C24 tetracyclic/ C26 tricyclic terpanes versus Hopane/Sterane ratio in Mundaú oil samples. As can be noticed, the C24 tetracyclic/ C26 tricyclic terpanes can be very suitable in determining the marine oils, since most of them presents high ratio values in relation to lacustrine and mixed oils. In addition, very low values for Hop/ Sterane were shown to be diagnostic of the marine oils
187. Hopane/Sterane ratio versus C27/C29 steranes diagram for the oil samples from Mundaú sub basin of Ceará Basin. This diagram allows a good separation of the oil families, since the C29 sterane largely predominates over the C27 steranes in marine oils. Conversely, high values of Hopane/Sterane ratio are linked to the lacustrine oils.
188. M/Z 191 Fragmentograms of oils from Mundaú sub basin. Note the differences in the Ts/Tm ratio, gammacerane abundance, tricyclic relative abundance between the lacustrine fresh water and marine hypersaline sourced oils
189. M/Z 217 Fragmentograms of oils from Mundaú sub Basin. Note the de differences in the the carbon distributions regarding C27 against C29 steranes between the lacustrine and the marine oil.
190. M/Z 231 Fragmentograms of oils from Mundaú sub basin. Note the differences in the abundance of C29 and 3methyl/ 4methyl triaromatic steranes between the lacustrine and marine oils. The lacustrine oils present higher concentrations of C29 and 4methyl triaromatic steranes.
191. M/Z 245 Fragmentograms of oils from Mundaú sub basin.Note the increase of the relative abundance of the C29 3-methy aromatic steranes over the C29 4-methy aromatic steranes in the Marine oils when compared to the Lacustrine ones.
192. Mass chromatograms from metastable ion monitoring of C27 to C30 steranes compounds of a hypersaline Paracuru (!) sourced oil recovered from the well 4CES 0012A CE
193. Mass chromatograms from metastable ion monitoring of C27 to C30 steranes compounds of a Mundaú (!) sourced oil recovered from the well 3CES 0061D CE .
194. Plot of C29 αββ/(αββ + ααα) steranes versus Ts/Tm from the oils analyzed for the Mundaú sub basin of Ceará basin.
195. Plot of C29 αββ/(αββ + ααα) steranes versus S/(S+R).
196. Map of TS/TS+TM from the oils analyzed for the Mundaú sub basin of Ceará basin.
197. Map of C29 αββ/ (αββ + ααα) steranes from the oils analyzed for the Mundaú sub basin of Ceará basin.
198. Oil Cracking diagram of the Ceará oil samples Note that the lacustrine oils are highly cracked when compared to the marine ones.
199. Oil cracking map
200.  

1. Calibration
   1. Oil Slick Satellite Data
   2. Seismic Interpretation (10.000 km of 3D seismic)
   3. Calibration with 101 wells with all geological data
   4. Calibration of the source rock system using 35 wells
   5. Advanced geochemical calibration data using 79 oil samples
   6. Seismic surface structural and fault Maps in Time and Depth
   7. Diagrams of thermal and maturity calibration data
   8. Hydrocarbon Distribution Maps
   9. Pore pressure data
   10. High Resolution Geochemical oil and gas analyses
   11. Petroleum System Modeling including calibration of temperature, maturation, generation, migration and preservation data, hydrocarbon types and oil families, and its vertical and horizontal distributions.
2. Deliverables
   1. Data of the 3D Seismic Interpretation
      1. Mapped seismic surfaces in depth and time
      2. Digital model provided in Petromod Format
      3. Gridded surface in depth used for modeling.
   2. The model includes
      1. Geological and Geochemical Data
         1. Conceptual model including a spatial distribution of source rocks, reservoirs and seals
         2. Reservoir and source rocks facies distributions
         3. Source rocks families and characteristics
         4. Spatial (vertical and horizontal) distribution, quality and maturity of the source rock systems Kinetic reactions used
         5. High resolution and advanced geochemical analyses of oil, gases and source rocks organic extracts
         6. Oil &source rock correlation and identification and characterization of oil and source rock systems
      2. Petroleum System Modeling
         1. 3D assessment of hydrocarbon migration over geological time
         2. Time of hydrocarbon charge
         3. Risk assessment for defined plays and leads (the potential of structural and stratigraphic traps will be quantified and evaluated)
         4. Heat Flow history maps
         5. 3D maturity and burial history plots and maps
         6. Temperature maps of main reservoir layers
         7. Source and thermal evolution (maturity) maps
         8. Hydrocarbon generation, expulsion, and transformation ratio maps
         9. 3D phase, volumes and quality, including mass balance for the entire model
         10. Pore pressure prediction maps
         11. Oil and gas accumulations potential with AVOs and DHIs identification
         12. Biodegradation risk