Marañon+Basin+Geochemical+Assessment,+ChemTerra+Intl+2000

OIL GENERATION IN SUBANDEAN BASINS OF PERU

Part I: A Geochemical Assessment of Genetic Oil-Types, Migration and Oil-Source Systems in the Greater Maraon Basin, Peru

Report

For: PERUPETRO, Lima, Peru, and CPI, Edmonton, Canada

November, 2000

By: H. von der Dick

ChemTerra Intl. Consultants (CTI), Calgary, Canada

Oil Generation In Subandean Basins Of Peru Part I Confidential Report

ChemTerra Intl. Consultants Ltd., Calgary, Canada Page 2

OIL GENERATION IN SUBANDEAN BASINS OF PERU Part I: A Geochemical Assessment of Genetic Oil-Types, Migration and

Oil-Source Systems in the Greater Maraon Basin, Peru

I. Executive Summary Report Part I & II and Synthesis ____________________________________ 3 A. Oil Classification in the Ucayali Basin: ___________________________________________ 3 B. Oil Classification of the Maraon/Huallaga/Santiago Basins:_________________________ 4 C. Second/Continuous Charge into Reservoirs and Biodegradation: _____________________ 4 D. Source Rocks in the Greater Maraon Basin: _____________________________________ 5 E. Basin Maturity: ______________________________________________________________ 5 F. Oil Source Correlations: _____________________________________________________ 6 G. Migration of Hydrocarbons:____________________________________________________ 7 H. Basin Modeling: Time Temperature Relationship of HC Generation:_________________ 7 I. Future Investigations: ___________________________________________________________ 8

II. Introduction and Scope of Study ___________________________________________________ 9 III. Study Approach, Limitations, and Databases ________________________________________ 12

2. Advantages of a Database ______________________________________________________ 12 IV. Oil Classification in the Ucayali Basin _____________________________________________ 14

B. S/H: Sterane / Hopane ratio Pr/Ph: Pristane / Phytane ratio _____________________________ 16 C. MCH: Methylcyclohexane_______________________________________________________ 16 D. _______________________________________________________________________________ 16

V. Oil-Oil Correlation and Oil Classification in the Santiago / Huallaga / Maraon Basins _____ 17 VI. Biodegradation and Second / Continuous Phase of Migration into Reservoirs______________ 26

A. Biodegradation______________________________________________________________ 26 B. Second and Continuous Migration and Reservoir Filling ___________________________ 26

VII. Source Rocks, Source Rock Potential and Distribution in the Greater Maraon Basin _______ 29 1. Ordovician Contaya and Devonian Cabanillas:______________________________________ 29 2. Carboniferous Ambo __________________________________________________________ 29 3. Carboniferous Tarma Formation _________________________________________________ 30 4. The Upper Carboniferous/Permian Copacabana/Ene Formation_________________________ 30 5. The Lower Triassic Pucara Formation_____________________________________________ 30 6. Lower Cretaceous Raya and Cushabatay___________________________________________ 31 7. Upper Cretaceous Chonta Formation _____________________________________________ 31 8. The Tertiary Pozo Formation____________________________________________________ 31

VIII. Basin Maturity Based on Measured Data._________________________________________ 33 IX. Oil Source Correlations in the Basins_____________________________________________ 36 X. The Oil-Source / Petroleum Systems of the Basins ____________________________________ 38

A. Migration of HC in the Maraon Basin. _________________________________________ 38 XI. List of Figures_________________________________________________________________ 40



OIL GENERATION IN SUBANDEAN BASINS OF PERU

Part I: A Geochemical Assessment of Genetic Oil-Types, Migration and Oil-Source Systems in the Greater Maraon Basin, Peru

I. Executive Summary Report Part I & II and Synthesis Based on available geochemical and geological data the oil systems and exploration potential of the Maraon, Huallaga and Santiago Basins in Peru were re-assessed. Ucayali Basin oils and source rock data were also incorporated and assessed for data comparison and data integration of various reports. This is the first report on Peruvian oils and source rocks to evaluate and integrate various data sets into a cohesive study on oil generation, migration, reservoir alteration, and timing of critical events through the complex tectonic history of these basins. The first part of this report (Report Part I) is an evaluation of existing data and reports with a prime focus on the geochemical classification of oil families in the basins, oil- oil correlation, the assessment of source rocks and their respective maturities, and geochemical evidence for the relationship of source rocks to discovered oils. Based on this framework conclusions on HC generation, migration and reservoir biodegradation are made. The second part of this report (Report Part II) investigates aspects of timing of maturation in the basins and HC generation events. The BasinMod software package was used to simulate and model HC generation in a number of wells with measured maturity data as model-constraining parameters.

A. Oil Classification in the Ucayali Basin: A large number of oils from the Greater Maraon Basin was investigated for their genetic relationship and their classification into oil families. Oils in the Ucayali Basin are characterized by their high maturity. Typical oils reflect maturity levels of at least 0.8% Ro with light oils / condensates such as San Martin, Aquaytia, and Cashiriari reflecting maturity levels around 1.1 1.4 % Ro in the basin. A number of basic geochemical parameters and biomarker data identify four genetically distinct oil families in the Ucayali Basin as displayed in Figure 9 of the Report Part I. These are: the San Martin/Cashiriari oils, the unique La Colpa oils, the Aqua Caliente oils, and the Maquia oils. Except for the Maquia-type oils, all these oil families are derived from Kerogen Type II-III source beds, with the Cashiriari Oil Family clearly indicating a substantial contribution from a (coaly) Kerogen Type III. The Maquia Oil Family is derived from Kerogen Type II material with typical indications for a reducing carbonate source environment. A critical observation for the Maquia Oil Family in the Ucayali Basin is the expressed bimodal n-alkane envelope in GC traces of these oils. Figure 4.3 of the Report Part I shows an example of this bimodal n-alkane envelope. Geochemical data provide evidence for a second HC generation/expulsion phase from the same source at higher maturity into the Maquia structure. In fact, geochemical indications are provided to suggest that the Aguaytia condensate is the exclusive 2nd (late mature) HC phase from the Maquia oil source. This observation is important because it was previously thought that re-migration had occurred into the northern Maraon Basin from Equador in order to explain unusual oil compositions. The geochemical characteristics of the oil families in the Ucayali Basin also define some general constraints for the search for the source rocks for these oil families: The Maquia oil type source should be



a pure Kerogen Type II source, possibly from a carbonate environment since the Maquia oils show Kerogen Type II characteristics and higher S-levels. Carbonate source rocks are generally higher in sulpur compared to shales because of lack of Fe in carbonate environments. Also, the Maquia oils are low in Diasteranes and possibly in Diahopanes, a group of rearranged biomarker species that are abundant in clay and shale environments. The low presence of these source-related tracer indicators in the Maquia oils further points to a carbonate source environment. All other oil families in the Ucayali Basin are derived from a Kerogen-Type II-III precursor material. The lack of the time-critical biomarker, Dinosterane, in these Kerogen Type II-III derived oils points to Paleozoic source rocks, indicating a pre-Mesozoic source age. Thus, four source rocks must be present in the Ucayali Basin to explain the geochemical variability of discovered oils: Three Paleozoic source rocks and one Mesozoic source rock .Also, geochemical analysis and oil oil correlations with Maraon oils clearly show, that the Ucayali Basin oils are limited to this basin with the exception of the Maquia Oil Family showing a very wide-spread occurrence in all basins.

B. Oil Classification of the Maraon/Huallaga/Santiago Basins: Except for the Huallaga Basin, the Santiago and Maraon Basins have numerous oil discoveries. Using a similar evaluation process as for the Ucayali Basin oils based on basic geochemical parameters in conjunction with complex biomarker evaluation and cross-checks to solidify interpretations, two basic oil families are recognized in the basins (Figure 14, Report Part I): Tambo/Sungachi oils and Samiria oils. The oils in the Tambo 1X, Sungachi 1 and Samiria 1S wells are classical reference oils in reservoirs in the basins that are otherwise characterized by oil degradation or complex migration histories. Solid geochemical proof is provided to the genetic link of the Samiria oil in the Maraon Basin with the Ucayali Maquia oils (Figure 13a, Report Part I). Thus,, the Maquia Oil Family has a very wide regional distribution. Tambo/Sungachi oils are only found in the Santiago Basin and the northern Maraon Basin: All (partially degraded) NE Maraon oils belong to the Tambo/Sungachi Oil Family. Figure 19 of the Report Part I shows the regional distribution of these oil families. An important observation here is the discrete regional distribution of the oil families with little or no reservoir mixing of different oil families. The Maquia and Tambo/Sungachi Oil Families are the principal two oil families in Santiago and Maraon Basins, however, they show some compositional variation within themselves: Preliminary biomarker data evaluation demonstrates a pure carbonate and a shaly carbonate source for the Maquia oils in the Maraon/Santiago Basins. The Tambo/Sungachi oil family is derived from a Kerogen Type II-III source rock. The Tambo oil seems to have a slightly higher terrestrial influence compared to the typical Sungachi oil. However, more in-depth biomarker analysis is required to outline regional trends for the respective sub-families shown in Figure 14 of the Report Part I.

C. Second/Continuous Charge into Reservoirs and Biodegradation: A significant observation in the Maraon Basin is the re-occurrence of the bimodal n-alkane distribution in Maquia-type oils and only in this group of oil. Based on this observation and several other arguments presented, a previous concept of re-migrating reservoir HC from Equador or re-migration due to late block tilting can be rejected: the Maquia oil source had, at least locally, two phases of HC generation and expulsion, although not all Maquia type oil reservoirs display a second, high mature charge. The spotty occurrence of this 2nd charge from the Pucara Formation may be due to local subsidence histories as will be explained later. In contrast, all Tambo/Sungachi oils do not display a second, high mature HC charge. Biodegradation is common in many reservoirs in the Santiago and Maraon Basins, in particular in the NE Maraon. In some cases, biodegradation is severe, other reservoirs/structures show slight or moderate biodegradation effects. Both principal oil families are affected, although it appears that Tambo/Sungachi oils are more affected, probably because of their concentration in the NE Maraon in shallow position with



meteoric water infiltration. In a number of reservoirs with Tambo/Sungachi oils it seems that recent trap filling competes with recent degradation processes, pointing to a dynamic system of HC destruction and HC migration.

D. Source Rocks in the Greater Maraon Basin: Based on TOC and Rock-Eval data nine formations from Ordovician age to the Tertiary can be identified as possible or potential source rocks. Table 6 of the Report Part I summarizes the basic nature of these formations. The oldest formations with considerable (paleo-) source potential (Type II) are the Ordovician Contaya and the Devonian Cabanillas Formations. Because of their generally high or extreme maturity the present-day TOC values are moderate, but were in the range of 2-4% TOC before HC generation exhausted these shales. These Paleozoic shales probably generated plenty HC in the distant geologic past, however, due to the Maraon Basin geometry it can be expected that the NE Maraon Basin contains immature Contaya and Cabanillas. From this it can be inferred that Tertiary or Cretaceous subsidence had matured previously immature Contaya/Cabanillas in some regions, however, more detailed work and data are required to reveal or identify a possible role of these formations in oil discoveries. The Paleozoic Ambo, Tarma and Ene/Copacabana Formations are important TOC rich sections in the Ucayali Basin. Except for the Ene/Copacabana the Kerogen Type is II-III or III-II. The Ene Formation appears to be mainly Type II, although some(local) Type II Kerogen was probably developed in the Ambo Formation, too. The oldest Mesozoic formation with good and excellent source characteristics is the late Triassic / early Jurassic Pucara Formation, which occurs in all basins. The Pucara is a bituminous carbonate with interbedded shaly sections. Two depocenters are described in the literature: one in the western Maraon Basin and a second in the western Ucayali Basin (Figure 28b, Report Part I). The N-S stretching Pucara subcrop between 75o and 76o longitude defines the basinal extension of this source unit. The Cretaceous Raya and Cushubatay Formation also have source characteristics, but mainly Kerogen Type III and III-II quality. The basinal extent of the source facies is not known at this point in time. The Late Cretaceous Chonta Formation has been described in the literature as a prominent source for Maraon oils. The Chonta Formation contains Type II and Type II-III Kerogens with frequent TOC concentrations in the range 2-3%. Our data suggest a rich Type II section in the Santiago Basin, the most western part of the Maraon Basin, and perhaps part of the Huallaga Basin (Figure 30a, Report Part I). Eastern and southern areas show diminishing source qualities and quantities. The Ucayali Basin does not contain a Chonta Formation in source quality. The youngest source section and previously largely unrecognized in the Tertiary Pozo Shale Formation with Type II Kerogen, locally developing into a Kerogen Type I. The Pozo Shale source facies may be restricted to the Santiago and (part of?) the Huallaga Basins, because low TOC quantities are recorded in most parts of the Maraon Basin.

E. Basin Maturity: Vitrinite reflectance data suggest as a rough guideline some constraints for HC generation depth intervals and amounts of paleo-erosion: in the Maraon Basin a max. paleo erosion of 3 km is indicated, however many structures indicate moderate or small last erosion because of low surface Ro data in the range of 0.2-03%. This is in contrast to the Santiago and Huallaga Basins with surface Ro data considerably higher, suggesting a significant last erosion and removal of part of the younger sedimentary sequence. Average Ro depth plots in the Maraon Basin suggest the onset of HC generation at 3km, fully mature conditions at 5km and termination of oil generation between 8-9km depth. Furthermore, Ro data suggest no significant HC generation anywhere in the Maraon Basin before 3.2km of (paleo-) depth was reached.



Thus, together with max. paleo-overburden data an absolute eastern limit for HC generation in the Maraon Basin can be outlined. A new, updated Ro contour map for the Chonta Formation is presented, based on accumulated data. The Ro contours show as expected increasing Chonta Formation maturities from East to West. The Chonta Formation is mature or late mature in the Santiago and Huallaga Basins, the northern part of the Maraon Basin and along a narrow zone parallel to the Santiago and Huallaga Basins (Figure 37, Report Part I). In essence, the Chonta Formation is immature or marginally mature East of 76o Longitude. The Chonta Ro contour map and general Ro depth trend data were also used to roughly project Cabanillas maturities in the Maraon Basin. As the oldest and deepest formation with source rock qualities the eastern edge of fully mature Cabanillas shown in Figure 38 Report Part I also defines the most eastern extension of hydrocarbon kitchens in the Maraon Basin. All oil discoveries East of this (absolute) generation limit must be the result of lateral oil migration in the basin. Oil discoveries in wells such as Bretana 1 and Paiche 1X outside any mature source sections clearly indicate long distance migration of >100 km, possibly up to 200km.

F. Oil Source Correlations: Several attempts were made to correlate the oil families in the basins with source rock sequences. The Pucara Formation is identified as the source for the Maquia Oil Family. The very wide distribution of the Maquia Oil Family is consistent with the wide distribution of mature Pucara Formation. This source rock is the most important source rock in the basins. The Chonta Formation is the source of the Tambo/Sungachi Oil Family as indicated from perfect correlations of biomarker profiles in rock and oil samples (e.g. Figures 42c and 43c, Report Part I). A Chonta marl and a Chonta shale actually form two distinct source sections, although further work is required to clearly separate the two Chonta subgroups. Oil source correlation is more difficult in the Ucayali Basin, probably due to the more patchy occurrence of source beds and the high maturity of most of these oils. It appears that the Ene Formation is the source of the Aqua Caliente Oil Family. Marine or lacustrine Ambo Formation is the most likely source of the La Colpa Oil Family, possibly with some contribution from surrounding coaly Tarma/Ambo sections. In fact, the TOC rich, coaly Tarma/Ambo Formations may be the perfect source for the Cashiriari Oil Family with a significant or dominant Kerogen-Type III contribution. The Pozo Shale is an excellent oil source in the Santiago Basin, but as of yet no oil discoveries can be related to this source. The Santiago Basin contains numerous seeps of unknown origin. Future work may be dedicated the investigate deeply buried Pozo Shale as a source for some of these seeping hydrocarbons. Besides the prominent source rocks with mainly Kerogen Type II material (with the exception for the Tarma/Ambo Formations) there are a number of shale formations with lower TOC content and dominantly Kerogen Type III material. Formations such as the Raya and Cushubatay probably contributed to oil generation and further enhanced the Kerogen-Type II-III or III-II character of the oils. Source rock logging in five Maraon wells could identify the two prominent source rock sequences Chonta- and Pucara Formations, but revealed no additional, major source formation that could be of significance. Thus, it appears the effective source rocks in the Santiago Basin are the Pucara-, Chonta-, and Pozo Shale Formations; the latter Tertiary source rock is only mature in deep Neogene sections of the Santiago Basin. In the Huallaga Basin, the Pucara Formation can be expected to be a major source. Few data are available for the Chonta Formation and the Pozo Shale. Both formations may have limited source extension or source quality in this basin. In the Maraon Basin the Pucara Formation is proven to be the significant source; the Chonta Formation source facies is limited to the northern Maraon Basin. The Pozo Shale Formation appears to be of non-source quality in the Maraon Basin, and it is also immature in this basin. The role of the Paleozoic source formations in the Maraon Basin is still not clear. Table 7 of the Report Part I provides an overview of the oil source systems encountered in the basins.



G. Migration of Hydrocarbons:

The depot centers of source beds and the regional maturity pattern define areas of HC generation. Comparing these areas of HC generation with areas of HC discoveries clearly demonstrates lateral migration distances of up to 200km. Furthermore, the clear distinction of oil families, the identification of their respective source beds, and specific geochemical observations discussed above provide fundamental insights into the migration of HC in the basins, in particular the Maraon Basin. The general direction of migrating HC was NE as shown in Figure 45 of the Report Part I; Structures that trapped oil after long lateral migration always trapped the same family of oil. Mixing of different oil families is, with one possible exception in the Ucayali Basin, never observed. This clearly points to discrete migration pathways. Maquia-Pucara oils were generated in a kitchen area covering large parts of all basins. Subsequent NE migration explains the wide distribution of Pucara Formation derived oils (the Maquia Oil Family). The Chonta Formation oils (Tambo/Sungachi Oil Family) were largely generated in the northern and northwestern part of the Maraon Basin and the Santiago Basin. They followed a strict NE migration direction, now forming the NE Maraon Basin oil district with discoveries such as Dorissa, Tambo, Bartra. An important observation is the second, high mature HC pulse from the Pucara Formation. With a possible exception in the Ucayali Basin in the Aguaytia Field this 2nd Pucara HC phase is always associated with the 1st, less mature Pucara HC phase. This observation points to identical migration pathways for both HC pulses. Also, the lack of a separate, single 2nd HC phase (2nd phase only) in a reservoir may have some significance for geological concepts for the timing of trap formation. Also, based on geochemical observations, it appears that HC migration out of the Chonta Formation is a rather late event and still active. Detailed geochemical observations from slightly degraded oils in comparison with heavy degraded oils provide proof for recent, on-going migration of Tambo/Sungachi HC into reservoirs.

H. Basin Modeling: Time Temperature Relationship of HC Generation: Basin modeling was used to gain first insights into the timing of HC generation in the Maraon, Santiago, and Huallaga Basins. Measured Ro data were used and necessary to constrain the model. Major results of modeling in the Maraon Basin are the observation of several episodes of rapid, deep subsidence as the cause for HC generation. A first cycle of subsidence about 280 m.y. ago affected the old, Paleozoic source beds; a second cycle at the end of the Jurassic matured the Pucara Formation, with the Paleozoic sources now progressing into gas generation. A third, last and deep subsidence event during Neogene times affected the Chonta Formation and triggered the 2nd HC pulse in the now late mature Pucara Formation. Figure 17 of the Report Part II in the Tanguintza well is a good example to demonstrate and recognize the staircase maturation progress of the Pucara Formation through geologic times. However, this 2nd Pucara HC phase is only observed in structures where this last Neogene subsidence event formed the maximum burial/heat exposure before some recent uplift. Other structures in the Maraon Basin have experienced a maximum burial in the second subsidence event with the Pucara Formation maturing or even progressing through the oil window in a single phase. Here, the last Neogene subsidence had no effect on Pucara Formation maturity and no 2nd HC pulse was possible. This differential subsidence scenario perfectly explains the earlier geochemical observation of spotty 2nd HC phase Pucara occurrences in the Maraon Basin. The Santiago and Huallaga Basins have different burial histories, characterized by moderate subsidence from early Mesozoic times to the late Paleocene/early Neogene. Then the basins plunged to great depth in excess of 10km. Here, the Pucara Formation slowly matured during Cretaceous times and generated and expelled HC during late Cretaceous/Paleogene times, before rapid Neogene subsidence transferred the Pucara Formation through the oil window into and even out of late (dry) gas generation. As in the Maraon Basin the Chonta Formation maturity process mimics the Pucara Formation maturation on a time maturity delayed pattern. The Chonta Formation matured and, in some wells, even passed through the oil window in the Santiago and Huallaga Basins. It appears, that late- or overmature Chonta Formation is replaced by mature Pozo Formation, the youngest (Tertiary) source rock formation in the



basin. HC modeling indicates that this youngest source rock is mature in structures with thick Neogene basin fill. It can be expected that Pozo Formation HC were generated and that expulsion and migration are still active. HC generation modeling in combination with geochemical data also provides some insights into the timing of biodegradation processes in the reservoirs. The 1st Pucara HC phase shows some signs of biodegradation whereas the 2nd Pucara HC phase entering identical reservoir horizons is an original high mature oil, unaffected from biodegradation. Thus, biodegradation was introduced with the uplift in early Cretaceous times, but the reservoir systems were re-sealed with continued subsidence. Neogene subsidence caused the Chonta Formation HC generation and the 2nd Pucara HC phase. Subsequent uplift breached many reservoirs containing Tambo/Sungachi Chonta oils, but the 2nd Pucara HC phase was not affected.

I. Future Investigations: Although considerable progress is achieved in our understanding of HC generation in the basins a number of problems and questions remain. The fate of gas generation is not known, the role of the Paleozoic source rocks in parts of the Maraon Basin between super-mature and immature stages is unclear, and, in view of the massive source beds in Perus basins, the volumes of generated oils is not known. Quantitative basin modeling could provide some comparison on total generated oil volumes, future oil prospectivity and data for possible future discoveries. Also, there is presently a specific lack on source rock data for the Huallaga Basin, making it difficult to assess this basin for its exploration potential. Report data that are available, but not yet evaluated, may fill this gap.



II. Introduction and Scope of Study A main purpose of this comprehensive study is the use and application of geochemical data in order to genetically classify discovered oils, clarify the oil potential of the Greater Maraon Basin in Peru, relate oil families to their respective sources, and to reconstruct HC generation and migration histories through geological times. Both processes, generation and expulsion / migration, and the timing of these events, are important parameters for the question of locating prospective areas in the Peru basins. This report is subdivided into two parts: Part I investigates the geochemical characteristics of oil systems in Perus major hydrocarbon provinces, and Part II evaluates results from hydrocarbon generation modeling. Figure 1 shows the work area, the basins, and the well control in this area Although a massive body of geochemical data exits for Peruvian basins in form of several massive studies and a large number of smaller reports (a combined total estimated to be 12000 pages of scanned text, figures, and data tables), exploration has made relatively little use of this information. The main reasons for this appear to be the non-familiarity of many geologists with geochemical data and concepts, and conflicting, contradictory information in varies reports and studies. Five reasons can be identified for this conflicting information:

false data (measurements) mislabeling of compounds in reports (in particular in the GeoMark Research Report) data that should exist, but were omitted or forgotten to enter in the report (GeoMark Research

Report), data gaps replaced by speculation (to some extent) gross over-interpretation of geochemical data.

Some examples may illustrate the confusion, erroneous and speculative nature of data and, consequently, the need for a re-assessment of this body of geochemical data: The paper of Sofer et al. (1986) is often referred to as a key paper for understanding the genetic relationship of Peruvian oils. The large Geomark Research Report covering almost 200 oils, applies the same procedures and concepts of this Sofer et al. (1986) approach. Figure 2a shows the GC traces of two oils in the Maraon Basin, the S. Huayuri (1) and S. Huayuri Vivian oils, along with typical biomarker spectra for terpanes and steranes. As obvious from the visual comparison of these bulk - and tracer component patterns, the two oils appear to be identical, both in bulk composition (GC traces) and genetic origin (identical biomarker spectra). Sofer et al.(1986) (and GeoMark Research) routinely and probably indiscriminately apply factor analysis to these biomarker spectra in order to classify and genetically relate the Peruvian oils. Unfortunately, the question of biomarker geochemistry applied to highly mature oils is never addressed, nor is there any attempt to filter or qualify these data to answer specific questions. Figure 2b shows Sofer et al. (1986) statistical factor plot with the two (identical) oils now at opposite factor clusters, suggesting different origins or environments. The reasons for this data conflict and other discrepancies are over-interpretation of data, in particular biomarker data of questionable value in (highly) mature oils, and unfiltered data noise, significantly contributing to factor scores. The end-result of this oil-typing of Peruvian oils is presented in Figure 3 in form of a confusing, questionable Principal Component Scores diagram. There is little hope or chance to assess or incorporate this approach into a geological context. Although this approach and interpretation may be questionable, the raw base data of this report is probably of considerable value, because it essentially covers every oil discovered in Peru. Likewise, Sofer et al. (1986) states on p.386 that certain geochemical parameters, such as TAS 3 and TAS 5, are not applicable to Peruvian oils. Yet the same group of authors (now at GeoMark Research) routinely calculate, plot, and report these values 10 years later in their comprehensive Peru oil report. None of the reports available at PeruPetro really addresses a general observation of HC (hydrocarbon) re-migration in many of the Peruvian oils. Re-charge affected a majority of oil reservoirs in the Maraon Basin, to some extent also the oils in the Ucayali Basin. Source and circumstances of this re-migration is



not clear, and a knowledgeable, critical reader is left to speculate to what degree certain geochemical data (and interpretations) are influenced from a second pulse of migrated oil. On the other side, valuable information is present in the data, but needs to be properly evaluated: The GeoMark Research Report presents data of almost 200 oil analysis, of which many contain valuable data on light HC. The work of Thompson at Arco and Mango at Shell over the last 20 years has clearly proven the enormous information value contained in C5 to C7 hydrocarbon distributions. Hunt (1995) points out the advantage and value of inexpensive light HC analysis over expensive biomarker data. GeoMark Research, fixed on the biomarker approach, ignores this information completely and even does not identify or quantify these light HC that are part of their routine GC (gas chromatography) analysis. Here, we try to evaluate this missed information opportunity, in particular because these light HC shed some light on this second HC pulse often observed in reservoirs. Furthermore, some biomarker profiles presented in these reports may be of dubious value in highly mature oils as a result of their limited thermal stability. Many of Perus oils are highly mature, yet all report evaluations rely heavily on biomarker evaluation, which inevitably leads to erroneous or even contradicting statements. Therefore, non-biomarker data are essential to cross-check biomarker data and to test various conclusions derived from geochemical data analysis. The Corelab Report generally relates interpretations closer to measured rather than statistically processed data; yet there are a number of inconsistencies derived from over-interpretation of data. In an attempt to group the few oils investigated, some basic, solid parameters are not honoured in classification attempts mainly based on biomarkers. Thus, a genetic oil classification scheme presented here for the first time is based on the entire data body, which was carefully investigated and evaluated. It differs from previous attempts to define the oil-source system of the Subandean basins in Peru. In regard to source beds there is some speculation or gaps of data in individual reports. Some reports refer to virtually every shale as a potential source rock for the oils. Based on speculation (or information of unknown source), a number of authors, for example, refer to the Ene Formation as a significant source throughout the Peruvian Subandean basins. Available data question this point of view. The Pucara is generally considered to be a good source, yet no report specifically identifies and demonstrates Pucara oils. Furthermore, Salas (1991) limits the Pucara source to specific areas of the Ucayali Basin and southern Huallaga Basin. Mathalone and Montoya (1993) see the Pucara source as well (and richer!) in the Maraon and Santiago Basins. These examples demonstrate a lack of consistent and systematic data presentation despite the presence of large data sets. Thus, a second key aspect of this ChemTerra Intl. (CTI) report is the critical evaluation of data and previous interpretations with the goal to provide a geochemical basin assessment based on comprehensive, but quality-controlled geochemical data sets. Specifically, in order to achieve these goals, this report tries to answer the following questions: What geochemical types of oils are present in the basins and how are these oils genetically related? Where in the basins do we find distinct genetic groups of oils? This information is essential for first

attempts to identify or speculate on source beds and migration avenues involved in the process of reservoir filling.

Which and how many source beds have to be involved to explain the observed genetic variety of oils?

Where are the hydrocarbon kitchens of these source beds that generated the reservoired oils? Can we conclusively demonstrate oil oil correlations, which is important for our understanding of

migration avenues and trap filling mechanisms? Can we conclusively demonstrate source oil correlations that subsequently serve as base information

to decipher migration distances, quantify oil volumes involved, and provide information for subsequent model reconstruction from source to trap?



In particular, the Maraon Basin has experienced reservoir oil mixing from (different?) sources or as a

result of re-migration from tilted reservoirs. Did oil types co-mingled and in what quantities? Did multiple hydrocarbon migration use established, older avenues or were new migration pathways involved due to basin restructuring? Was a second phase migration a result of block tilting with subsequent re-distribution of old, but reservoired oil? Or was re-migration a result of a second generation/expulsion phase?

The basins have late and overmature source sections that must also have generated large quantities of

gas. So far, no major gas discovery is reported. Did the gas migrate into different directions (as, e.g. in the WCSB) and escaped to surface?

The basins in question evolved in stages throughout their geologic past. This often implies more than

one phase of HC expulsion and migration. Can we provide insights to these geochemical events in time from thermal modeling and HC generation modeling?

This initial, preliminary report essentially omits any geological framework and rather concentrates on the geochemical task. The reader may be referred to many reports and publications available at PeruPetro for the geological basin analysis and basin evaluation The mandate for this project was to evaluate geochemical data for the Santiago, Huallaga and Maraon Basins. Because of data problems and overlap of geochemical data from different sources in the Ucayali Basin, these data are also incorporated here. The Greater Maraon Basin referred to in this report means the combined Ucayali/Huallaga, Santiago/Maraon Basins, that were part of a large Paleozoic marine basin complex before individual basins and subbasins evolved at the end of Paleozoic times.



III. Study Approach, Limitations, and Databases Since there is a large body of significant information available in a large number of reports and in order to systematically use and evaluate these data with confidence, it was decided to initiate a user-friendly Excel database. Most of the basic source rock data for the Greater Maraon Basin were quality checked and entered into a database. A second database was initiated for the basin oils with almost complete entry of all Ucayali oils. However, additional future efforts are required to correct data and link these databases. In this present phase, the Corelab Report and the Geomark Research Report are the essential data entries and data evaluations. The Corelab data comprise outcrop samples and a number of oil data, mostly from the Ucayali Basin and the western Maraon Basin. The Geomark Research Report comprises a massive data set, mostly biomarker data, of virtually every oil discovered in Peru, however, no source rocks were investigated. Since these two major reports are of different vintages it is not possible to link and easily compare source rock data from Corelab with oil data from GeoMark Research. The Ucayali Basin oils had to be added into this study because of sampling overlap of the two labs with the possibility to cross-check analytical data. Here, some significant discrepancies evolved when comparing identical samples from different labs: it appears that GeoMark Research has compounds misidentified. The two databases are only compatible when these discrepancies are resolved. Besides the two mentioned data sets, a number of data from varies reports and summary reports were entered, mostly data from the DGSI Lab in Houston, USA. Special emphasis was put on maturation data because these data are key parameters for thermal - and HC generation modeling attempts. At present time some basin areas show a reasonable data coverage. Additional future inspection of several other large studies (e.g. the Anardarko Report, a 2nd Corelab report etc.) may fill in some data gaps. Table 1 provides an overview of source rock data entry up to November 30,2000. Table1: Source Rock Data Entry

Basic Data

TOC R.E. Ro Ex- tract

Fractions dC13Sat dC13 Aromatic

IP14-18

Pr- Ph

x x x x x x x x x x

DGSIMancheriche x x x x x Mobil Ponassillo x x DGSI Pupuntas x x x x x

DGSI Tanguinza x x x x x DGSI Tamanco x x x x x

CoreLab/Tucunare x x x x x

2. Advantages of a Database The decision to initiate a computer database was made primarily to properly evaluate geochemical data sets from different basin areas and different labs. This decision also involved additional time requirements and thus cost, however, CTI also feels that a computer database provides decisive advantages for later data evaluations and specific data searches that would be difficult to perform without such a database. Some of the advantages are:



After a massive effort of data entry for the Ucayali oils the entire genetic oil classification of this basin could be profoundly performed in short time.

Exploration is presently evaluating the foothill trend in the Huallaga/Santiago basin area with specific

questions on source rock data and source rock distributions. Some key questions could be addressed immediately instead of searching report files for hours or days. Thus, searching, finding and retrieving geochemical data becomes very fast and efficient.

Rather than just assessing previous data or evaluations isolated from individual reports, a database

incorporating all data from various sources allows us now to completely revise and update geochemical maps with increased confidence. Thus, we will be able to present maps, cross-plots etc. on more complete data sets.

In the present form, the geochemical data sets are of minor value due to unresolved inconsistencies and

lack of a proper digital, fast retrieval system. A quality controlled, structured and usable database is an asset for any company with exploration interests in Peru. Exploration companies frequently borrow geochemical reports located at PeruPetro. A geochemical database is an asset that can be sold, traded, or offered to attract interest.



IV. Oil Classification in the Ucayali Basin The Ucayali Basin, including the Pachitea Subbasin, is structurally separated from surrounding basins by structural highs and arches. Ucayali oils are found in the Vivian, Paco, Cashiyacu, Ene, Aqua Caliente, Raya, and Aguanuya Formations. The reservoired, non-biodegraded oils in this basin have API gravities from around 30o to almost 55o and low %S contents between 0.01 and 0.5%. Oils in the Maquia Oil Field consistently show values between around 0.3 and 0.5 % S. A reported value of 0.07% S in the Maquia 1 well is probably in error, a high value of 0.55% for a La Colpa oil at 1555m is the result of biodegradation enriching the S-content of oils. Based on oil groupings discussed later, the original, unaffected La Colpa oil should have around 0.1 0.2 % S-content. Figures 4.0 to 4.3 show a number of Whole Oil Chromatograms of reservoired Ucayali Basin oils. Figure 4.0 is the Aqua Caliente 32 oil in the Raya Formation. The alkane envelope with a maximum around C9-C10 suggests a very mature oil, possible generated at Ro 1.0 1.2%. Figure 4.1 shows the Whole Oil GC of a Cashiriari light oil with an n-alkane envelope terminated at about nC25. Isoprenoid hydrocarbons (Ip13-Ip18 and Pr-Ph) are very low in concentration, as are biomarker concentrations in this light oil. These are indications for a highly mature oil near the bottom of the oil window. Figures 4.2a-c show a reservoir depth sequence of La Colpa oils from around 1555m down to 2450m. The shallow La Colpa 1x oil at 1555m is heavily biodegraded as obvious from the large hump and lack or reduction of n-alkanes, which are preferentially degraded. The low API gravity of this oil is clearly a result of biodegradation. The La Colpa oil at 2001m (Figure 4.2b) is moderately biodegraded, reflected by intermediate API value and presence of n-alkanes, although at reduced levels. The La Colpa Whole Oil GC from a depth of 2453m in Figure 4.2c shows the original, unaffected La Colpa oil. Again, a high maturity seems indicated for this oil. Figure 4.3 is an example for an oil in the Maquia Oil Field. A peculiar observation is a bimodal alkane envelope suggesting a second charge into the reservoir at high maturity. The alkane envelope nC12-C40 would suggest a primary charge of a fully mature oil, followed by a 2nd later charge. There are some common features to these Ucayali oils that provide a first indication of source environments: Except for the Maquia oil in Figure 4.3, all oils exhibit a preference of methylcyclohexane (MCH) over nC7, an indication for a terrestrial, or even significant terrestrial source input (von der Dick et al., 1989). This dominance of MCH correlates with high Pristane over Phytane ratios (Pr/Ph > 1.0) in all Ucayali oils, also indicating a terrestrial OM input besides a Kerogen Type II source. The Cashiriari oils have highest MCH and Pr/Ph dominances, indicating a significant Kerogen Type III source for this oil. In contrast, the S- richer Maquia oils have n-C7 dominance associated with Pr/Ph ratios



Figure 5 shows a cross-plot of Pr/nC17 versus Ph/nC18. These ratios are both source and maturity controlled, with a trend of increasing maturity to the origin of the diagram and source variation recognized across diagonal trends. The plot suggests a majority of the Ucayali Basin oils derived from Type II-III Kerogens, but it also shows a distinct group of oils related to a Type II Kerogen of a reducing depositional environment. All Kerogen Type II oils in Figure 5 are from the Huaga and Maquia Oil Fields. The S-content of the (original, non-biodegraded) oils can be used as an additional parameter to further classify the oils as illustrated in Figure 6. Both Figures 5 and 6 show the presence of three basic oil groups in the basin: San Martin / Cashiriari oils with very low S-content, but high Pr/Ph ratios. The Aqua Caliente-Ganzo Azul-La Colpa sample group with low S-contents and Pr/Ph values >1 (but



Table 2: Geochemical Characteristics of Ucayali Oil Families San Martin/

Cachiriari

La Colpa Aqua Caliente/

Ganzo Azul

Maquia % S 0.0-0.04 0.08 0.05-0.1 0.25-0.4

Pr / Ph 2.3-3.5 1.0-2.0 1.0-2.0 < 1.0 C13 -26.5 to -25.5 -29.3 to -29.1 -28.7 to -28.6 -29.0 to -28.5 S / H invalid 3.0-5.0 < 1.0 < 1.0

nC7 / MCH



V. Oil-Oil Correlation and Oil Classification in the Santiago / Huallaga / Maraon Basins Oil discoveries have been made in a number of wells in the Santiago Basin, for instance in the Puintza 1X and the Putuime 1X wells, while there is no discovery reported for the Huallaga Basin. However, the Shanusi Seep located in the Huallaga Basin in the Chonta Formation may serve as an indication for the oil prospectively of this basin. The Maraon Basin has numerous oil discoveries in many oil fields as shown and discussed in following sections. The API gravities for the oils in these three basins vary widely, from around 15o to 35o degree. No oil in these basins shows clear signs of immaturity, and low API gravities are related to varies degrees of biodegradation. The GC traces of biodegraded oils show reduced or truncated n-alkane distributions and typical humps of analytically unresolved (complex) branched and cyclic HC. The branched and cyclic alkanes resist biodegradation to some degree, whereas n-alkanes, in particular the light n-alkanes, are preferably degraded. Since biodegradation enriches the sulfur content compared with the original oil, the sulfur content has little value here to decipher genetic relationships. Also, API gravities do not necessarily correspond with the intensity of biodegradation in many cases, because as will be discussed later many reservoirs appear to have experienced a second phase of reservoir charge or are experiencing continuous (recent) charge with some or perhaps no reservoir alteration of this re-charge. Figures 10a 10d show a series of Whole Oil GC traces for selected oils in these basins. The common characteristics of these oils are broad n-alkane envelopes; sometimes extending into the nC40 range, with a maximum in the nC10 nC15 range. The smooth n-alkane distributions suggest mature oils, i.e. an equivalent Ro level of around 0.8%. However, there are also distinct differences observed in the GC traces of these oils: Puintza 1, Tambo 1, and Sungachi 1are oils with MCH > nC7, all other oils display nC7 > MCH. Also, these three oils consistently show Pr/Ph ratios > 1.0 and the IP patterns (Ip-13 Ip-18) of these three oils appear to be similar (although this comparison should be based on quantified data rather than a visual comparison). In contrast, the Samiria, Huasaga, Chambira Este, and Yanayacu oils show nC7 > MCH and Pr/Ph ratios < 1.0. Thus, it appears that two basic oil types are present in the Santiago/Maraon Basins with the following characteristics when some biomarker data and isotope values are incorporated (Table 3): Table 3: Geochemical parameters to discriminate and group Santiago/Maraon Basin oils

Parameter for Oil Type Type Tambo - Sungachi Type Samiria nC7/MCH Ratio < 1 > 1

Pr/Ph Ratio > 1 < 1 Steranes/Hopanes (S/H) 0.6 1.0 0.1 0.4

TET / (T25+T26) low Moderate to high dC13sat (permil) -25.0 -28.5 -28.4 - -29.3

Diasteranes (ppm) Abundant Reduced Diahopanes (ppm) Generally Present Generally Absent

Some essential information can be derived from this Table 3: Tambo Sungachi oils are of Kerogen II-III origin and derived from a more open, oxic depositional environment. High MCH levels indicate the Kerogen Type III contribution, as does often a high Pr/Ph ratio. Abundance of Diasteranes and Diahopanes indicates a shaly environment. Samiria oils are derived from an anoxic Kerogen Type II environment with a substantial portion of organic matter derived from bacteria as a result of high C29-C35 Hopane derivatives (low S/H ratios). The low or even absent levels of rearranged (=Dia-) biomarker may suggest a carbonate source environment for this oil type.



The common origin of the Tambo 1 oil and the Sungachi 1 oil is clearly obvious from Figure 11, showing identical sterane patterns for both oils. Thus, the Tambo/Sungachi oils are truly a major oil family in the Santiago/Maraon Basins based on several common geochemical source indicators in Table 3 and Figure 11. Besides these common characteristics of the Tambo/Sungachi Oil Family, some differences are also noted which ultimately results in two sub-families: The Tambo Oil Family and the Sungachi Oil Family. As indicated in Figure 10a, the Tambo 1 oil shows an extended n-alkane range into nC45, whereas the Sungachi oil in Figure 10b does not exhibit n-alkanes into this range. This extended n-alkane range is typical for more waxy oils influenced from higher land plant input. In fact, this is (tentatively) supported by biomarker data: the Tambo 1 oil has more land plant derived biomarker compounds than the Sungachi oil. The Puintza 1 oil in the Vivian Formation may be a Sungachi oil type. However, an extended biomarker database is required to systematically separate Tambo type oils from Sungachi type oils on a consistent, basin-wide scale. The observed differences in the extended n-alkane range may have limited diagnostic value for oils with a long migration history. Similarly, the Samiria oils can apparently be subdivided into two units; the Tiraco Dome Seep is a Samiria oil type based on basic geochemical criteria and specific biomarker profiles. However, the variation of a specific biomarker pair, a C24-Tetracyclic Terpane (Tet) and the associated C25- and C26-Tricyclic Terpanes (T25 and T26), display considerable variation as shown in Figure 12. In Tambo/Sungachi type oils, Tet is always reduced compared to the two Tricyclic Terpanes T25 and T26, whereas Tet is always dominant in Samiria type oils, however, with considerable variation. Preliminary thinking is that the extreme Tet dominance in Maraon Basin oils is related to a Kerogen Type II of a pure marine carbonate environment, whereas moderate Tet dominance may signal some shaly component within this carbonate. This is also supported by very reduced Diasterane levels in the Tiraco Dome Seep, which may reflect the reducing, pure carbonate environment. The Tiraco Dome Seep is certainly not derived from a Cretaceous terrestrial source as speculated in the Geomark Research Report. A comparison of the general characteristics of the Maquia oils in the Ucayali Basin with the Samiria 1 oil in the Maraon Basin reveals some common features which in turn suggest an identical source for these oils: Both oils share nC7/MCH ratios >1 and Pr/Ph ratios consistently



Oils in the NE Maraon Basin are substantially more difficult to classify due to their sometimes extensive level of biodegradation and water washing, and due to some data problems. However, a partial second oil database provides some insight into the nature and origin of these (heavily) biodegraded oils. These data include samples from screened, partially hand-calculated, corrected Corelab & Geomark Research data, the critical Bretana 1 oil as the most eastern oil discovery, and control samples from all oils the Ucayali Basin as shown in Table 4.



Table 4: Screened data from GeoMark and Corelab reports. Lab # Sample

ID Basin Field/Loc. Type Well x y Formation Oil Family Depth

(ft) nC7 MCH nC7/M

CH 13Csat pr/ph pr/17 ph/18 tet/26 S/H

CoreLab U Agua Caliente

32 Agua Caliente

17.65 16.31 1.08 -28.50 1.33 0.31 0.26 0.73 0.35

GeoMark PR-092 U Agua Caliente

AC-26 74.71 8.83 Paco Agua Caliente

4.20 4.40 0.95 -28.68 1.47 0.36 0.27 0.61 0.51

CoreLab U Cashiriari 3X Cashiriari 12.81 22.60 0.57 -26.10 2.08 0.23 0.15 1.78 0.69 GeoMark PR-133 U Cashiriari 1X 72.73 11.87 Ene Cashiriari 8490 7.60 7.23 1.05 -25.87 3.10 0.19 0.09 1.59 1.14 GeoMark PR-185 U Cashiriari 72.78 11.86 Agua

Caliente Cashiriari 7814 5.85 6.30 0.93 -25.81 3.41 0.25 0.10 1.00 0.65

CoreLab U La Colpa 1X La Colpa 1.88 21.25 0.09 -29.00 1.52 1.15 0.80 0.34 1.96 CoreLab U La Colpa 1X La Colpa 11.21 20.58 0.54 -29.10 1.53 0.66 0.46 0.31 1.82 CoreLab U La Colpa 1X La Colpa 9.84 13.55 0.73 -29.20 1.50 0.52 0.40 0.23 4.00 CoreLab M Huasaga 1X Maquia 25.92 19.43 1.33 -29.00 0.86 0.94 1.19 0.66 0.34 CoreLab M Chambira Esta 124 Maquia 28.51 17.79 1.60 -28.90 0.93 0.58 0.67 0.68 0.36 CoreLab M Yanayacu 61XCD Maquia 30.68 21.05 1.46 -28.40 1.05 0.66 0.73 0.78 0.31 CoreLab M Samiria S1 Maquia 42.11 25.86 1.63 -28.70 1.03 0.34 0.38 0.86 0.33 CoreLab U Campo

Maquia 12 Maquia 28.34 8.42 3.37 -28.50 0.70 0.31 0.46 0.71 0.40

CoreLab M Corrientes 6X Maquia 18.93 16.66 1.14 -29.20 0.80 1.13 1.45 0.66 0.33 GeoMark PR-049 M Bretana Maquia -24.80 1.25 1.28 1.10 0.63 0.62 GeoMark PR-132 M Capirona 2X 75.42 3.52 Chonta Maquia 9548 0.22 0.32 0.68 -29.22 1.05 0.57 0.65 0.54 0.54 GeoMark PR-183 M Capirona 2X 75.42 3.52 Chonta Maquia 9557 2.87 1.43 2.01 -29.28 1.15 0.60 0.64 0.52 0.55 GeoMark PR-095 M Corrientes DST 1 28XCD 75.07 3.82 Chonta Maquia 11364 0.02 0.05 0.41 -29.18 0.98 0.89 0.97 0.58 0.50 GeoMark PR-102 M Corrientes DST 3 10XC 75.07 3.82 Chonta Maquia 9824 0.07 0.11 0.65 -29.24 0.96 0.97 1.05 0.52 0.54 GeoMark PR-104 M Corrientes 12XC 75.07 3.82 Chonta Maquia 9892 0.24 0.25 0.96 -29.24 0.91 0.89 1.00 0.52 0.52 GeoMark PR-108 M Corrientes 16XCD 75.07 3.82 Chonta Maquia 10500 0.50 0.51 0.98 -29.19 1.04 0.93 1.01 0.53 0.52 GeoMark PR-114 M Corrientes 6XC 75.07 3.82 Chonta Maquia 9630 0.11 0.11 1.00 -29.16 0.92 1.09 1.16 0.52 0.59 GeoMark PR-135 M Corrientes 8-21-1X 75.06 3.81 Chonta Maquia 9850 0.54 0.44 1.23 -29.20 0.99 1.08 1.14 0.50 0.54 GeoMark PR-182 M Corrientes 45XCD 75.07 3.82 Chonta Maquia 10716 0.47 0.37 1.29 -29.16 0.99 0.90 0.98 0.50 0.58 GeoMark PR-191 M San Juan 77XD 75.21 3.69 Chonta Maquia 10338 0.19 0.18 1.09 -29.22 0.97 1.16 1.31 0.50 0.61 GeoMark PR-039 M Sun 1z 1X Cushabatay Maquia 16549 3.22 2.90 1.11 -29.21 1.33 0.62 0.54 0.59 0.69 GeoMark PR-099 M Yanayacu DST2 32XC 74.94 4.89 Maquia 0.10 0.21 0.48 -29.14 0.94 0.85 0.96 0.49 0.51



GeoMark PR-090 U Campo Maquia

MA-11 74.95 7.33 Maquia 0.50 0.21 2.38 -28.68 0.92 0.30 0.36 0.48 0.55


16 74.96 7.32 Cashiyacu Maquia 2040 2.60 3.30 0.79 -28.59 0.95 0.30 0.37 0.63 0.60


16 74.95 7.33 Maquia 2136 0.29 0.11 2.64 -28.65 0.79 0.29 0.38 0.47 0.63

GeoMark PR-139 U Huaya 4X 75.19 7.11 Vivian Maquia 904 0.90 0.20 4.50 -28.67 0.86 0.36 0.43 0.46 0.56 GeoMark PR-145 M Pauayacu 70XC 75.41 3.36 Vivian Maquia? 8335 9.40 4.60 2.04 -28.47 1.33 0.39 0.39 0.52 0.62 GeoMark PR-192 M Valencia 100D 75.74 3.18 Chonta Maquia? 10936 2.60 2.07 1.26 -28.38 1.59 0.30 0.27 0.50 1.13 GeoMark PR-080 M Valencia 25X 75.74 3.18 Vivian Maquia? 1.85 0.82 2.26 -28.52 1.35 0.30 0.29 0.57 0.56 CoreLab Sungachi 1 Tambo/Sun

gachi 13.78 36.00 0.38 -25.30 1.15 1.02 1.02 0.19 0.64

CoreLab Piuntza 1 Tambo/Sungachi

14.74 17.36 0.85 -28.10 1.29 0.41 0.37 0.34 0.95

CoreLab Tambo 1 Tambo/Sungachi

17.97 26.46 0.68 -28.30 1.27 0.61 0.54 0.30 1.05

GeoMark PR-057 M Bartra 75.64 2.47 Vivian Tambo/Sungachi

0.05 0.09 0.60 -26.88 1.10 1.00 0.79 0.25 1.49

GeoMark PR-122 M Bartra 1B-17-5 75.64 2.46 Vivian Tambo/Sungachi

8503 0.02 0.07 0.29 -26.74 1.36 0.98 0.65 0.26 1.67

GeoMark PR-123 M Bartra 1B-17-2 75.65 2.48 Vivian Tambo/Sungachi

7850 0.02 0.04 0.50 -26.82 1.20 0.96 0.70 0.25 1.29

GeoMark PR-119 M Capahuari 1A-43-14 76.43 2.80 Vivian Tambo/Sungachi

12200 0.10 0.80 0.13 -28.10 1.38 0.65 0.54 0.23 2.31

GeoMark PR-121 M Capahuari 1A-43-13 76.43 2.80 Vivian Tambo/Sungachi

12551 0.53 1.70 0.31 -27.98 1.41 0.60 0.49 0.16 2.22

GeoMark PR-131 M Capahuari 11 76.50 2.69 Vivian Tambo/Sungachi

13339 5.60 7.80 0.72 -28.29 1.37 0.71 0.60 0.21 1.52

GeoMark PR-073 M Capahuari -54

54 76.43 2.80 Chonta Tambo/Sungachi

12877 0.24 0.78 0.31 -24.30 1.43 0.96 0.71 0.20 0.42

GeoMark PR-147 M Capahuari S V-4

RFT V-4 76.43 2.80 Vivian? Tambo/Sungachi

2.05 2.55 0.80 -28.13 1.49 0.60 0.46 0.21 2.00

GeoMark PR-062 M Capahuari S-27

27 76.43 2.80 Chonta Tambo/Sungachi

3.40 5.00 0.68 -24.94 1.39 1.14 0.93 0.17 0.76

GeoMark PR-053 M Dorissa 76.21 2.75 Chonta Tambo/Sungachi

11705 1.18 1.36 0.87 -26.82 1.33 0.67 0.66 0.19 0.75

GeoMark PR-054 M Dorissa 76.21 2.75 Vivian Tambo/Sun 2.61 4.18 0.62 -28.54 1.37 0.68 0.57 0.26 1.35



gachi GeoMark PR-070 M Dorissa 1 76.21 2.76 Vivian Tambo/Sun

gachi 2.60 6.80 0.38 -28.55 1.41 0.79 0.63 0.24 1.21

GeoMark PR-111 M Dorissa 1A-49-1 76.20 2.77 Vivian Tambo/Sungachi

10747 1.34 2.50 0.54 -28.45 1.40 0.65 0.54 0.23 1.24

GeoMark PR-059 M Forestal V 76.23 2.31 Vivian Tambo/Sungachi

0.03 0.10 0.33 -27.23 1.44 0.77 0.62 0.24 1.73

GeoMark PR-136 M Forestal CH-10 76.16 2.34 Chonta Tambo/Sungachi

4.25 5.90 0.72 -26.33 1.41 0.92 0.79 0.19 0.70

GeoMark PR-137 M Forestal 5 76.16 2.34 Vivian Tambo/Sungachi

9760 0.31 0.92 0.34 -27.26 1.40 0.66 0.51 0.22 1.71

GeoMark PR-060 M Huayuri 13 76.23 2.62 Chonta Tambo/Sungachi

11641 1.86 2.20 0.85 -26.11 1.35 0.84 0.79 0.20 0.69

GeoMark PR-140 M Huayuri V-3 76.23 2.63 Vivian Tambo/Sungachi

0.17 0.57 0.30 -28.02 1.44 0.65 0.51 0.23 1.62

GeoMark PR-141 M Huayuri 2 76.23 2.62 Vivian Tambo/Sungachi

10318 3.10 4.30 0.72 -28.19 1.41 0.65 0.54 0.20 1.72

GeoMark PR-190 M Huayuri 1A-48-1 76.23 2.62 Chonta Tambo/Sungachi

10783 4.50 5.55 0.81 -26.39 1.41 0.87 0.73 0.18 0.67

GeoMark PR-055 M San Jacinto B 75.88 2.30 Chonta Tambo/Sungachi

8510 1.30 2.40 0.54 -26.21 1.28 1.16 1.04 0.19 0.70

GeoMark PR-071 M San Jacinto A 75.87 2.32 Vivian Tambo/Sungachi

0.10 0.25 0.40 -26.74 1.31 1.05 0.85 0.26 1.30

GeoMark PR-051 M Shiviyacu 76.14 2.50 Vivian Tambo/Sungachi

0.10 0.02 4.00 -27.89 1.28 0.58 0.52 0.21 1.55

GeoMark PR-146 M Shiviyacu V-26 76.14 2.49 Vivian Tambo/Sungachi

0.55 1.30 0.42 -27.83 1.47 0.61 0.47 0.25 1.51

GeoMark PR-044 S Dominguza 1 77.82 4.39 Puca Tambo/Sungachi

2935 1.10 2.07 0.53 -28.28 1.67 0.65 0.43 0.35 0.90

GeoMark PR-045 S Piuntza DST 1 1 77.79 4.11 Vivian Tambo/Sungachi

12811 3.85 4.50 0.86 -28.44 1.48 0.54 0.42 0.36 1.19



Figure 15 is the identical cross-plot to Figure 5 showing the Ucayali oils. A general separation of the Greater Maraon Basin oil families is clearly indicated. All Maquia Type oils plot in the Kerogen Type II field or close to the border of Type II-III. All other oil families plot in the Kerogen Type II-III region, with Cashiriari oils as the most mature oils and with the highest Kerogen Type III signature. In this plot, all the NE Maraon Basin oils plot in the field of Tambo/Sungachi oils, suggesting, in fact, a Tambo/Sungachi oil type. The Bretana 1 oil, indicated here as a Maquia oil type for reasons discussed below, plots close to the Tambo/Sungachi oils. Figure 16 is the Pr/Ph versus dC13sat cross-plot for all oils investigated here. Some further discrimination of oil families is recognized from this plot. Cashiriari oils are a distinct group here because of high Pr/Ph ratios not observed in any other family. Maquia oils and La Colpa oils form distinct clusters due to some common geochemical characteristics. Tambo/Sungachi oils (including the NE Maraon Basin oils) form a large, nevertheless distinct cluster. The Aqua Caliente group forms a separate cluster within the Tambo/Sungachi cluster. The Bretana 1 oil appears to have Tambo/Sungachi characteristics; however, it is possible that some of the Bretana geochemical characteristics are modified from both extensive reservoir degradation (see discussion below) and very long distance migration. Figure 17 is an important biomarker diagram based on Sterane/Hopane (S/H) ratios and the Tet/T26 ratio, the ratio of C24-Tetracyclic versus the C26-Tricyclic Terpane discussed in Table 3 as an important source discriminator for the oils. As expected, Maquia oils overlap with Agua Caliente oils with identical Tet/T26 ratios and similar low S/H ratios (see also Figure 8!). However, Tambo/Sungachi oils are clearly separated from Maquia oils. The NE Maraon Basin oils are again consistent with Tambo/Sungachi signatures. Thus, it is proven that these biodegraded NE Maraon Basin oils belong to the genetic Tambo/Sungachi Oil Family, and are not derived from Maquia oil related sources. The Bretana 1 oil plots in the center of typical Maquia oils, strongly suggesting a Maquia type oil origin but with some characteristics that underwent changes due to long distance migration and degradation. Biomarkers are fairly resistant to degradation, in particular the Tri- and Tetracyclic Terpanes used in Figure 17, which is the reason for our suggested classification of the Bretana 1 oil as a Maquia oil. On the other hand, low S/H values for some Tambo/Sungachi oils may be the result of biodegradation since steranes are degraded before Hopanes. La Colpa and Cashiriari oils also form their distinct clusters in Figure 17, although the values for the Cashiriari oils are not reliable due to the high maturity of these oils. Figure 18 is a cross-plot of Pr/Ph versus nC7/MCH. The nC7/MCH values of Maquia oils are typically >1, but extent here into values of 0.5 as a result of biodegradation. Tambo/Sungachi, Cashiriari and Agua Caliente oils plot in distinct clusters, and La Colpa oils coincide with Tambo/Sungachi oils because of their common characteristics as Kerogen Type II-III derived oils. Although there are some scattered data points due to the high mobility of light HC and degradation effects, this Figure 18 confirms the oil classification scheme derived from a number of geochemical parameters. The main oil families in the Greater Maraon Basin are:

the Cashiriari, Agua Caliente and La Colpa Oil Families limited to the Ucayali Basin, the Maquia Oil Family with presence in almost the entire Greater Maraon Basin, and the Tambo/Sungachi Oil Family in the Santiago/Maraon Basin.

Table 5 provides a listing of oil reservoirs and their respective oil families. Figure 19 is a map of the regional distribution of these oil families in the Greater Maraon Basin. It is obvious that the Ucayali Basin oil families are limited to this basin, with the exception of the Maquia Oil Family. Tambo/Sungachi oils are mainly found in the Santiago Basin and NE part of the Maraon Basin. The oil family distribution map is a key to recognize and comment on migration directions and distances once the oil sources are identified.



Table 5: List of oil fields/wells and their associated oil families

Loc. Loc. Bio- Continuous

Basin Field Well X Y Reservoir degraded 2nd charge Oil Family

U Agua Caliente 32 74.6 8.8 Raya - - Agua Caliente

U Agua Caliente AC-26 74.71 8.83 Paco - - Agua Caliente

U Aquaytia 1 75.22 8.38 Agua Caliente - - Maquia

M Bartra 75.64 2.47 Vivian ++ + Tambo/Sungachi

M Bartra 1B-17-5 75.64 2.46 Vivian ++ +'?' Tambo/Sungachi

M Bartra 1B-17-2 75.65 2.48 Vivian ++ +'?' Tambo/Sungachi

M Bretana 1 74.25 5.2 ? ++ - Maquia

U Campo Maquia 11 74.95 7.33 ? - + Maquia

U Campo Maquia 12 74.95 7.33 Vivian - + Maquia

U Campo Maquia 16 74.96 7.32 Cashiyacu - + Maquia

U Campo Maquia 16 74.95 7.33 ? - + Maquia

U Campo Maquia 16 74.95 7.33 Paco - + Maquia

U Campo Maquia 17 74.95 7.33 ? - - Maquia

M Capahuari 1A-43-14 76.43 2.80 Vivian (+) - Tambo/Sungachi

M Capahuari 1A-43-13 76.43 2.80 Vivian - - Tambo/Sungachi

M Capahuari 11 76.50 2.69 Vivian - - Tambo/Sungachi

M Capahuari 54 76.43 2.80 Chonta (+) - Tambo/Sungachi

M Capahuari S V-4 76.43 2.80 Vivian ? - - Tambo/Sungachi

M Capahuari S 27 76.43 2.80 Chonta (+) +'?' Tambo/Sungachi

M Capirona 2X 75.42 3.52 Chonta - - Maquia

M Capirona 2X 75.42 3.52 Chonta - - Maquia

U Cashiriari 1X 72.73 11.87 Ene - - Cashiriari

U Cashiriari 3X 72.73 11.87 Cushubatay - - Cashiriari

U Cashiriari 3X 72.73 11.87 Cushubatay - - Cashiriari

U Cashiriari ? 72.78 11.86 Agua Caliente - - Cashiriari

M Chambira Este 124 75.2 3.8 Chonta + yes Maquia

S Chingana Seep Seep 77.93 4.45 Pozo ++ ? Maquia

M Corrientes 28XCD 75.07 3.82 Chonta + +'?' Maquia

M Corrientes 10XC 75.07 3.82 Chonta + + Maquia


M Corrientes 16XCD 75.07 3.82 Chonta + + Maquia


M Corrientes 8-21-1X 75.06 3.81 Chonta + + Maquia

M Corrientes 45XCD 75.07 3.82 Chonta + + Maquia

M Corrientes 6x 75.35 4 ? + + Maquia

S Dominguza 1 77.82 4.39 La Puca - - Tambo/Sungachi

M Dorissa 76.21 2.75 Chonta - - Tambo/Sungachi

M Dorissa 76.21 2.75 Vivian - - Tambo/Sungachi

M Dorissa 1 76.21 2.76 Vivian (+) - Tambo/Sungachi

M Dorissa 1A-49-1 76.20 2.77 Vivian (+)? -? Tambo/Sungachi

M Forestal V 76.23 2.31 Vivian + - Tambo/Sungachi

M Forestal CH-10 76.16 2.34 Chonta - - Tambo/Sungachi



M Forestal 5 76.16 2.34 Vivian + - Tambo/Sungachi

M Huasaga 1x 76.66 3.14 Agua Caliente + + Maquia

U Huaya 4X 75.19 7.11 Vivian - ? Maquia

M Huayuri S-13 76.23 2.62 Chonta - - Tambo/Sungachi

M Huayuri V-3 76.23 2.63 Vivian - - Tambo/Sungachi

M Huayuri S-2 76.23 2.62 Vivian - - Tambo/Sungachi

M Huayuri 1A-48-1 76.23 2.62 Chonta - - Tambo/Sungachi

S Ipacuma Seep 77.95 4.95 Pozo ++ - Maquia

U La Colpa 1X 73.47 9.32 Copacabana (+) ? La Colpa

U La Colpa 1x 1X 73.47 9.32 Aqua Caliente ++ - La Colpa

U La Colpa 1x 1X 73.47 9.32 Tarma (+) - La Colpa

M Pauayacu 70XC 75.41 3.36 Vivian - - Maquia ?

S Puintza 1 77.79 4.11 Vivian - - Tambo / Sungachi

S Putuime 1 77.93 4.38 Pozo ++ ? Tambo / Sungachi

M Samiria S1 74.9 5.45 Chonta - - Maquia A2

M San Jacinto B 75.88 2.30 Chonta (+) - Tambo/Sungachi

M San Jacinto A 75.87 2.32 Vivian ++ + Tambo/Sungachi

M San Juan 77XD 75.21 3.69 Chonta + + Maquia

U San Martin 1X 72.77 11.76 Aqua Caliente - - Cashiriari

U Sepa 1X 73.5 11.1 Tarma - - LaColpa/Aqua Caliente Mix

H Shanusi Seep 76.5 6.2 Chonta ++ - Maquia

M Shiviyacu ? 76.14 2.50 Vivian - - Tambo/Sungachi

M Shiviyacu V-26 76.14 2.49 Vivian - - Tambo/Sungachi

M Sun 1X 76.00 4.65 Cushabatay - - Maquia

M Sungachi 1 76.46 3.61 Vivian ? + + Sungachi

M Tambo 1 76.4 2.95 Vivian - - Tambo

H Tiraco Dome Seep 75.97 6.4 ? ++ ? Maquia A1

M Valencia 100D 75.74 3.18 Chonta - - Maquia

M Valencia 25X 75.74 3.18 Vivian - - Maquia

M Yanayacu 32XC 74.94 4.89 Chonta + +'?' Maquia

M Yanayacu 61XCD 75.95 4.85 Chonta + + Maquia

Biodegraded samples

- No biodegradation, (+) Slight biodegradation, + Biodegraded,

++ Severe biodegradation



VI. Biodegradation and Second / Continuous Phase of Migration into Reservoirs

A. Biodegradation Biodegradation is a process of bacterial attack and alteration of oil. Unless located at the surface, source rocks are seldom affected from biodegradation, however, shallow reservoirs often show signs of biodegradation. The process of degradation continues as long as molecular oxygen is available and reservoir temperatures are moderate; usually infiltrating meteoric waters provide the molecular oxygen and the nutrients required for HC reservoir degradation. Therefore, water washing is often associated with degradation. Extensive degradation and water washing may lead to severely altered oils or oil residues such as the tar sands of Western Canada or the extensive tar sands in Maracaibo, Venezuela. Biodegradation significantly changes a number of oil properties and characteristics: API gravities are lowered, the sulfur content is increased, oxygen levels are elevated and substantially higher molecular weights are encountered. Biodegradation preferably attacks n-alkanes, starting with light n-alkanes and progressing through to the heavier n-alkanes. Branched and cyclic alkanes, including the biomarkers, are more resistant while aromatic HC are very resistant to microbial degradation. Among the classical biomarkers, the Steranes are less stable than Hopanes, while the Tricyclic Terpanes and Diasteranes are highly stable, even at very advanced levels of biodegradation. Therefore, biomarker geochemistry can often be applied to degraded oils to compare or correlate these with other altered or unaltered oils in a basin. Water washing mostly affects the light HC of an oil according to the solubility of these light compounds in water. Many light HC species that are easily degraded have limited solubility. This differential behavior is the basis to assess biodegradation versus water washing effects in reservoired oils. Aromatics such as Benzene and Toluene, e.g., are fairly resistant to degradation, but highly soluble in formation waters. We have briefly discussed biodegradation in the Ucayali Basin, with the La Colpa oil as the only Ucayali Basin reservoired oil showing prominent signs of degradation. In the Maraon Basin, and in particular in the NE and E discoveries, biodegradation is common but occurs at various degrees. Figure 20 shows the GC traces of the two main oil families in their original, unaltered pattern. GC traces of oils that differ substantially from this HC distribution indicate multi-phase migration, continuous migration, and / or biodegradation effects. The Bretana 1 oil in Figure 21 is an example for degraded Maquia-type oil; the Bartra 1B-17-5 oil is a former Tambo/Sungachi oil, which is now severely degraded. An example for extreme degradation is shown in the Aecite River Seep of the Santiago Basin. Usually, more complex biomarker profiling has to be used to try to group these degraded oils. In many cases reservoir degradation in the Maraon Basin is not as severe as illustrated in Figure 21. In addition, the observed biodegradation in many reservoirs allows us to decipher and reconstruct migration and reservoir filling histories, as will be explained in detail in the next chapter.

B. Second and Continuous Migration and Reservoir Filling Sofer et al. (1986) have speculated about reservoir oil re-distribution from Ecuadorian reservoirs N as a result of block or basin tilting at Tertiary times. However, there is considerable doubt about this concept, in view of the data and observations presented here and several conclusions that are discussed below. A 2nd expulsion phase in the Maquia Oil Family of the Ucayali Basin was already briefly addressed above, where this 2nd expulsion phase appears to be associated with substantially higher maturity levels because of the pronounced dual n-alkane distribution (see Figure 4.3). The Aguatyia condensate is, in all likelihood, a Maquia oil type at very advanced source maturity. Thus, it appears that a second-generation phase followed by another expulsion event and migration, is the reason for the dual n-alkane envelope seen in Figure 4.3 for the Maquia oils in the Ucayali Basin. Geological data have to be investigated to estimate the age of the Aquaytia structure in the Ucayali Basin. If truly a recent structure, this could explain the super-mature Maquia oil in Aguaytia at last stages of source rock HC expulsion, and into an older Maquia structure with



earlier (mature) oil. In general terms, the observations made here in the Ucayali Basin are an indication for a second pulse of oil from late source rock maturation, an event that could also have affected the Maraon Basin. Figure 22, showing two Maquia Oil Field samples from the Ucayali Basin, is a further example of this demonstration for a dual reservoir charge discussed in Figure 4.3. An important finding in Maquia type oils in the Maraon Basin is the fact, that the same dual n-alkane distribution seen in the Maquia Oil Field (Ucayali Basin) is also observed in Maquia type oils of the Maraon oils. Figure 23 shows a Maquia oil from the Yanayacu well in the Maraon Basin, with this dual n-alkane envelope. The oil is moderately biodegraded, however, this biodegradation only effected the first, early migration phase. The second phase at high maturity is witnessed in the C6-C12 HC distribution, which appears unaltered. Also, an important observation is the fact of a consistent nC7 > MCH dominance preserved in this second HC phase: it clearly suggests two phases of oils from an identical source at different maturity levels. An unaltered C6-C12 HC envelope and geochemical evidence for biodegradation effects in the higher molecular range can only be explained from continuous or second-phase migration. In both the Ucayali and Maraon Basins, the observation clearly points to a discrete early migration phase and a discrete later, second migration phase, separated in time by a phase of biodegradation. It appears that the second phase of Maquia oil related HC migration largely escaped biodegradation, possibly due to reburial of previously shallow reservoirs. The observation of this Maquia-oil related dual-expulsion/migration system of early mature (and partially degraded) and late highly mature oils into the reservoirs is not always very pronounced as seen in such fields as the Corrientes, Chambira Este, Huasaga and San Juan Fields in Figure 24. The hump and high Pristane and Phytane levels relative to (reduced) n-alkanes in the nC15-nC20 range demonstrate various degrees of biodegradation with an unaltered 2nd phase always recognized. This 2nd HC phase becomes visually more pronounced in these GC traces, the more 2nd phase HC entered the reservoir system, and the more intense the biodegradation was for the 1st HC phase. Figure 19 suggests that many, but not all Maquia-type oils have recognizable 2nd charges. Although somewhat speculative and a point of later discussions, it could be suggested that the 2nd charge pattern in Figure 19 stretches along a NNW-SSE trend, that could be related to a specific high maturity of the Maquia source beds at a specific point in geological times. The obvious next question is, whether the dual, maturity-related Maquia-oil system is limited to Maquia oil reservoirs or extents into the Tambo/Sungachi oil system in the Santiago-Maraon Basins. Figure 25a shows a number of selected Tambo/Sungachi oils that have experienced little biodegradation. The extreme level of MCH in these oils is not related to source facies, but to this mild biodegradation process, affecting some light ends of the GC traces. An important observation here is the distinct lack of any signs for dual n-alkane envelopes recognized in many Maquia oils. This clearly indicates a one-phase HC charge and also suggests a younger source than for the Maquia oils: If, in fact, a younger source is involved, the main phase of Tambo-Sungachi oil related expulsion could coincide with 2nd phase expulsion from an older (deeper) Maquia oil related source. However, Figure 25b, showing more severe cases of biodegraded Tambo/Sungachi oils, may, at a first glance, question the conclusion of a single migration event for the Tambo/Sungachi oils. All oils in this figure show severe or very severe biodegradation in the reservoir, but they also display significant or even abundant light HC in the front end GCs, apparent for a dual charge system as discussed before. However, the fundamental difference between the two oil systems is, that this 2nd charge molecular envelope is only recognized in highly degraded Tambo/Sungachi oils, but never observed in lightly degraded or unaltered Tambo/Sungachi oils. The reason for this observation (and apparent contradiction) is a presently ongoing migration and reservoir filling process competing with presently active biodegradation in many Tambo/Sungachi oil reservoirs. In some fields or field sections (such as Bartra, Figure 21) the present supply with fresh migrating oil is limited and biodegradation is a rapid process; in other parts



such as the Bartra V-14, biodegradation may be slower and with increased rates of current HC migration into the structure. Four main geochemical observations essentially support this scenario of Tambo/Sungachi oil reservoir filling from one single source at a common maturity level, starting at one point in the geological past and presently continuing, and biodegradation that started in the past and is still active: Unaffected Tambo/Sungachi oils show MCH predominance over nC7; this MCH predominance is

always observed; it is sometimes extreme due to preferred degradation of nC7. This points to a single source type involved.

The second observation is the homogeneous n-alkane distribution in original Tambo/Sungachi oils, indicating one, not two, maturity stages involved.

The third observation is the presence of light HC in highly degraded oils, with the only explanation from recent migration.

The fourth observation is the often extreme MCH dominance in this recent HC migration, only explained by recent biodegradation.



VII. Source Rocks, Source Rock Potential and Distribution in the Greater Maraon Basin A basic geochemical database initiated at PetroPeru in Lima and extended in Calgary allows us to quickly screen the basins for source rock characteristics and to plot relevant data. The following Table 6 provides an overview of the basic geochemical characteristics of several formations encountered in the four basins. A brief description and the significance of the formations (from old to young) in regard to source potential is as follows:

Table 6: Summary of Source Rock Data

Formation Main Data Source Basin

Max TOC (%)

Freq. TOC (%)

Max HI Freq. Kerogen Type

Contaya Maraon 1.0 1 9.0 Type II (?) Cabanillas Maraon 3.0 1-2 145 Type II (?)

Ambo Ucayali 35.0 5-25 483 Types II-III & II Tarma Ucayali 13.1 2-4 165 Type III

Ene/Copacabana Ucayali 21.5 2-6 673 Types II and II-III Pucara All 12.5 2-5 538 Type II

Raya/Cushubatay All 65.0 2-7 227 Types III & III-II Chonta Santiago/Maraon 5.8 2-3 642 Types II & II-III Pozo Santiago 2.4 4-7 491 Type II-I

1. Ordovician Contaya and Devonian Cabanillas: Few samples are available from these shales of early basin formation, however, the data indicate that both shale packages are relatively thick and, more important, enriched in TOC. The max. TOC recorded is 1% for the Contaya and 3% for the Cabanillas; the latter formation averages values around 1-2%; the Hydrogen Index (HI) for the Cabanillas is max. 300. Although these numbers are not impressive (and perhaps the reason for neglect), one should consider the presently very high or even extreme maturity of these early Paleozoic source rocks. It can be expected that at least the Cabanillas had a significant source potential with (reconstructed) TOC values around 3-4%. Thus, the Cabanillas had significant initial oil source potential and has realized this potential in the geological past, although there are no geochemical indications pointing to a survival of these Devonian hydrocarbons. The second part of this report will address the timing of HC generation from these early source beds and the possible fate of these HC.

2. Carboniferous Ambo The Ambo Formation of the southern Ucayali Basin has been described as a delta/marine clastic sequence and is best developed in southern Peru (Mathalone and Montaya, 1993). In northern Peru, the Ambo is patchy and highly mature. Available data are limited to the southern Ucayali Basin where the Ambo Formation is shallow enough to be recorded in wells or outcrops (see Figure 26a). The Ambo Formation exhibits a large range of TOC values from less than 1% to 35%. The Hydrogen Index values (HI) vary accordingly from < 100 to almost 500, as obvious from Figure 26b. Most samples in this HI TOC diagram, in particular those with very high TOC, plot in Kerogen Types III and III-II fields, emphasizing the coaly character of this formation. However, most of the Ambo samples are also very mature and, although of coaly nature, the initial HI at deposition was certainly somewhat higher and comparable to many coaly sequences in Indonesia and Australia with proven oil generative capabilities. The reason for the increased HI potential to normal coal seams is the relative enrichment of oil prone material in these shaly coal sequences during sedimentary/depositional processes.



Besides the general character as a Type III-II organic matter, the Ambo apparently also comprises some (local?) sections of typical Type II Kerogen, as indicated in Figure 26b by HI values around 450 550 for early mature Ambo samples. Figure 26c is a HI-OI diagram for Ambo samples with TOC values >25%. The plot indicates mature samples tracking along the Type I / Type II maturation path, although they are clearly coaly samples that should actually plot along the Type III or Type III-II path. As pointed out by Peters (1986), many mature coals show abnormally low OI values, and, unless recognized as coals, can be mistaken for oil prone source beds. In our geochemical oil characterization it was mentioned that Ucayali oils with the exception of Maquia oils appear to be derived from Kerogen Type III-II or Type II-III material. The Ambo Formation is certainly a formation of interest as an oil source in the Ucayali Basin.

3. Carboniferous Tarma Formation Again, data for this formation are limited to the Ucayali Basin. TOC values are usually around 2-3 %, but values can be as high as 13%. The low HI values



expected high Kerogen transformation into HC followed by expulsion, the original, typical TOC range is probably closer to 4-8%. Figure 28b shows the sample and data points available for the Pucara Formation, together with literature information on the depocenters and subcrop edges. Depocenters occur in the northern Ucayali Basin and in the western Maraon Basin, extending into the Santiago Basin. Although somewhat diffuse it appears that high TOC values may be concentrated along the Santiago-Huallaga Basins. Thus, in conclusion, it appears that the Pucara is a basin-wide occurring organic-rich formation. Furthermore, present or (reconstructed) paleo-depths and measured maturity data indicate a late or overmature stage in the basins with the expectation of significant volumes of HC generated from this formation in post-Triassic times.

6. Lower Cretaceous Raya and Cushabatay Both formations have been considered as possible or potential source beds in the basins. Our database does not indicate significant TOC in these formations in the Ucayali Basin, which is consistent with the terrestrial coarse grain character of these formations in this basin. However, north of the Ucayali Basin, both the Cushabatay and Raya Formations display TOC values from 1

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