65779793 Source Rocks and Oil Families

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ABSTRACT

An extensive evaluation of organic source facies,the application of hydrocarbon geochemistry, andintegrated basin modeling of the southwest portionof the Maracaibo basin in Colombia (referred to asthe Catatumbo subbasin) indicate (1) multipleorganic-rich horizons occur within the Cretaceousand Paleocene sections, (2) most of the reservoiredoil and gas was sourced locally from Cretaceous

marine carbonate facies by means of lateral and ver-tical migration, (3) two subfamilies of Cretaceousoils are recognized that reflect different sourcefacies within the Cretaceous section and differentmaturation and migration histories, (4) oil and gaspresent in the southern Catatumbo subbasin indi-cate a contribution from Paleocene terrestrialsource facies that required westerly migration froma source area in Venezuela, possibly within theNorth Andean foredeep, and (5) oil generation fromCretaceous source rocks began in the Oligocene,and peak generation occurred in the late Miocene.These key conclusions are based on source rock analyses of 365 rock samples from eight wells, gaschromatography/mass spectrometry, and isotope

and bulk composition analyses from nine roextracts and seven oil samples.

INTRODUCTION

The Catatumbo subbasin of Colombia forms southwest flank of the Maracaibo basin,extremely prolific hydrocarbon-producing basinnorthern South America (Figures 1, 2). Althou

considerable work has been done to understasource rocks, oil families, and hydrocarbon migtion in the Venezuelan portion of the Maracabasin (e.g., Brenneman, 1960; Bockmeulen et 1983; Blaser and White, 1984; Gallango et al., 19Talukdar et al., 1985, 1986, 1987; Sweeney et 1990; Talukdar and Marcano, 1994), very li work has been published on the basin’s southwflank, which extends into Colombia.

To define organic source facies, oil families, amigration history in the Colombian portion of Maracaibo basin, an extensive sampling and ansis program was undertaken in this area. Thanalyses and their interpretations provide a strobasis for understanding the distribution of discered hydrocarbons in this region and for undstanding the potential for additional oil and gas coveries. In this paper, we describe the geochemanalyses that were completed on samples from Catatumbo area and outline our interpretationthe generation and migration of hydrocarbobased on those analyses.

GEOLOGIC SETTING

Structural Setting

The Catatumbo subbasin in Colombia is situain the southwest corner of the Maracaibo ba(Figure 1). The Catatumbo subbasin is boundedthe west by the Santander massif and the SierraPerijá, and in the south and southeast by tMérida Andes. The eastern boundary of tCatatumbo subbasin is defined by the VenezueColombia border. Two general structural sty

1

©Copyright 1998. The American Association of Petroleum Geologists. Allrights reserved.

1Manuscript received December 4, 1995; revised manuscript receivedMay 30, 1997; final acceptance February 3, 1998.

2Exxon Exploration Company, P.O. Box 4778, Houston, Texas 77210-4778.

3Exxon Production Research Company, P.O. Box 2189, Houston, Texas,77252-2189.

4Ecopetrol, Calle 37, No. 8-47, Piso 8, Santafé de Bogotá, Colombia.Data and interpretations for this paper were obtained from a joint Exxon-

Ecopetrol study of the Catatumbo subbasin. Many people participated orassisted in that study. J. J. Sequeira, P. C. Wellman, and V. J. McDermott(Exxon Exploration Company) interpreted the structural setting of this area.R. H. Young (Exxon Exploration Company) helped to develop the stratigraphic

framework. Quinn Passey and V. A. Clark (Exxon Exploration Company)assisted in Delta Log-R analyses. M. B. Farley, T. C. Huang, and Y. Y. Chen(Exxon Exploration Company) provided biostratigraphic interpretations thathelped constrain the stratigraphic framework. We extend special thanks toErnesto Samper (Ecopetrol), who assisted in obtaining Ecopetrol reports andlogs; Carlos Arce (Esso Colombiana), who coordinated and assisted inobtaining core, cuttings, and oil samples; and T. J. Frantes (Exxon ExplorationCompany), who facilitated the initiation and completion of this work. This paperbenefited from the critical review of editors Kevin Biddle, Wallace Dow, StevenSchamel, and Geoffrey Newton. Finally, we would like to thank ExxonExploration Company, Exxon Production Research Company, and Ecopetrolfor their permission to publish the results of this study.

Source Rocks and Oil Families, Southwest MaracaiboBasin (Catatumbo Subbasin), Colombia 1

D. A. Yurewicz,2 D. M. Advocate,2 H. B. Lo,3 and E. A. Hernández4

AAPG Bulletin, V. 82, No. 7 (July 1998), P. 1329–1352.



characterize the Catatumbo subbasin. One style isdominated by basement-involved reverse faults andfolds on the western margin of the subbasin. Thesecond style is characterized by wrench-relatedthrust faults, reverse faults, and folds associated with flexures on the western (Catatumbo f lexure)and eastern flanks of the subbasin (Figure 3). Thetiming of deformation is difficult to date precisely,but both styles appear to extend nearly to the sur-face; we postulate that they formed late (approxi-mately 8–5 Ma). This timing is consistent with thereported late Miocene–Pliocene age of uplift in theSantander massif, the Sierra de Perijá, and theMérida Andes (Kellogg, 1984; Kohn et al., 1984;Shagam et al., 1984).

Hydrocarbon traps occur as a series o f en-echelon fault-propagation and fault-bend folds. Tenfields have been discovered in the Catatumbo area with a cumulative estimated ultimate recovery (EUR) of over 550 million oil-equivalent bbl (Figure

2). The largest field is Tibu, which has an EUR of 255 million bbl of oil plus 375 billion ft3 of gas. Alldiscovered fields include a combination of oil andgas. The undeveloped Cerrito 1 discovery in thesouthern portion of the basin, however, containsdry gas only.

Stratigraphic Setting

The stratigraphic section in the Catatumbo sub-basin records deposition in three successive tecton-ic settings: (1) a Triassic–Jurassic back-arc rift set-ting, (2) a Cretaceous marginal-sag setting, and (3)a Tertiary foreland basin. The rocks deposited ineach setting are summarized in following para-graphs and in Figure 4. More detailed descriptionsof the local stratigraphy can be found in Notesteinet al. (1944), Roberts et al. (1959), Richards (1968),and Stauffer (1982).

The oldest unmetamorphosed rocks in this areaare Triassic–Jurassic red sandstones, shales, and vol-

canics that comprise the Giron Formation. Theserocks unconformably overlie igneous and metamor-phic rocks of pre-Triassic age and fill Triassic– Jurassic grabens.

Cretaceous rocks consist of fluvial and shallow-to deep-marine limestone, shale, and sandstonethat represent deposition on a broad, stable shelf ina marginal-sag tectonic setting. The principal strati-graphic units include the Uribante Group (RíoNegro, Apón, and Aguardiente formations) and theCapacho, La Luna, Colon, and Mito Juan forma-tions. The Uribante Group (Aptian–Albian) consistslargely of shallow-marine sandstone, limestone, andshale. Fractured sandstones and limestones in thisinterval are important reservoirs in the Catatumbosubbasin, and some interbedded organic-rich shaleslikely generated some of the oil and gas in thisbasin. The Capacho (Cenomanian–Santonian) andLa Luna (Santonian) formations consist of dark-gray organic-rich deeper marine carbonates and shalesand are the principal hydrocarbon source units inthis basin. They also contain minor reservoirs where they have been fractured. The CapachoFormation in the Catatumbo subbasin is referredto as the Cogollo Formation by some workers(e.g., Stauffer, 1982), but is not equivalent to theCogollo Group of Venezuela (Figure 5). TheCapacho Formation correlates to the lower LaLuna Formation in the Sierra de Perijá (Renz,1956, 1959), to the Middle Magdalena basin of Colombia, and to the lower La Luna in much of the Maracaibo basin of Venezuela. The Colon(late Santonian–Maastrichtian) and Mito Juan(Maastrichtian) formations consist of gray togreenish-gray marine shales and siltstones havinglittle chance of containing hydrocarbon source

1330 Source Rocks and Oils, Maracaibo Basin

Figure 1—Location map of study area within the Mara-

caibo basin.



beds or reservoirs. This thick, organic-lean shaleinterval is a very effective seal and isolatesCretaceous reservoirs from shallower Tertiary reservoirs.

The Tertiary section in the Catatumbo subbasin is

characterized by shales, sandstones, and minor coalsdeposited in f luvial, braided-stream, deltaic, andcoastal-plain environments (Figure 4). These rocksrecord the development of a foreland basin andencroachment of deltaic complexes associated with the uplift and erosion of the adjacent Andean oro-genic belt to the west. Many of the thin sandstones within this interval are productive reservoirs in theCatatumbo subbasin, but most of the production

from the Tertiary section is from fluvial to deltsandstones in the Barco and Mirador formatioSome interbedded shales and coals (par ticulathose in the Barco and Catatumbo formations) hhigh organic contents, but are immature for oil a

gas generation.

METHODOLOGY

Standard source rock analyses were performon 365 core and cuttings samples from eig wells, and detailed bulk compositional analy were completed on rock extracts from nine c

Yurewicz et al. 1

Figure 2—Map of theCatatumbo subbasin showing the location of fields, well samples usedfor geochemical analyseand wells used in Delta Log-R analysis.



and cuttings samples and seven oil samples(Figure 2). Standard source rock analyses includ-ed TOC (total organic carbon) measurements,Rock-Eval pyrolysis, visual kerogen analysis, and vitrinite ref lectance (%R o ). These data were sup-plemented with geochemical data from Exxonfiles on two additional Catatumbo subbasin oilsthat fell outside the original study area. The datafrom these analyses are presented in Tables 1–6.Maturity measurements from visual kerogen analyses and maturity estimates from burial history and biomarker analyses were converted to vitri-nite reflectance equivalents (VRE %R o ).

Delta Log-R, a petrophysical method of calcu-lating TOC (Passey et al., 1990), was performedon four wells in the Catatumbo subbasin. DeltaLog-R evaluates TOC variation on a stratigraphi-cally continuous basis, thereby providing a better representation of vertical and lateral variability within possible source horizons. To determinethe timing of hydrocarbon generation and migra-tion, burial history and yield analyses were com-pleted at three well sites in different parts of thebasin. These burial history models were also usedto back-calculate TOC and hydrogen indices (HI)to original conditions for source rating.

SOURCE ROCKS

Geochemical and petrophysical analyses indicatethat there are multiple organic-rich strata in theCretaceous and Paleocene stratigraphic sections of the Catatumbo subbasin. TOC data derived from coreand cuttings samples and from Delta Log-R analysesare summarized for all formations in Table 1, andorganic matter–type data derived from visual kerogenanalyses and pyrolysis data are summarized in Table 2.

Several layers of possible source rocks exist in theCretaceous section in the Catatumbo subbasin,including the La Luna Formation (excellent to goodoil source), Capacho Formation (excellent oil to poor gas source), and Uribante Group (good to poor oiland gas source). Additionally, organic-rich beds occur within the Mito Juan and Colon formations, but these

units are rated overall as poor-quality gas sources.Organic-rich shales and coals also occur in thePaleocene section in the Catatumbo subbasin. TheBarco and Catatumbo formations contain high TOCand mixtures of type III and type II organic matter,and range from poor-quality gas to good-quality oilsources; however, maturity data, yield modeling, andoil family analysis suggest that these rocks are imma-ture in the Catatumbo subbasin.


Figure 3—Schematic structural cross section, Catatumbo subbasin.



Uribante Group (Aptian–Albian)

The Uribante Group contains approximately 450 m of shallow-marine carbonates, sandstones,and calcareous shales (Figure 4). Organic-rich shales occur scattered throughout the Aguar-diente Formation and the Mercedes and Tibumembers of the Apón Formation (Figure 6; Table1). These rocks contain primarily amorphouskerogens (Table 2), but are too mature to accu-rately determine organic-matter type on a VanKrevelan diagram. These source beds range froma poor gas to a good oil rating. Although they arelocally as rich as the La Luna Formation, thesebeds typically rank as lower quality sources, as issuggested by their range of backtracked originalTOC (OTOC) values and original hydrogenindices (OHI) (Figure 7A).

Capacho Formation (Cenomanian–Santonian)

The Capacho Formation consists of Cenomanian–Santonian carbonates and shales and correlates to the

Yurewicz et al. 1

Figure 4—Stratigraphicchart for the Catatumbosubbasin.

Figure 5—Cretaceous correlation chart. The stratigrafor the Middle Magdalena basin is adapted from Scha(1991), and the stratigraphy for the Maracaibo basiadapted from Parnaud et al. (1995).



lower La Luna Formation in the Sierra de Perijá(Renz, 1956, 1959), the Maracaibo basin in Venezuela , and the Middle Magdalena basin of Colombia (Figure 5). The Capacho Formation is200–425 m thick in the Catatumbo subbasin andconsists of dark-gray to black shales and lime-stones with TOC that averages 1.27 wt. % andranges up to nearly 5 wt. % (Table 1). Delta Log-R analyses indicate that this formation includes a

thick section with a TOC of greater than 2 wt. %(Table 1; Figure 6), and that the best source faciesoccur in lowermost and uppermost Capacho. Thelowermost Capacho is interpreted to be a trans-gressive deposit. This interval recorded deposi-tion during a period of slower sedimentation anddecreased oxygen levels that were conducive toconcentration and preservation of organic matter.Kerogens are dominantly amorphous, and organic


Table 1. Summary of TOC Data in the Catatumbo Subbasin*

Rock-Derived Data Delta Log-R AnalysesSource

Average Maximum Average Maximum BedNo. of TOC TOC No. of TOC of TOC Thickness

Formation Samples (wt. %) (wt. %) Wells Beds** (wt. %) (ft)**

Tertiary Léon 2 0.50 0.61Carbonera 17 0.54 0.95Mirador 6 0.77 1.03Los Cuervos 8 0.38 0.74Barco/Catatumbo 52 6.15 68.15 3 3.0 8.0 125

CretaceousMito Juan 27 0.77 2.09 4 2.4 5.0 70Colon 35 0.66 1.13 4 2.3 6.0 50La Luna 47 4.50 11.23 4 3.4 10.0 82Capacho 33 1.27 4.96 4 3.0 13.0 142

Aguardiente 57 1.05 4.24 2 4.3 11.0 41 Apón-Mercedes 36 0.76 2.62 1 4.5 9.0 26 Apón-Tibu 45 0.66 5.67

*TOC = total organic carbon.**Beds with greater than 2 wt. % TOC.

Table 2. Summary of Organic- Matter Type in the Catatumbo Subbasin*

Visual Kerogen (%) Van KrevelenFin. Hydrogen Index Organic-Matter Type (%)

Formation Amor. Dis. Herb. Woody Coaly Algal Present Original I II III

Tertiary Léon 99 1 – – – – 18 – – 100Carbonera 10 – 39 – 51 – 35 – – 100Mirador 25 – – 100

Los Cuervos 15 – – 100Barco 60 – 5 2 33 – 84 100 – 15 85

CretaceousMito Juan 66 – 15 – 19 – 69 224 – 5 95Colon 67 24 2 – 7 – 40 – – 5 95La Luna 82 – – 2 16 – 90 525 – 75 25Capacho 85 11 – – 4 – 42 375 – 60 40

Aguardiente 79 – 4 – 17 – 20 – – 50 50 Apón-Mercedes 85 – – – 15 – 22 – – 50 50 Apón-Tibu 83 – – – 17 – 35 – – 50 50

*Amor. = amorphous, Fin. Dis. = finely disseminated, Herb. = herbaceous.



matter is interpreted to be a mix of types II andbased on pyrolysis data. The Capacho source brange from an excellent oil to a poor gas ratbased on their range of backtracked original T values and hydrogen indices (Figure 7A).

La Luna Formation (Santonian)

The La Luna Formation is a widespread strgraphic unit comprised of organic-rich limstones and shales, and represents a periodmaximum transgression and anoxic depositacross northern South America (Macellari and Vries, 1987). Geochemical analyses have shothat the La Luna Formation is the pr incisource rock in much of this area, including very prol i f ic Maracaibo basin of Ve nezu(Talukdar et al., 1986; Talukdar and Marca1994) and the Middle Ma gdalena Val leyColombia (Zumberge, 1984). La Luna TOC valin the Maracaibo basin average 3.8 wt. %, ran

between 1.5 and 9.6 wt. % (Talukdar and Mcano, 1994), and average 4.3 wt. % in the MidMagdalena Valley (Zumberge, 1984).

The La Luna Formation is approximately 60thick in the Catatumbo subbasin and consistsdark-gray, parallel-laminated, lime mudstones wackestones and minor shales. TOC analysis47 La Luna samples from se ven wells in Catatumbo subbasin yielded an average TOC4.5 wt. %, with a maximum of 11.2 wt. % (Ta1). Most samples are in the 4–5 wt. % range. Torganic matter consists predominantly of amphous kerogens (Table 2) and is interpretedbe mainly type I I based on pyrolysis daBacktracking of present-day TOC and hydrogindex data to immature “original” equivale(OTOC and OHI) shows that the La LuFormation is a good- to excellent-quality prone source unit (Figure 7A). The La LuFormation currently is within the late oil windin the Colombian portion of the Maracaibo ba(see following discussion).

Yurewicz et al. 1

Figure 6—Delta Log-R profile for a portion of the Crceous section in the Cerrito 1 well. The gamma-ray is plotted on the left, and log-calculated TOC (toorganic carbon) is displayed on the right. The calcued TOC plot shows that (1) thin intervals of high Toccur throughout the Uribante Group (Aguardiente Fmation and the Mercedes and Tibu members of

Apón Formation), (2) organic-rich facies are more psistent in the Capacho Formation, and (3) the most c

tinuous development of high TOC values occurs inLa Luna Formation.



Figure 7—Source-rating charts for (A) the La Luna, Capacho, and

Aguardiente formations, (B) theColon and Mito Juan formations,and (C) the Barco and Catatumboformations. These charts are based on estimates of original TOC (total organic carbon) and HI (hydrogen indices) that are backtracked from maturity data, organic-matter type,and pyrolysis data. Rocks with high original HI and TOC are rated as good

to excellent oil sources; rocks with low original HI and TOC are rated as poor gas sources.



Yurewicz et al. 1

T a b l e 3 .

S u m m a r y o f O i l s A n a l y z e d f o r T h i s S t u d y *

W e l l N a m e

S a r d i n a t a S u r 2 7

T i b u 4 7 9 C

T i b u 3 5 3

T i b u 3 8 8

T i b u 4 9 K

P e t r o l e a 3 4

R í o D e O r o 3 5 R í o D e O r o 1 2 R í o Z u l l i a 1 0

F o r m a t i o n

U r i b a n t e t o

C a r b o n e r a

B a r c o ?

U r i b a n t e t o

U r i b a n t e

?

L a L u n a t o

U r i b a n t e ?

U r i b

a n t e ?

M i r a d o r

B a r c o ?

B a r c o ?

U r i b a n t e

O i l G r o u p

A

A

A

A

B

B

B

B

C

A P I ( 6 0 ° F )

2 2 . 9

1 7 . 6

3 1 . 3

3 2 . 0

4 3 . 4

4 3 . 0

4 3 . 4

4 3 . 5

3 9 . 9

S u l f u r ( % )

1 . 4 9

2 . 1 2

1 . 0 7

1 . 1

0 . 0 8

0 . 0 8

0 . 0 8

0 . 0 9

0 . 3

L i q u i d C h r o m a t o g r a p h y ( % )

S a t u r a t e s

4 4 . 4

3 4 . 2

4 9 . 8

4 6 . 0

7 3 . 9

6 9 . 7

7 6 . 2

7 5 . 2

7 2 . 3

A r o m a t i c s

3 5 . 4

4 3 . 7

3 4 . 3

1 8 . 0

2 0 . 1

2 0 . 8

1 7 . 8

1 8 . 8

2 3 . 3

N S O

1 1 . 1

1 5 . 1

1 1 . 7

3 6 . 0

6 . 0

9 . 6

6 . 0

6 . 1

4 . 4

A s p h a l t e n e s

9 . 1

7 . 0

4 . 2

4 . 4

0 . 0

0 . 0

0 . 0

0 . 0

0 . 0

G a s C h r o m a t o g r a m

( C 1 0 + s a t . G C )

P r i s t a n e / p h y t a n e

0 . 7 7

0 . 8 6

0 . 8 0

1 . 1 1

1 . 1 4

1 . 0 8

1 . 0 4

3 . 3 7

P r i s t a n e / n C 1 7

0 . 6 5

0 . 5 7

0 . 5

0 . 4 9

1 . 3 7

0 . 4 6

0 . 4 5

0 . 8 8

P h y t a n e / n C 1 8

0 . 8 8

0 . 7 8

0 . 7

0 . 5 3

1 . 6 1

0 . 5 4

0 . 5 3

0 . 2 6

C a r b o n I s o t o p e ( δ 1 3 C ) ( ‰ )

S a t u r a t e s

– 2 7 . 6

– 2 7 . 3

– 2 7 . 5

– 2 7 . 5

– 2 5 . 8

– 2 5 . 2

– 2 6 . 3

– 2 6 . 3

– 2 8 . 2 1

A r o m a t i c s

– 2 7 . 0

– 2 7 . 1

– 2 7 . 0

– 2 7 . 0

– 2 4 . 3

– 2 4 . 1

– 2 5 . 1

– 2 5 . 2

– 2 6 . 9 3

B i o m a r k e r S u m m a r y

T e r p a n e / s t e r a n e s

3 . 3 2

3 . 1 0

2 . 6 1

0 . 3 8

0 . 5 8

0 . 3 4

0 . 7 1

4

T s / T m

0 . 4 4

0 . 3 7

0 . 7 2

1 . 8 3

1 . 3 2

1 . 4 4

1 . 2 8

0 . 9 8

C 2 9 / C 3 0 h o p a n e

0 . 8 1

0 . 7 5

0 . 7 8

0 . 3 7

0 . 8 8

0 . 7 6

1 . 0 4

0 . 6 4

1 8 α - O l e a n a n e / C 3 0

h o p a n e

–

–

–

–

–

–

–

0 . 2

C 3 5 / C 3 4 e x t e n d e d h o p a n e s

0 . 9 9

0 . 9 5

0 . 8 9

–

–

–

–

0 . 6 1

S t e r a n e s C 2 7 : C 2 8 : C 2 9

4 2 : 2 9 : 2 9

3 8 : 3 2 : 3 1

4 0 : 3 2 : 2 9

3 3 : 3 2 : 3 5

5 3 : 1 9 : 2 9

5 3 : 2 1 : 2 6

4 6 : 2 3 : 3 0

3 0 : 4 5 : 2 5

3 0 : 3 5 : 3 5

D i a . / r e g . s t e r a n e

0 . 3 1

0 . 3 4

0 . 4 8

0 . 8 8

1 . 0 4

1 . 0 1

1 . 9 3

0 . 7 2

( 2 0 S ) / ( 2 0 S + 2 0 R )

0 . 5 2

0 . 4 8

0 . 5 1

0 . 3 1

0 . 3 8

0 . 4 3

0 . 6 4

0 . 4 9

M P I * *

0 . 5 4

–

0 . 5 5

1 . 0 9

1 . 3 6

1 . 0 2

0 . 9 9

T A / ( M A + T A )

0 . 7 6

0 . 5 9

0 . 7 0

–

–

0 . 8 8

0 . 8 1

T A S † ( 2 0 + 2 1 ) / ( 2 0

– 2 9 ) 2 3 1

0 . 1 7

0 . 1 0

0 . 1 8

–

–

0 . 8 1

0 . 8 1

M A S † † ( 2 0 + 2 1 ) / T o t a l 2 5 3

0 . 8 4

0 . 0 9

0 . 1 8

1 . 0 0

1 . 0 0

* D a

t a f o r

t h e o

i l s f r o m

T

i b u

3 8 8 a n

d R í o Z u

l i a w e r e

f r o m

e x

i s t i n g

E x x o n f

i l e s .

A l l o

t h e r s a m p

l e s w e r e o

b t a i n e

d a n

d a n a

l y z e

d f o r

t h e

E x x o n

/ E c o p e

t r o l s

t u d y .

* * M P I = m e

t h y

l p h e n a n t

h r e n e

i n d e x .

† T A S =

t r i - a r o m a

t i c s

t e r

o i d ( m / e 2 3 1 ) .

† † M A S = m o n o - a r o m a t i c s

t e r o

i d ( m / e 2 5 3 ) .



Colon and Mito Juan Formations (LateSantonian–Maastrichtian)

Organic-rich intervals also occur in the Upper Cretaceous Mito Juan and Colon shales above theLa Luna Formation. Overall, measured TOC valuesare low (less than 1 wt. %), but Delta Log-R analy-ses indicate that there may be 30–50 m (100–150ft) of shale with TOC values greater than 2 wt. %in this interval. Organic matter is typically type IIIand hydrogen indices are low, so that the bedsgenerally rate as poor-quality gas sources (Figure7B). Yield modeling of the Colon Formation indi-cates that it may be generating some oil in deeper parts of the Catatumbo subbasin (see Maturationdiscussion).

Catatumbo and Barco Formations(Maastrichtian–Paleocene)

The Barco and Catatumbo formations areapproximately 245 m thick and consist of cross-bedded fluvial to deltaic sandstones, dark-gray deltaic shales, and minor coals. Organic-rich shales and coals in the Barco and Catatumbo for-mations have TOC values that range as high as

68 wt. % in some coals and 10–12 wt. % in someshales. Organic matter consists of a mixture of amorphous, finely disseminated, coaly, and herba-ceous kerogens and is interpreted to be predomi-nantly type III with a minor contribution of type II

based on pyrolysis data. Although the Barco andCatatumbo formations have beds with high TOCcontents, the relatively low hydrogen indices thatcharacterize this interval indicate that it is typical-ly a poor- to fair-quality gas source (Figure 7C);furthermore, maturation data and modeling of hydrocarbon yields indicate that these formationsare immature for hydrocarbon generation in theCatatumbo subbasin.

OIL FAMILIES

Oil samples from seven wells in the Catatumbosubbasin were analyzed for this study to identify oilfamilies and to correlate possible source intervals


Figure 8—Schematic east-west cross section of the Catatumbo showing the stratigraphic distribution of oil groupsand possible migration pathways from Cretaceous source rocks.

Figure 9—Gas chromatograms and mass fragmen-tograms for typical group A and group B oils.





to the pooled hydrocarbons. These data were sup-plemented with Exxon data on two additional oilsamples from the Catatumbo subbasin (Figure 2;Table 3).

The nine oil samples examined from the Cat-atumbo area can be placed within three groups. Thefirst two groups (A and B) are probably members of asingle oil family; that is, they have similar geochemi-cal characteristics that indicate they were generatedfrom a common source. The third group (C) is inter-preted as a separate oil family that has a source differ-ent from A or B oils. Most of the oil samples fall with-in groups A and B. Group C is comprised of a singleoil sample from Río Zulia field.

Group A oils are principally found in Tertiary sandstone reservoirs (Figure 8) and are character-ized by low to moderate API gravity (17.6–32°), ahigh sulfur content (0.8–2.12%), moderate satu-rates/aromatics ratios, low diasteranes, and amoderate level of maturity (VRE of 0.55–0.75 %R o )(Figure 9). Group B oils are from Cretaceous lime-stone and sandstone reservoirs (Figure 8) andhave high API gravities (40.6–54.6°), low sulfur content (0.03–0.10%), high saturates/aromaticsratios, higher diasteranes, and a high level of maturity (VRE of 0.9–1.1 %R o ) (Figure 9). Group

Figure 10—Gas chromatograms and mass fragmen-tograms for group C oil, Río Zulia field.

Figure 11—Stable carbon isotopic composition of 17 oilsand 9 rock extracts from the Catatumbo subbasin and adjacent fields in Venezuela. The data show the differen-tiation of group A and B oils and the close correlation of La Luna and Capacho extracts to these oils. Barcoextracts overlap with the group C oil.



A oi ls have lighter (more negative) carbon iso-topic values than group B oils (Figure 11).Characteristics of each group are presented inTables 4 and 5.

Group A and B oils are interpreted to be twomembers (subfamilies) of a single oil family thathad a similar source. Biomarker signatures suggestthat these oils were generated from marine carbon-ate rocks that contain primarily algal organic mat-ter. Evidence of a marine source for these oilsincludes their low pristane/phytane ratio (Figures

9, 12, 13), low ratio of C29 /C27 steranes (Figure 12),low hopane/sterane ratio, abundance of extendedtricyclic terpanes, and low abundance of waxy n-alkanes (nC27 /nC17 ratio) (Figure 13). Differencesin the two subfamilies probably reflect minor varia-tions in maturity or the relative amount of ter-rigenous material within the source interval.Differences in API gravity, sulfur content (Figure14), saturates/aromatics ratios, and Ts/Tm ratios

are likely due to differences in maturity. Grouoils are from older and deeper Cretaceous res vo irs and have many charact er ist ics of higmature oils. The higher diasterane/regular sterratios in group B oils may be due to a higher rigenous content in the source facies or to its her maturity.

The group C oil occurs within the TertiMirador Formation in Río Zulia field and diffmarkedly from group A and B oils. Group C chacteristics indicate it is a mature to highly mat

oil derived primarily from nonmarine organic mter (Figure 10). Evidence for a nonmarine souincludes its high pristane/phytane ratio, hnC27 /nC17 ratio, low C27 /C29 sterane ratio, and presence of oleananes. The high diasterane/relar sterane ratio indicates a clay-rich source facand is consistent with a nonmarine source facSome properties of the group C oil may indicatnonmarine source or high maturity. Th

Yurewicz et al. 1

Table 4. Summary of Group A Oils, Wells Sardinata Sur 27, Tibu 479C, Tibu 353, and Tibu 383, Catatumbo Subbas

Property Implication

Low to moderate API gravity (17.6–31.3°) Mature oil

High sulfur content (0.8–2.12%) Carbonate sourced and/or biodegraded oils

Lower saturates/aromatics ratio and more NSO and Biodegraded and/or lower maturity than group B o

asphaltene than group B oils

Pristane/phytane ratio 0.77–1.29 Anoxic to dysoxic depositional environment

Some alkane peaks decreased or disappeared Biodegradation of the oils (Sardinata 27 andin whole-oil gas chromatograms Tibu 479C)

Lighter carbon isotopic values than group B Different source rock with lighter carbon isotopesthan group B or similar sources, but oils are lessmature than group B

Abundant tricyclic terpanes, with extended Oils generated from algal organic matter;tricyclic up to C31 carbonate source rocks

C27 /C29 steranes 1.08–1.46 Marine algal source

nC27 /nC17 0.09–0.46 Marine source

Hopane/sterane ratio 1.45–4.17 Marine source

Ts/Tm 0.37–0.72

Oleanane/C30 hopane ratio was not measurable

C35 /C34 extended hopanes 0.45–0.99 (visually > 1) Anoxic environments (includes carbonatesand evaporites)

Diasterane/regular sterane 0.31–0 .57 Little contribution from clay-rich clastics

Good tri-aromatic and mono-aromatic steroids Mature oils



properties include a low sulfur, nickel, and vanadi-um content. The high API gravity, high saturates/ aromatics ratio, the lack of asphaltenes, and high Ts/Tm ratio all indicate that the group C oil is amoderate- to high-maturity oil. There also is evi-dence that this dominantly nonmarine oil wasmixed with oil sourced from marine organic mat-ter. This evidence includes the elevated tricyclicterpanes and low hopane/sterane ratio. Char-acteristics of the group C oil are summar ized inTable 6.

Talukdar et al. (1986) placed oils in the Ven-ezuelan portion of the southwest Maracaibo basininto three oil families: (1) a mature to highly mature marine oil of La Luna origin (very similar to the group A and B oils studied here), (2) amature terrestrial oil sourced from Paleoceneshales (similar to group C), and (3) a mixedmarine and terrestrial oil. The mature marine oilsoccur in Eocene reservoirs in El Rosario field, andthe highly mature marine oils are produced from

Cretaceous reservoirs in West Tarra and ElRosario fields (see Figure 2 for the location of these fields). Terrestrial oils have been identifiedin Eocene reservoirs at Los Manueles f ield.Characteristics of these oils are summarized inTable 7. The mixed marine and terrestrial oilshave been identified from Eocene and Paleocenereservoirs in West Tarra, Los Manueles, and LasCruces fields. These oils show geochemical traitsof both the marine and terrestrial oils and arecharacterized by n-alkane, sterane, and terpanedistributions typical of marine oils, elevatedhopane/sterane ratios (7–9), and an abundance of oleanane typical of the terrestrial oils. Our inter-pretations agree well with Talukdar et al. (1986),although we did not recognize a purely terrestrialoil in any of our samples. Figure 15 summarizesthe distribution of oil families in the Colombianand Venezuelan portions of the southwestMaracaibo basin based on data from this study and work by Talukdar et al. (1986).


Table 5. Summary of Group B Oils, Wells Petrolea 34, Tibu 49K, Río De Oro 12, and Río De Oro 35, CatatumboSubbasin


High API gravity (40.6–54.6°) High-maturity oils

Low sulfur content (0.03–0.10%) Mainly due to high maturity of oils

Higher saturates/aromatics ratio and no asphaltene Mainly due to high maturity of oils

Pristane/phytane ratio 1.04–1.16 Anoxic to dysoxic depositional environment

Heavier carbon isotopic values than group A Same source but more mature, or differentsource with heavier carbon isotopes

Dominant tricyclic terpanes, with Marine carbonate source or lacustrine salineextended tricyclic up to C36T source (DeGrande et al., 1993); the

lacustrine source can be ruled out (low hopane/sterane ratio)

C27 /C29 steranes 1.17–2.09 Marine algal source

nC27 /nC17 0.15–0.44 Marine source

Hopane/sterane ratio 0.30–0.71 Marine source

Ts/Tm 0.36–5.63 May be smaller when less mature

Oleanane/C30 hopane ratio was not measurable

C35 /C34 extended hopanes 0–1.52

Diasterane/regular sterane 0.88–1.93 Cannot assess how much of the high valuesare due to high maturity vs. clay richness

Very weak tri-aromatic and mono-aromatic steroids Due to high maturity of oils



OIL–SOURCE ROCK CORRELATIONS

Extracts from eleven rock samples in fiveCatatumbo subbasin wells were analyzed for thisstudy to correlate possible source intervals to thetrapped crude oils (Figure 2; Table 8). Analyses were completed on samples from the Barco, Mito Juan, La Luna, and Capacho formations. Extract sig-natures of the Capacho and La Luna samples aresimilar to the group A and B oils (Table 3) and sug-gest that similar organic-rich facies sourced most of the oil in this region. Stable carbon isotopes of theCapacho sample can be correlated to either thegroup A or group B oils (Figure 11). The Capacho

Yurewicz et al. 1

Figure 13—Pristane/phytane vs. nC27/nC17 of Catatumsubbasin oils. The nC27/nC17 ratio is a measure of

waxy composition of an oil, and thus indicates terre

al sources. The high nC27/nC17 ratio of the group Ccombined with its high Pr/Ph ratio, suggests a terrnous origin. Group A and B oils appear to have a comon source.

Figure 12—Source affinity of oils and rock extracts with-in the Catatumbo subbasin based on redox state vs.organic-matter type from isoprenoids and steranes. Thisdiagram shows that group A and B oils were sourced from anoxic source rocks with predominantly algal

organic matter. The La Luna and Capacho rock extractsare very similar to these oils and were the probablesource. The group C oil appears to have been generated from a more oxic source facies. Group C oil is similar tothe Barco extracts, which have an aerobic, dominantly terrestrial organic-matter signature.

Figure 14—Percent sulfur vs. API gravity of Catatumsubbasin oils. In general, marine-sourced oils h

higher sulfur contents than lacustrine or nearshmarine-sourced oils; however, sulfur content is higdependent on thermal maturity, with sulfur contdecreasing with increasing thermal maturity. Ttrend shown here may reflect increasing maturity

Tertiary (group A) to Cretaceous (group B) reservoioils. Note the high API gravity and low sulfur of the Zulia oil (group C) compared to other oils reservoiin Tertiary formations.



sample is overmature for biomarker signatures andtherefore cannot be positively correlated with theoils. Stable carbon isotopes of the La Luna samples

correlate closely with the group B high-maturity oils; La Luna biomarker signatures are more similar to group B high-maturity oils than the group A oils.


Table 6. Summary of Group C Oil, Well Río Zulia 10, Catatumbo Subbasin


High API gravity (39.9°) Mature oil

Low sulfur content (0.3%) Terrestrial source or high maturity

High saturates/aromatics ratio, low NSO, and High maturity

no asphaltene

High pristane/phytane ratio (3.37) Terrestrial source

Lighter carbon isotopic values than group B; Different source rock with lighter carbonsimilar to group A isotopes than group B, or similar sources but oils are

less mature than group B

Elevated tricyclic terpanes (high C23T) Marine algal source

C27 /C29 steranes (0.87) Terrestrial source

C27 /nC17 (0.91) Terrestrial source

Hopane/sterane ratio (4) Marine source

Ts/Tm (0.98) Moderate to high maturity

Oleanane/C30 hopane ratio (0.2) Contribution from higher plants; middle Cretaceous or younger sources

C35 /C34 extended hopanes (0.61)

Diasterane/regular sterane (0.72) Some contributions from clay-rich clastics

Low nickel and vanadium content Terrestrial source or high maturity (8 ppm nickel, 8 ppm vanadium)

Table 7. Characteristics of Oils Within the Southwest Maracaibo Basin, Venezuela*

Mature Marine Oils Highly Mature Marine Oils Terrestrial Oils

API gravities: 20–39° API gravities: 37–55° API gravities: 36°Sulfur content: 0.7–1.3% Sulfur content: <0.5% Sulfur content: <0.5%

Vanadium content: 20–235 ppm Vanadium content: <8 ppm Vanadium content: <4 ppmSaturated hydrocarbons: 53–69% Saturated hydrocarbons: 72–93%Resins and asphaltenes: 8–22% Resins and asphaltenes: 0.2–8.8%

Aromaticity ratio: >70% Aromaticity ratio: 77–100% Abundant n-alkanesPristane/phytane ratio: >3High C29 sterane stereoisomerscompared to C27 sterane stereoisomers

Low concentration of tricyclic terpanesPresence of triterpane 18α oleananeHopanes/sterane ratio >10

*Data from Talukdar et al. (1986).



These data suggest that the La Luna Formation isthe source for group B oils, whereas the Capachoand Uribante rocks may contribute more to thegroup A oils.

Extract analyses of the Barco and Mito Juan sam-ples are similar to the group C oil. Key points of comparison include the carbon isotope data(Figure 11), the pristane/phytane ratio vs. C29 /C27sterane ratio (Figure 12), and the presence of oleanane. Maturation data (vitrinite, Tmax, and ther-mal alteration index) and burial history models,however, indicate these units are immature for hydrocarbon generation in the Catatumbo sub-basin. The presence of Paleocene-sourced oils inthe Catatumbo subbasin thus indicates migrationfrom a more mature Tertiary source kitchen, proba-bly in Venezuela (see the discussion on Migration).

Paleocene shales and coals have been suggestedby others to be the probable source for oils generat-ed from terrestrial organic facies in the Venezuelanportion of the southwest Maracaibo basin (Blaser and White, 1984; Talukdar et al., 1986; Cassani et al.,1989; Talukdar and Marcano, 1994; Mendez and

Scherer, 1995). Paleocene shales and coals Venezuela have been shown to have high TOC valand hydrogen indices, are locally mature, and hbeen correlated to terrestrial facies oils. For examPaleocene shales and coals on the north flank of Mérida Andes have high TOC values (7.6–39.4 wt.type III kerogens, high hydrogen contents, and sucient maturity to generate oil and gas (Blaser a

White, 1984; Cassani et al., 1989). Thermal matumodeling by Blaser and White (1984), Talukdar et(1986), and Talukdar and Marcano (1994) showthat these shales also are mature along the southwflank of the Maracaibo basin in Venezuela. Terresoils in this area have been correlated with orgamatter in the Paleocene Orocue group (CatatumBarco, and Los Cuervos formation equivalents) the Eocene Carbonera Formation by Cassani et(1989) and Tocco et al. (1990); however, these woers discount the Carbonera as a viable soubecause it is immature.

SOURCE MATURATION

Burial history and yield analyses were compleat three well sites in different parts of the Catatumsubbasin: the Cúcuta 2 well in the south, the T91K well in the center, and the Río de Oro 14K w(Figures 16–19) in the northern part of the stuarea (see Figure 2 for locations). Each site was amodeled, removing late Miocene–Pliocene upand erosion to estimate the burial and thermal hiry of source rocks in adjacent synclinal drainareas (compare Figures 17 and 19).

Maturation data and burial history modeling incate that only the Upper Cretaceous La Luna aCapacho formations, and the Lower CretaceUribante Group, have generated hydrocarbons win the Catatumbo subbasin, except for deeper ptions of the basin where the Colon shale has abegun to generate oil and gas (Figure 18). Maturatdata and burial history modeling show that Paleocene Barco Formation is immature in Catatumbo subbasin, but regional maturation mshow that it is mature in adjacent Venezuela (Blaand White, 1984). Oil generation from Cretacesource rocks began as early as the late Eocene–eOligocene, with peak oil generation taking placethe late Miocene (Figure 16). Source beds hcooled due to removal of overburden, and oil gention has ceased on structures that were uplifted eroded in the late Miocene–Pliocene (Figure 1 while the same beds in the adjacent synclines are generating hydrocarbons (Figure 18). Althoughgeneration began prior to trap formation in the lMiocene–Pliocene, the two critical events do ovlap, thus providing a source of hydrocarbons for late-forming traps. Discovered hydrocarbons

Yurewicz et al. 1

Figure 15—Map of the southwest Maracaibo basin show-ing the distribution of oil families in Colombia and

Venezuela based on data from this study and published data in Talukdar et al. (1986).



principally oil with some gas, which is consistent with predictions made by burial history and yieldmodels. More gas could be expected locally wherethe source beds have undergone greater burial, or possibly where the source facies contains more ter-restrial organic matter.

The timing of source rock maturation in our burial history models is approximate and dependson estimation of two critical factors: (1) the timingand magnitude of anomalous heat flow and (2) theamount and age of deposition, uplift, and erosion.Heat-flow estimates were constrained by downhole


Table 8. Summary of Rock Extract Analyses

Well Name Tibu Tibu Socuavo Socuavo Cerro Tibu Tibu Tibu Sardinata178K 178K 1 1 Gordo 3 408K 408K 408K Norte 2

Depth Top (ft) 7116.01 7145.59 7515.43 8238.93 1100.01 4243.42 4334.51 4734.51 4232.42Depth Base (ft) 7124.67 7165.83 7545.83 8312.5 1400.00 4243.42 4467.33 4755.25 4232.42Formation La Luna La Luna La Luna Capacho Barco/ Barco Barco Barco Barco

Mito JuanTotal Organic Carbon and Rock-Eval Pyrolysis (extracted)

TOC (wt. %) 3.75 4.44 4.80 5.08 1.38 69.84 1.03 2.80 20.76Tmax (°C) 448 454 452 454 442 427 443 440 424S1 (mgHC/g rock) 0.13 0.14 0.14 0.21 0.07 2.83 0.06 0.19 0.52S2 (mgHC/g rock) 3.90 3.93 6.25 2.96 1.76 168.14 0.64 11.37 40.99S3 (mgCO2 /g rock) 0.27 0.54 0.47 0.34 0.53 4.30 0.53 0.36 1.98PI [S1 /(S1+S2 )] 0.33 0.03 0.02 0.07 0.04 0.02 0.09 0.02 0.01HI (mg HC/g TOC) 104 89 130 59 128 241 62 406 198OI (mg CO2 /g TOC) 7 12 10 7 38 6 51 13 10

Approximate LOM 10–11 10–11 11–11.5 11.5–12 8–9 8–8.5 8–8.5 8–9 7–8(%R o and thermal alteration index)

Approximate VRE 0.85–1.1 0.85–1.1 1.1–1.2 1.2–1.5 0.55–0.65 0.55–0.60 0.55–0.60 0.55–0.65 0.50–0.55Liquid Chromatography

Saturates 58.4 53.3 41.6 65.7 26.0 10.7 20.9 45.5 32.4

Aromatics 21.2 23.2 28.4 16.9 23.4 34.3 34.9 24.8 35.6NSO 17.8 19.8 25.1 16.0 44.6 42.6 30.2 26.2 13.6

Asphaltenes 2.6 3.7 4.9 1.4 6.0 12.4 14.0 3.5 5.6

Gas Chromatography Pristane/phytane 1.39 1.34 1.23 1.38 4.96 1.73 2.29 7.71 6.09Pristane/nC17 0.79 0.54 0.61 0.85 3.74 0.92 1.84 4.48 4.95Phytane/nC18 0.68 0.53 0.61 0.74 0.72 0.63 0.92 0.55 0.98

Carbon Isotope ( δ13C) (‰)Saturates –26.6 –25.5 –26.2 –27.6 –28.6 –27.3 –28.6 –31.3 –32.4 Aromatics –25.7 –25.1 –25.3 –25.8 –27.3 –26.0 –27.1 –32.0 –29.0

Biomarkers Summary Terpane/steranes 1.16 1.82 0.86 1.18 17.84 18.09 9.22 201.50 28.01

Ts/Tm 1.38 0.79 1.99 0.76 0.12 0.06 0.17 0.08 0.12C29 /C30 hopane 0.70 1.45 0.96 0.82 1.09 0.60 0.56 1.42 1.53Oleanane/C30 hopane – – – – 0.29 0.22 0.12 0.06 0.05C35 /C34 extended hopanes – – – – 0.44 0.55 0.50 0.37 0.41Steranes C27:C28:C29 44:25:31 – 44:32:24 – 21:24:54 16:41:43 20:36:44 0:100:0 26:39:35Steranes C27 /C29 1.42 – 1.83 – 0.39 0.37 0.45 – 0.74Dia/Reg Sterane 1.45 – 0.84 – 0.43 0.59 0.61 0.94 0.54

(20S)/(20S+20R) – – 0.50 – 0.58 0.42 0.46 – 0.78MPI* 0.99 0.99 0.78 1.23 0.57 0.60 0.58 0.63 0.58TA/(MA + TA) 1.00 1.00 1.00 1.00 0.47 0.20 0.37 0.58 0.61TAS** (20+21)/(20–29) 231 1.00 1.00 1.00 1.00 0.12 0.21 0.46 0.07 0.29MAS† (20+21)/Total 253 0.10 – – – – 0.10 0.12 0.08 0.13

*MPI = methylphenanthrene index.**TAS = tri-aromatic steroid (m/e 231).†MAS = mono-aromatic steroid (m/e253).



temperatures observed in the wells that were stud-ied. Modeling of temperature data suggests a present-day heat flow of 1.5–1.7 HFU (heat-flow units) anda temperature gradient of 1.7–2.0°F/100 ft(0.29–0.34°C/100 m). This present-day heat f low reflects the sum of contributions from a Late Jurassic thermal anomaly associated with back-arcrifting, crustal radiogenic heat flow, background

mantle-derived heat flow, and conductive propties of the strata. The anomalous heat flow geneed by Late Jurassic rifting was determined by meling middle Cretaceous–Paleocene subsidenceeach site. Subsidence during this time intervapredicted to be chiefly driven by crustal attention due to rifting and subsequent cooling. Oburial history models predict that the crust

been thinned approximately 30–40%.Late Tertiary deformation in the Catatum

subbasin was dominated by wrench tectoniThis tectonic event did not create a regionally vated heat f low and had little effect on the thmal history of the area, other than to cause louplift and lower the thermal conditions of rocks at those sites.

Post-Jurassic burial history for this area wmodeled using the preserved stratigraphic stion at each of the well sites used in this stuNone of the sites studied contain a complstratigraphic record. The Eocene Mirador Foation is at the surface at the Río de Oro 14K w

whereas the Miocene Léon Formation crops at the Tibu 91 and Cúcuta 2 well sites. Estimaof the missing section were made at each susing published reports on the range in strgraphic thickness of individual formations, afrom correlations with nearby wells that peneted younger stratigraphic intervals. Burial histormight be improved with (1) a better restoratof missing upper Tertiary formations and more detailed biostratigraphic data to refine a

Yurewicz et al. 1

Figure 16—Instantaneous hydrocarbon yield curves for the Río de Oro 14K well. The curve shows that oil gener-ation began in the Oligocene and reached peak yield at 12–5 Ma. Hydrocarbon generation rapidly declined oncethe structure was uplifted.

Figure 17—Burial history curv

for beds in the Río de Oro 14K well. The La Luna Formation ishighlighted for reference.



and rates of subsidence for individual formations,plus the extent of possible unconformities.

MIGRATION

Our current geochemical data, which includecharacterization of source beds within the Cata-tumbo subbasin, correlation of oils to possiblesource beds in the Cretaceous section, maturationdata, and burial history modeling, all indicate thatmost of the oils in the Catatumbo subbasin werelocally sourced from Cretaceous shales and lime-stones. Three distinct migration systems have likely operated to fill Catatumbo subbasin traps that devel-oped in the late Miocene–Pliocene. Oils reservoiredin the Cretaceous section represent one migrationsystem. These oils likely migrated directly into thereservoir from adjacent Cretaceous source beds, andalong fractures and faults that developed in the lateMiocene–Pliocene. The estimated maturity of theoils (determined from a combination of parame-ters including %20S of the C29 sterane saturatedbiomarkers, methylphenanthrene index of the

aromatic biomarkers, percent tri-aromatic steraneof the aromatic biomarkers, and the isoprenoidratio of the C4–C19 saturated hydrocarbons) inthese reservoirs (VRE of 0.9–1.1 %R o ) falls withinthe range of measured maturity of Cretaceoussource rocks (0.85–1.99 %R o ) (Table 9), suggest-ing either that earlier generated oils have beendisplaced by or mixed with more mature later generated oils, or that earlier generated oils have

continued to mature in the reservoir along with adjacent source beds.

Most of the Cretaceous-sourced oils reservoiredin Tertiary sandstones represent a second migrationsystem. Oils reservoired in the Tertiary section areseparated from the Cretaceous source kitchen by athick succession of shales in the Late CretaceousColon and Mito Juan formations. These shales forman effective seal and limit cross-stratal migration;therefore, oils reservoired in Tertiary sandstonesprobably migrated from Cretaceous source bedsalong fractures and faults that developed concur-rent with trap formation in the late Miocene–Pliocene. The estimated maturity of the oils inthese reservoirs (VRE of 0.55–0.75 %R o ) is wel lbelow the range of measured maturity of Cre-taceous source rocks (0.85–1.99 %R o ), wh ich implies that the fractures and faults that were con-duits for filling Tertiary reservoirs are no longer active migration pathways. Figure 8 shows possiblemigration pathways along faults into Cretaceousand Tertiary reservoirs.

Oils in Río Zulia field require a third migrationmodel. Isotope and biomarker analyses of these oils

(Figures 10–13; Table 6) indicate that they weresourced from Paleocene shales and coals in theBarco and Catatumbo formations; yet maturationdata and burial history modeling indicate that theserocks are immature for hydrocarbon generation inthe Catatumbo subbasin. These oils, therefore,must have migrated laterally from areas where theBarco Formation is mature. Maturation levels inthe Barco Formation increase westward into the


Figure 18—Instantaneoushydrocarbon yield curve for Cretaceous source beds modeled for an off-structure location from the Río de Oro 14K well. Thecurve shows that oil generation

began in the Oligocene, reached peak yield at 12 Ma, and is still generating liquids.



Maracaibo basin and along the axis of the North Andean foredeep that borders the nor thwesternflank of the Mérida Andes (Figure 1). Organic-rich coals and shales in the Barco Formation analyzedfrom the Catatumbo subbasin are characterizedby low to moderate hydrogen indices (H I =100–300). Burial history modeling indicates thatthe low hydrogen index source facies (HI =100–200) require a VRE of 0.8 %R o or greater before they begin to generate hydrocarbons.Source beds such as these may only be generatingoil and gas along the North Andean foredeep.Only a small fraction of the Barco Formationsource beds analyzed from the Catatumbo sub-basin have hydrogen indices of 300. Burial history modeling indicates that these source beds may begin to generate hydrocarbons at a VRE of 0.65 %R o.Barco Formation source beds with these charac-teristics may be actively generating oil and gasover a larger portion of the Maracaibo basin.Tertiary-sourced oils reservoired in Río Zulia field,therefore, may have migrated out of the North Andean foredeep or perhaps from less mature por-tions of the Maracaibo basin. The proximity of RíoZulia field to the North Andean foredeep, and lack of Tertiary-sourced oils in other Catatumbo fields,suggest that the North Andean foredeep is the pri-mary source area of these oils.

The fields in the Catatumbo subbasin containsome gas in addition to oil, and the Cerrito discov-ery in the southernmost Catatumbo subbasin is

reported to be all gas (Figure 2). Burial history yield modeling show that Cretaceous oil sourocks have begun to generate gas, and thsource rocks are considered to be the primsource for much of the gas in the Catatumbo sbasin. Some gas, however, may have migrated frsource kitchens in Venezuela. In particular, source kitchen along the North Andean foredmay be actively generating gas from a wide rangsource rocks and may be the source of gas encotered in the Cerrito discovery. There may be adtional occurrences of gas in the southeCatatumbo subbasin from this same source area

SUMMARY AND CONCLUSIONS

Geochemical analyses indicate there are multistratigraphic intervals with good oil- and gas-generacharacteristics in the Catatumbo subbasinColombia. These characteristics include organic-rshales and limestones within the Cretaceous Ap Aguardiente, Capacho, and La Luna formations, shales and coals within the Paleocene Barco aCatatumbo formations. Cretaceous hydrocarbsource units are characterized by high original T(total organic carbon) and hydrogen contents anpredominance of amorphous organic material. Ttype of source rock is capable of high liquid yiSource adequacy does not appear to be a signcant risk factor in the Catatumbo subbasin.

Yurewicz et al. 1

Figure 19—Burial history curvemodeled for an off-structurelocation from the Río de Oro14K well.



Most of the oil in the Colombian portion of thesouthwest Maracaibo basin belongs to one oil family and was generated in Cretaceous marine sourcerocks. Based on a number of biomarker, isotopic,and compositional parameters, this source has beeninterpreted to be marine algal-rich rock deposited inan anoxic carbonate-shelf setting. Some of the key oil characteristics that indicate these source condi-tions include high sulfur content, pristane/phytaneratios of less than 1, dominance of C27 steranes,presence of extended tricyclic terpanes with a C23dominance, and C35 /C34 extended hopanes greater than 1. Based on a number of saturate and aromaticbiomarkers, and tri-aromatic steranes, a generationand expulsion maturity range of VRE (vitrinitereflectance equivalents) of 0.55 to 1.0 %R o is esti-mated for the oils in this area. In general, extractsfrom Cretaceous samples (0.85–1.5 %R o ) were toomature for biomarker correlation with the oil sam-ples; however, isotopic data show a positiveoil–source correlation to Upper Cretaceous La Lunaand Capacho formations.

Río Zulia field and some of the nearby fields in Venezuela contain mixed terrestrial (Tertiary) andmarine (Cretaceous) oils. The terrestrial componentof these oils probably was derived from organic-r ich shales and coals within the Paleocene Barcoand Catatumbo formations. The Río Zulia oil sam-ple is characterized by low sulfur, pristane/phytaneratios greater than 3, low abundance of tricyclicterpanes, abundance of oleanane, and predomi-nance of C29 steranes and diasteranes. Paleoceneorganic-rich rocks in the Catatumbo subbasin havesimilar attributes, but maturity data and burial his-tory modeling indicate that they are immature. We

postulate that Tertiary terrestrial-sourced oils in theCatatumbo subbasin were derived from similar Paleocene rocks in source kitchens along the North Andean foredeep. Paleocene rock samples in theCatatumbo subbasin have a low to moderate hydro-gen content with high TOC and are dominated by amorphous and coaly organic material. This typeof source facies is more gas prone than theCretaceous source rocks and may be responsiblefor some of the gas, as well as the some of the oil,found in the Catatumbo area.

Maturity data and burial history analyses indicatethat Cretaceous source rocks are mature and havebeen generating hydrocarbons since the lateEocene or early Oligocene; however, it appears thatPaleocene source rocks have not yet reached matu-rity within the Catatumbo subbasin. Peak oil gener-ation from Cretaceous source beds occurred in thelate Miocene and largely predated lateMiocene–Pliocene trap development. These sourcebeds, however, have continued to generate andexpel hydrocarbons and are filling the young traps.

Most of the oil and gas within the Catatumbosubbasin was sourced locally, although some oil,especially the oils sourced from terrestrial organicfacies in Río Zulia field and perhaps gas in Cerritofield, may have migrated from a source kitchenalong the North Andean foredeep in Venezuela.Oils generated from Cretaceous source rocks thatare reservoired in Cretaceous and Tertiary forma-tions have had different migration and maturationhistories. Oils in Cretaceous reservoirs have migrat-ed laterally from adjacent source beds and alongfractures and faults that developed during lateMiocene–Pliocene trap formation. The maturity of


Table 9. Average Vitrinite Reflectance by Formation and Sample Location*

Well Name

Tibu Carbonera Cerro Tibu Socuavo Tibu Río de Oro SardinataFormation 91K 5K Gordo 3 178K 1 408K 14 Norte 2

Tertiary Léon – – – – – – – –

Carbonera – – – – – – – –Mirador – – – – – – – –Los Cuervos – – 0.52 (1) – – – – –Barco – – 0.55 (1) – – 0.51 (13) 0.50 (2) 0.52 (2)

CretaceousMito Juan – 0.56 (5) 0.55 (2) – – – 0.63 (1) –Colon 0.68 (2) 0.60 (1) 0.64 (4) – – – 0.72 (1) –La Luna – – 0.85 (1) 1.01 (7) 1.21 (2) – 1.05 (1) 1.15 (2)Capacho 0.94 (2) 1.24 (2) 1.22 (2) – 1.14 (5) – 0.96 (1) –

Aguardiente 1.14 (1) 1.59 (1) 1.42 (2) – – – 1.04 (4) 1.37 (2) Apón-Mercedes – 1.58 (1) 1.48 (1) – – – 1.13 (3) 1.78 (2) Apón-Tibu – – 1.56 (1) 1.46 (4) – – 1.12 (2) 1.99 (1)

*Number of samples measured is in parentheses.



these oils closely matches the maturity of adjacentsource beds, suggesting that earlier generated oilshave been displaced by later generated oils or thatearlier generated oils have continued to mature inthe reservoir along with adjacent source beds.Cretaceous-sourced oils that are trapped in Tertiary reservoirs have migrated along fractures and faultsthrough a thick Upper Cretaceous shale seal. These

oils are less mature than the Cretaceous sourcebeds in the Catatumbo subbasin, suggesting thatthese conduits are no longer active.

Source adequacy is not a risk in the Catatumbosubbasin. There are multiple intervals with goodsource characteristics that have generated oil andgas during and after trap formation. The greatestrisk within this area is the possibility of encounter-ing primarily gas along the southern flank of theCatatumbo subbasin. The gas discovery at Cerrito 1points to a greater chance of encountering gas inthe southern portion of the basin and may reflectproximity to the very mature source kitchen in theNorth Andean foredeep.

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Yurewicz et al. 1



Don Yurewicz

Don Yurewicz received a B.A.degree (1970) in geology fromRutgers University and an M.S.

(1973) degree and Ph.D. (1976)from the University of Wisconsin.He joined Exxon Production Re-search Company in 1977, wherehis work focused on carbonatereservoirs and source rocks. Hetransferred to Exxon U.S.A. in 1985and was active in exploration alongthe U.S. Gulf Coast and in the midcontinent. Since 1991he has worked for Exxon Exploration Company, wherehis work has included regional studies in Colombia,

Venezuela, Bolivia, and Mexico. He is currently assignedto regional studies in the Middle East.

Dave Advocate

Dave Advocate received B.S.(1979) and M.S. (1983) degrees ingeology from California StateUniversity, Northridge. He has

worked as a production geologistand explorationist in the Alaskan

Ar ct ic , the Gu lf of Mexico , andthroughout South America for Exxon. His recent work is mainly concerned with source rock char-acterization, oil geochemistry, andhydrocarbon systems.

H. B. Lo

H. B. (Hoom-Bin) Lo received hisPh.D. in geology from West VirginiaUniversity in 1977. He worked for

GeoChem Laboratory and GeoChemResearch from 1977 to 1979. He joined Exxon Production Research Company in 1979 and has workedon various aspects of petroleum geo-chemistry. His work at Exxon hasincluded research and developmentof organic maturity techniques andinterpretation of source rock and hydrocarbon geochemi-cal data to evaluate the source element of the hydrocarbonsystem in many basins around the world.

Edgar Hernández

Edgar Augosto Hernández Fon-esca is a geologist for Colombian

Petroleum Company (Ecopetrol).Edgar graduated from the NationalUniversity of Bogotá, Colombia, in1987. He worked five years as a

well-site geologist and later spentthree years working in the Llanosforeland basin regional project. After eight years of working for the explo-ration division, he joined the pro-duction division. He is presently the geologist for theCoporo 1 well in the Llanos foothills basin.


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65779793 Source Rocks and Oil Families