shelf petroleum system of the columbus basin, offshore trinidad, west indies. ii. field geochemistry...

Shelf petroleum system of the Columbus basin, offshore Trinidad,

West Indies. II. Field geochemistry and petroleum migration model

Richard G. Gibson*, Leon I.P. Dzou

BP North American Exploration, 501 Westlake Park Blvd, Houston, TX 77079, USA

Received 14 October 2002; received in revised form 28 October 2002; accepted 3 November 2003

Abstract

Petroleum migration patterns in the present-day shelf area of the Columbus basin reflect a complex interaction of structural evolution,

stratigraphic architecture, and fault-seal behavior. Thermogenic charge access is ultimately controlled by the geographic distribution of sand-

prone carrier beds and how these vertically stacked stratigraphic units relate spatially to one another along their basinal limits. Migration in

this system consists of two components, cross-stratal migration through mud-dominated, deep-water (slope and basin floor) sediments

followed by horizon-parallel flow along laterally extensive, sand-prone, shelf carrier beds. Thermogenic charge access to any individual sand

occurs only in a linear geographic area where that sand is not shielded from vertical migration by stratigraphically older sands.

The geochemical characteristics of the trapped petroleum in this system are primarily a reflection of migration distance, with the earliest-

expelled (lowest maturity) products having progressed farthest along the migration pathway. Because of the stratigraphic architecture and

structural geometry involved, a pattern of increasing thermogenic content and maturity with depth at any location is created, despite the fact

that a significant portion of the migration is horizon-parallel. In parts of the basin, this simple pattern has been overprinted by complex

mixing of maturity fractions in single accumulations as a result of late-stage differential source-rock uplift. The observations are inconsistent

with previously proposed models for this basin that emphasize petroleum fractionation accompanying vertical migration through the shelf

stratigraphic section.

q 2003 Elsevier Ltd. All rights reserved.

Keywords: Trinidad; Petroleum geology; Geochemistry

1. Introduction

In Part I of this paper (Gibson, Dzou, & Greeley,

2004), we presented a petroleum source-rock evaluation

of the Columbus basin, offshore Trinidad, based on the

distribution of petroleum type, thermal modeling con-

siderations, and general geochemical characteristics of the

trapped petroleum. This work showed that a geographic

variation in source-rock quality due to depositional

environment is the primary control on product distribution

in the basin. In addition, we showed that biogenic gas is a

ubiquitous component of the petroleum in the area and

constitutes a significant fraction of the trapped

accumulations.

In this paper, we focus on post-expulsion aspects of the

petroleum system, including migration pathways from

source to trap and how these control the detailed distribution

of petroleum within individual fields and at the basin scale.

In order to do this, we interpret the geochemical patterns in

two representative fields in the context of the stratigraphic

and structural framework of these areas. The resulting

models are then generalized and adapted to the basin scale.

Finally, we discuss the exploration implications of these

models.

2. Description of the Columbus basin

2.1. Stratigraphy

The regional setting, framework, and Cretaceous through

early Oligocene evolution of the Columbus basin were

described by Gibson et al. (2004) and are not repeated here.

During late Oligocene to middle Miocene time, the

Southern basin of Trinidad and the offshore Columbus

0264-8172/$ - see front matter q 2003 Elsevier Ltd. All rights reserved.

doi:10.1016/j.marpetgeo.2003.11.002

Marine and Petroleum Geology 21 (2004) 109–129

www.elsevier.com/locate/marpetgeo

* Corresponding author.

E-mail address: [email protected] (R.G. Gibson).

http://www.elsevier.com/locate/marpetgeo

basin comprised a foreland basin associated with southeast

vergent thrusting to the north (Algar, 1998; DiCroce, Bally,

& Vail, 1999). Since late Miocene time, when the paleo-

Orinoco river drainage was diverted eastward by the rising

Serrania del Interior Oriental (Hoorn, Guerrero, Sarmiento,

& Lorente, 1995), southern Trinidad and the Columbus

basin have been the loci of deposition of siliciclastic

sediments that locally exceed 30,000 ft (9150 m) in

thickness.

On seismic lines in the southwestern part of the

Columbus basin, a thick wedge observed between lower

Tertiary and basal Pliocene is inferred to be of upper-

Oligocene through Miocene age. Only the top of this

succession has been penetrated by a couple of deep wells in

the far southwestern part of the basin and, thus, its lithologic

character is not known for certain. The section is thickest in

the north (,10,000 ft, 3050 m) and thins gradually south-

ward while onlapping the underlying passive margin

(DiCroce et al., 1999). Well data from the Amacuro shelf

in Venezuela indicate that this section consists largely of

outer shelf to slope shales (DiCroce et al., 1999), whereas

the correlative units to the north in Trinidad’s Southern

Range (Cipero Fm.) are deep-water marls (Stainforth,

1948). Thus, this interval within the Columbus basin is

interpreted to be dominantly deep-water mudstones. In the

main petroleum-productive part of the Columbus basin,

much of this section has been tectonically removed due to

large-magnitude extension (see below).

Overlying the pre-Pliocene wedge is the Plio-Pleistocene

progradational sequence of the Orinoco delta. This section,

the principal one penetrated by offshore wells, consists of

interbedded mudstone and poorly consolidated sandstone

deposited during eastward progradation of the Orinoco

system (DiCroce et al., 1999; Wood, 2000). Since middle

Miocene time, the depositional system has prograded

towards the NE, with the shelf edge migrating ,400 km

from a position in eastern Venezuela to its current position

,100 km east of the Trinidad coast (DiCroce et al., 1999).

Shelf edge positions within the Columbus basin at various

times are shown in Fig. 1a. All of the shelfal deposition

within the study area occurred since approximately 5 Ma

(Wood, 2000).

The Plio-Pleistocene stratigraphic framework used for

this study is based on that of Wood (2000) with some

modifications based on seismic mapping. Within any

chronostratigraphic interval of this progradational section,

depositional environments change from coastal plain

through shallow marine to slope and basinal settings toward

the northeast. In the southwestern part of the basin (south of

Trinidad), the Plio-Pleistocene succession is approximately

15,000 ft (4600 m) thick. Farther toward the northeast, the

section is progressively expanded across a series of down-

to-NE growth faults, with the section locally exceeding

30,000 ft (9150 m) thick. The Plio-Pleistocene shelf depos-

its in the expanded area define a series of eastward-

thickening sedimentary wedges that reflect syn-kinematic

deposition on the downthrown side of a system of SW-

dipping (counter-regional) normal faults just outboard of the

present-day shelf edge. Accommodation space for the

deposition of these thick sediment packages was structurally

generated by extension and partial to complete removal of

Miocene through lower Tertiary strata.

As discussed in detail by Heppard, Cander, and

Eggertson (1998), the deep stratigraphy in most of the

discovered fields is overpressured, with fluid pressures

locally approaching the fracture condition for the shales.

The top of the abnormally pressured section is not

regionally at a constant stratigraphic level, but occurs in

younger strata toward the northeast (Heppard et al., 1998;

Wood, 2000). The transition from normal to abnormal

pressure typically occurs close to the shelf to slope

transition (see Wood, 2000), where sand content within

the stratigraphic section decreases from .50% in the shelf

to ,25% on the slope.

2.2. Structural geology

The Plio-Pleistocene section in the Columbus basin is

affected by two sets of structural elements (Leonard, 1983):

(1) a syn- to post-depositional, NW–SE striking extensional

fault system and (2) a series of NE – SW trending

contractional folds. The principal structural detachment

for both sets of structures occurs near top Cretaceous,

probably within lower Tertiary or uppermost Cretaceous

shales.

The extensional fault system within the basin is bounded

on the northeast by a family of large-displacement, counter-

regional (SW-dipping), listric normal faults situated near the

present-day shelf edge (Fig. 1b and c). Movement on these

counter-regional faults accounted for much of the extension

within the basin and, as the depositional system prograded,

the shelf edge generally tracked along the hanging wall side

of the active counter-regional system (Wood, 2000). Major

NE-dipping normal faults dominate the extensional system

in the hanging wall of the counter-regional system and

typically cross-cut it, progressively translating the upper-

most counter-regional fault segments out into the basin

toward the NE. Broad, asymmetric rollover anticlines are

created by a combination of slip on the counter-regional and

NE-dipping normal faults. Secondary normal faults structu-

rally segment these rollover anticlines.

Structures related to crustal shortening include a series of

NE–SW trending ridges that generally decrease in ampli-

tude from NW to SE across the basin. The flanks of Galeota

Ridge, located in the NW, locally have limb dips up to 458,

whereas the ridges further south have limb dips of ,108. In

some areas, superposition relationships between faults and

folds indicate that shortening began after and/or outlasted

the extensional deformation phase at any given location.

As discussed by Gibson et al. (2004), the Cretaceous

source beds occur below the structural detachment and have

a much simpler geometry that is discordant to the overlying

R.G. Gibson, L.I.P. Dzou / Marine and Petroleum Geology 21 (2004) 109–129110

Fig. 1. (a) Regional map of Columbus basin showing petroleum fields, major structural features, and shelf edge positions at specific times during the Plio-

Pleistocene. Shelf-edge position at basal Pliocene time is off map to the west. Fields mentioned in the text are labeled; see Fig. 1 in Gibson et al. (this volume)

for index to other field names. Dashed lines indicate cross-sections shown in (b)–(d). (b) Regional WSW–ENE cross-section through Samaan field. (c)

Regional WSW–ENE cross-section through the SEG area and southeastern field trend. (d) NNW–SSE cross-section across basin showing large-scale basin

geometry and relative positions of Samaan and SEG. Light dashed lines within age units of (b)–(d) are structural form lines.

R.G. Gibson, L.I.P. Dzou / Marine and Petroleum Geology 21 (2004) 109–129 111

Plio-Pleistocene units. The large-magnitude extension

within the overlying section thinned or removed much of

the Miocene through lower Tertiary section within the

growth-faulted domain. This typically results in close

juxtaposition of the Cretaceous source with part of the

Plio-Pleistocene section.

3. Previous petroleum migration models

Previous work in the Columbus basin has led to conflicting

ideas about petroleum migration processes. Early ideas

presented by Leonard (1983) were developed using an

upper-Miocene source-rock and involved migration of

petroleum along major growth faults into traps within the

Plio-Pleistocene section. Leonard (1983) concluded that

trapped petroleum phase (oil versus gas) is related to the

degree of source-rock maturity at the time that faults cut

through the section, connecting the source and reservoir

(Fig. 2a). This model was used to explain the observed lateral

segregation of oil (west) and gas (east) in Teak field (Fig. 1a).

In work focused on understanding fault seals in Teak and Poui

fields (Fig. 1), Gibson (1994) questioned the fault-conduit

interpretation and suggested that the phase distribution in

these fields could have resulted from preferential migration of

gas across the major faults that subdivide the fields.

Geochemical-based analyses (Heppard, Ames, & Ross,

1990; Persad et al., 1993; Ross & Ames, 1988) defined

Fig. 2. Previously proposed petroleum migration models for the Columbus basin: (a) fault migration into Teak field to explain lateral segregation of oil and gas

(after Leonard, 1983); (b) tortuous vertical migration out of overpressured section into Samaan field (based on Heppard et al., 1990, 1998); (c) combined lateral

and vertical migration into Mahogany field controlled by geometry of shelf sand terminations (after Gibson & Bentham, 2003). Arrows indicate petroleum flow

pathways; dark gray in (b) and (c) is overpressured section; light gray in (c) shows extent of shelf sands.


vertical compositional changes of oils in several fields

(Samaan, Teak, Poui—Fig. 1a) and led to the development

of more vertical-directed migration models (Fig. 2b). These

authors interpreted that the presence of progressively lighter

petroleum at shallower depths was produced by migration-

fractionation (‘evaporative fractionation’ of Persad et al.,

1993). Migration pathways from the deep source were

postulated to be either along faults (Heppard et al., 1990;

Persad et al., 1993) or through zones of pervasive hydraulic

fracturing within the overpressured section (Heppard et al.,

1998). Final petroleum migration into the structural traps

was interpreted to have been driven by pressure-induced

fracturing during Pleistocene uplift and deformation

(Heppard et al., 1998).

Most recently, Gibson and Bentham (2003) developed a

migration model based on a study of fault seals in Mahogany

field (Fig. 1a) that emphasizes the role of lateral migration

within sheet-like, shelf sand horizons (Fig. 2c). In this

model, vertical migration from the deep source through

deep-water mudstones is laterally displaced from the

present-day accumulations, and the distribution of pet-

roleum within the fields is largely controlled by lateral

migration pathways within sand carrier beds. Charge access

into the shelf sands is controlled by the basinward-stepping

geometry of successive shelf edges. Faults set up the trap

geometries and serve as barriers/baffles to migration, but do

not act as migration pathways.

In the following sections, we attempt to reconcile these

contrasting models by interpreting a geochemical data set in

the context of the stratigraphic and structural evolution

described in Section 2.

4. Analytical methods and interpretation approach

Selected oil and condensate samples collected over the

last 30 years from the study area were prepared and

analyzed at Baseline-DGSI in The Woodlands, TX. The

samples were topped under a stream of nitrogen at 40 8C for

1 h and excess pentane was added to precipitate asphaltenes.

The polar fraction was removed using a Waters Sep-Pak

Plus CN cartridge with pentane solvent. The saturated

hydrocarbon fraction was separated by medium-pressure

liquid chromatography using deactivated silica and acti-

vated silica columns. Whole oils were spiked with trans-2-

heptene as an internal standard and analyzed on a Hewlett

Packard 5890 Series II gas chromatograph. The data were

processed using EZ Chrom software from Scientific Soft-

ware Inc. An aliquot of the saturate fraction for GC-MS

analysis was diluted with cyclohexane and spiked with 5b-

cholane as an internal standard. Ortho-biphenyl was used as

the internal standard during analysis of the aromatic

fraction. GC-MS analysis was performed on a Hewlett

Packard 5890 Series II gas chromatograph coupled to a

Hewlett Packard 5970 Series mass selective detector.

Analytical conditions used for oil and condensate analyses

are documented by Dzou, Holba, Ramon, Moldowan, and

Zinniker (1999). Carbon isotopic analyses of natural gas

samples were performed at Isotech Laboratories in Cham-

pagne, IL.

The principle aim of the geochemical work was to

characterize variations in thermogenic–biogenic petroleum

ratio and maturity to be used as indicators of the migration

pathways responsible for charging of the Columbus basin

fields. Interpretation of the relative contributions of

thermogenic and biogenic petroleum to a sample is based

on gas carbon isotope data, assuming that the biogenic

fraction is methane-dominated and isotopically light

(Clayton, 1991). Thus, plots of d 13C for methane through

butane (C1 –C4) are expected to exhibit the greatest

depression of d 13C C1 for samples with the largest biogenic

contribution.

Biogenic gas can exist either on its own or as mixtures

with thermogenic products. The phase behavior during

mixing will depend on the degree of saturation of the

interacting phases. For instance, oil interacting with pure

biogenic gas (.99% C1) is likely to initially go into solution

until the gas contains enough heavy components to be in

thermodynamic equilibrium with the oil. At the other end of

the spectrum, an undersaturated oil will dissolve biogenic

gas until it becomes gas saturated.

Maturity evaluation of the oil and condensate samples

was done using a variety of molecular and biomarker ratios

that reflect thermal stress-dependent (time and temperature)

transformation reactions. Key ratios used in this study,

selected for their overall insensitivity to fractionation

processes (Dzou & Hughes, 1993), include nC17/pristane,

nC18/phytane, C29 20S/(20S þ 20R), and methylphenan-

threne index (MPI ¼ 3 þ 2/9 þ 1). For all of the maturity

indices used in this paper, greater values imply higher

maturity. Normal-alkane/isoprenoid ratios, such as nC17/

pristine and nC18/phytane, are well-established maturity

indicators that have been used to assess maturity of both

source rocks and oils (Connan & Cassou, 1980; Tissot,

Califet-Debyser, Deroo, & Oudin, 1971); these have

dynamic ranges that correspond to the early to main stages

of petroleum generation. Since organic matter type and

depositional environment can affect these ratios, we have

limited their use to comparative analysis within small areas

where we can assume a high degree of average source-rock

homogeneity. In addition, we have restricted our analyses to

non- or mildly biodegraded samples where these ratios are

unlikely to be affected.

Mackenzie (1984) and Peters and Moldowan (1993) have

reviewed the use of biomarkers for maturity assessment.

Specific biomarker ratios undergo their greatest change in

value over narrow ranges of thermal stress (8C) or %Ro, and

the effective range varies from one biomarker to another.

For instance, TR23/H30 is sensitive to maturity changes

over the 120 – 150 8C thermal stress (0.6 – 1.0% Ro)

range (Peters & Moldowan, 1993). Other biomarkers that

are sensitive over narrow ranges include C20/C28R


(120–150 8C, 0.6–1.0% Ro) and C29 S/S þ R (90–120 8C,

0.5 – 0.7% Ro). The methylphenanthrene index

(MPI ¼ 3 þ 2/9 þ 1) is particularly suited for maturity

assessment at elevated maturity levels (%Ro . 1.0, 150–

200 8C; Cassani, Gallango, Talukdar, Vallejos, & Ehrmann,

1988; Radke, 1988). Therefore, we use MPI as an indication

of the degree to which the high-maturity portion of the

charge was captured into an accumulation.

Since the generation and expulsion of petroleum from a

source-rock occurs over a range of depth and thermal stress,

a petroleum reservoir should receive progressively more

mature petroleum as it is filled from a source-rock

undergoing continuous burial, assuming that the reservoir

remains in communication with the source-rock. Thus, if a

field is filled uni-directionally in a sequential manner, the

most mature petroleum in the reservoir should be located

nearest to the point of charge influx from the expelling

kitchen (England & Mackenzie, 1989). If migration

continues throughout the entire petroleum generation

process, a reservoir at the margin of a source kitchen

could sequentially receive early, early þ main, early þ

main þ late, early þ main þ late þ over mature products

expelled from the source-rock. However, if a reservoir is

isolated from the petroleum source at some stage during the

expulsion history, it will lack geochemical indicators of

the maturity reached after the time of isolation. Ultimately,

the type and geochemical characteristics of petroleum in a

reservoir depends not only on the thermal stress state and

characteristics of the source-rock, but also on the avai-

lability of migration pathways and traps relative to the

moving locus of expelled petroleum.

5. Representative field examples

In this section, we present detailed analyses of two areas

selected as representative examples from the southeast and

northwest field trends (see Gibson et al., 2004). The Southeast

Galeota (SEG) complex and Samaan field (Fig. 1a) were

chosen for detailed work because of both their similarity to

each other and their differences. In addition, parts of both

areas have been discussed in the literature (Heppard et al.,

1990, 1998; Persad et al., 1993) and used in the development

of previous petroleum migration models.

Both the SEG and Samaan areas are located within the

same general depositional trend of the growth-faulted part

of the basin. They contain petroleum trapped primarily in

coastal-plain to marginal marine, upper-Pliocene (2–3 Ma)

reservoir sands. In both cases, sand units comprise

approximately 50% of the gross stratigraphic section.

Most of the sand units are sheet-like deposits that can be

correlated over areas of 500 þ km2 in the immediate

vicinity of the fields, although individual sand units cannot

be correlated between the SEG and Samaan areas. The

reservoir sands in both areas change facies into slope

mudstones toward the NE from the fields. Because of

the overall progradational nature of the stratigraphic

section, the position of this facies change shifts basinward

(toward the NE) with decreasing reservoir age.

Structurally, the two areas show both similarities and

some significant differences. When viewed along NE–SW

cross-sections (Fig. 1b and c), both the Samaan and SEG

structures appear to be rollover anticlines associated with

major normal faults. Both structures are bounded on the SW

by substantial NE-dipping faults, and strata on the NE flank

of the structures dip and thicken northeastward toward a large

counter-regional fault system. In addition, both areas

straddle regional anticlines formed during NW–SE short-

ening, although the vertical relief on the Samaan ridge is

greater than that in SEG (Fig. 1d). Angular truncation of beds

at the seafloor on the crest of Samaan and elevation of

stratigraphic units above their ‘regional’ elevation, indicate

that the Samaan structure underwent substantially more post-

extensional uplift than the SEG area. The absence of

Pleistocene units at Samaan and their dramatic thickening

toward the northeast (Fig. 1d) implies that this uplift occurred

during the Pleistocene. In addition, Samaan overlies an area

of apparent uplift at Cretaceous level that is not observed at

SEG (see Gibson et al., 2004). Thus, although both the SEG

and Samaan structures had similar origins as extensional

structures, Samaan experienced a more intense overprint

during Pleistocene NW–SE shortening which also uplifted

the underlying Cretaceous section. As a result, Samaan is a

more intensely faulted, higher-relief culmination than the

lower-relief, less complex SEG structure.

5.1. Southeast Galeota area

5.1.1. Field description

The Southeast Galeota (SEG) area consists of a complex

of several fields that are either currently producing

(Immortelle, Amherstia, Cassia) or under development

(Parang, Kapok). The area is situated in the southeastern

field trend, approximately 60 km southeast of Galeota Point,

Trinidad, and just north of the Venezuela border (Fig. 1a).

Structurally, the complex is a low-relief, NE–SW trending

anticline dissected into several major fault blocks by NW–

SE striking normal faults that generally dip basinward

(Fig. 3). The NE flank of the structure is characterized by

relatively steep basinward bedding dips and a series of

moderately to gently dipping, counter-regional (SW-dip-

ping) fault segments (Fig. 1c). The upper-Pliocene reservoir

section thickens toward the northeast due to deposition

during movement on these counter-regional faults. On the

NE side of the structure, a younger, large-displacement, NE-

dipping growth fault truncates the updip end of the counter-

regional fault segments and juxtaposes the SEG complex

against an expanded section of latest Pliocene and

Pleistocene strata (Fig. 1c). The NE-dipping normal faults

within the SEG complex also offset the older counter-

regional fault system. The SEG area is underlain at depths

.20,000 ft (6100 m) by gently NNW-dipping Cretaceous


strata situated below the structural detachment. There is no

evidence for either uplift of the Cretaceous in this area or

erosion of Tertiary strata at the seabed on the crest of the

SEG structure.

Many individual sands contain petroleum accumulations

within the SEG complex. Gas is volumetrically dominant,

with oil occurring in thin oil legs below gas caps in a few

zones. Each sand and major fault block is a separate

accumulation, characterized by distinct fluid-contact levels.

A map of the ‘22’ sand (Fig. 3), stratigraphically in the

middle of the productive reservoir section, illustrates the

typical petroleum distribution and trap geometries. Oil and

gas accumulations are trapped by a combination of bedding

dip closure and fault-seal, with faults comprising one to

three sides of the trap. As is typical of all sands in

the complex, hydrocarbon–water contacts within the 22

sand are deepest on the NE side of the structure and become

progressively shallower toward the SW. Younger sands tend

to be petroleum bearing on the NE side of the structure

(Immortelle and Amherstia fields) and older sands contain

most of the reserves on the SW side (Cassia field).

The majority of the drilled section is normally pressured,

with abnormal pressures appearing in the deepest sands

where sand net-to-gross decreases and outermost shelf to

slope depositional environments are encountered. The onset

of abnormal pressure rises stratigraphically from SW to NE.

5.1.2. Fault-seal analysis

Fault-seal evaluation in the SEG area was done using

the approaches outlined by Gibson (1994) and Gibson

Fig. 3. Map of ‘22’ sand in the SE. Galeota area showing the main faults (dark gray) and petroleum accumulations (medium gray-oil, light gray-gas). Dashed

line indicates cross-section shown in Fig. 5. Key faults are labeled. Letters preceding depth values correspond to thousands of feet. Heavy arrows indicate fill-

spill migration pathway implied by fault-seal analysis.


Fig. 4. Fault-seal analysis for the SEG ‘22’ sand: (a) ‘displaced shale fraction’ plot showing expected SGR values (contours as a function of stratigraphic

position and fault throw). Dashed lines correspond to boundaries of major lithologic units as they vary in position due to increasing throw to the right. Low SGR

values correspond to domains of reservoir self-juxtaposition; (b) fault plane sections for ‘22’ sand at trap-bounding faults in the SEG area. Regions of reservoir

self-juxtaposition are shaded and hydrocarbon–water contact shown (heavy dashed lines). Note coincidence of downthrown hydrocarbon–water contact

depths with top of self-juxtaposition windows. Fault names refer to Fig. 3.


and Bentham (2003). These studies show that faults in the

Columbus basin seal significant petroleum columns only

where the SGR (shale gouge ratio, Yielding, Freeman, &

Needham, 1997) is .0.25. Most cases of reservoir self-

juxtaposition do not fit this criterion and are inferred to be

potential ‘windows’ that can allow cross-fault petroleum

migration. A ‘displaced-shale-fraction’ plot (Fig. 4a),

similar to the ‘juxtaposition’ plots of Knipe (1997),

illustrates the expected SGR values for a range of fault

displacements of the ‘22’–‘23’ reservoir interval in the SEG

area. Low SGR (,0.2) windows correspond to areas where

the sands are self-juxtaposed (Fig. 4a). SGR values for all

other juxtaposition geometries meet the SGR . 0.25

criteria for sealing. Thus, we expect that cross-fault

petroleum flow could occur where reservoirs are self-

juxtaposed, but would be unlikely where different sands are

in contact across faults.

Direct evidence in support of this in the SEG area can be

seen in a series of fault-plane sections showing juxtaposition

relationships of the 22 sand (Fig. 4b). In four of the five

examples, the hydrocarbon–water contact for an accumu-

lation corresponds in depth with the shallowest depth of 22

sand self-juxtaposition across the fault. Only the western-

most (‘E’) fault does not show this behavior. Instead, the

trap on the downthrown side of the E fault is not filled down

to the depth of cross-fault self-juxtaposition, and no

accumulation exists in the upthrown block (Cassia field).

5.1.3. Geochemistry

Figs. 5 and 6 summarize the available oil, condensate and

gas geochemical data from reservoirs within the SEG

complex. Stable isotope data from gas accumulations show

variable degrees of d 13C C1 depression (Fig. 6a), implying a

range of thermogenic–biogenic ratios within the complex.

In addition, the presence of gases with no thermogenic

contribution is implied by the lack of C2þ in gas shows from

the upper part of the wells in the area (Fig. 5).

Oil and condensate maturity indicators show that

petroleum with a wide range of maturity is trapped within

the SEG complex. Maturity indices based on biomarkers

(e.g. MPI, C29 S/S þ R) and n-alkane/isoprenoid ratios

(nC17/pristine, nC18/phytane) are positively correlated with

one another (Fig. 6b). We interpret this to indicate that

individual accumulations within the SEG complex received

different fractions of the total petroleum charge.

Both the variation of thermogenic–biogenic ratio and

maturity within this data set can be related to stratigraphic

and geographic position. In general, there is a trend toward

increasing maturity and thermogenic fraction with depth

(increasing reservoir age) at most geographic locations

Fig. 5. Cross-section through key wells in the SEG area (section line in Fig. 3) showing location of most samples used in this study. GC traces,

methylphenanthrene patterns, and a summary of important geochemical ratios are shown for each sample. Gray shading on well sticks indicates depths over

which only C1 gas shows are observed. Well identification letters correspond with Fig. 3. Geochemical samples posted at well E are projected from several

different wells located in similar structural positions along strike (NW–SE) within this fault block. See text for discussion.


Fig. 6. Summary of SEG geochemical data: (a) gas isotope plot for all samples showing variable depression of d 13C C1; (b) plot showing positive correlation

between various maturity indicators; (c) geochemical variation with distance along horizons from the counter-regional fault.


within the complex (Fig. 5). Lateral variations are less easy

to define because of the paucity of samples from a single

stratigraphic horizon at various locations. However, several

samples from the 22 sand show a substantial decrease of

maturity and thermogenic–biogenic ratio from NE (Immor-

telle–Amherstia) to SW (Kapok) (Fig. 5). In addition, the

stratigraphically deeper appearance of C2þ gas shows

toward the NW (Fig. 5) is consistent with a trend of

decreasing thermogenic–biogenic ratio laterally along a

horizon from NE to SW.

The lateral variations can be better illustrated by plotting

compositional parameters versus the distance to the

intersection of the reservoir with the counter-regional fault

that bounds the east side of the SEG complex (Fig. 6c).

Since the counter-regional fault trend developed close to the

shelf edge and probably marks the approximate eastern limit

of shelf sands at any stratigraphic level, Fig. 6b shows that

both maturity (nC17/pristine, MPI, C29 S/S þ R) and

thermogenic–biogenic ratio decrease with distance from

the northeastern limit of the reservoir they are trapped in.

5.1.4. Migration model

The fault-seal observations imply a relatively simple

model for filling of the traps within the SEG complex by fill-

and-spill around/across faults within individual sand carrier

beds from the NE toward SW. The model, similar to that

proposed by Gibson and Bentham (2003) for Mahogany

field (Fig. 1a), is illustrated in map form (Fig. 3) by a series

of arrows showing the migration pathways along the 22 sand

horizon. Column heights within individual fault traps are

limited by cross-fault spill points at depths of reservoir self-

juxtaposition on the SW side of each fault block. As

discussed in detail by Gibson and Bentham (2003), each

sand horizon acts as a separate migration system, with little

to no communication between different sands because of the

high-quality fault seals developed along fault segments with

high SGR values.

The geochemical patterns in the SEG complex can be

interpreted as a direct result of this migration process, with

the largest fractions of the most mature thermogenic

petroleum captured on the NE (proximal) side of the

structure. Fig. 7 shows a petroleum migration model that

integrates both the fault-seal and geochemical data. During

the early stages of structural development, biogenic gas was

sourced from within the Tertiary section and accumulated in

the crestal portion of the structure (Fig. 7a). The earliest-

expelled, lowest maturity, thermogenic petroleum from the

Cretaceous source migrated along the sand carrier beds and

interacted with the biogenic accumulations (Fig. 7b). Since

the biogenic accumulation would have been initially

undersaturated with respect to liquid, the low-maturity oil

charge dissolved in the gas, forming low maturity gas

condensates (e.g. shallow samples in wells B and C, Fig. 5).

As slip increased on faults within the complex, the initial

accumulation was fault-segmented, and the eastern seg-

ments continued to receive progressively more mature

thermogenic charge (Fig. 7c and d). In this way, the

observed pattern of increasing contribution of high-maturity

thermogenic charge towards the NE along any individual

sand was developed. In the case of the 22 sand in the SEG

area, the westernmost fault block (Cassia field) did not

receive any thermogenic charge (C1 gas shows only, Fig. 5)

since the accumulation in the next block towards the NE did

not fill to the cross-fault spill level defined by reservoir self-

juxtaposition (Fig. 4b).

In this model, the observed vertical geochemical

trends are not a product of vertical petroleum migration.

Instead, they are a secondary trend that reflects the

proximity of a given trap to the northeastern sand extents

of the horizons within that trap. Since the depositional

system was progradational throughout the accumulation

of the reservoir section, shallow sands at a specific

location are more distal from the corresponding shelf

edge than deeper sands. Thus, laterally migrating

petroleum in the deepest sands had to travel the shortest

distance, through the least number of intermediate traps,

from the point of entry into the carrier bed (Fig. 7).

Numerous occurrences of residual gas have been

observed below gas accumulations within the SE trend

fields (Rosen, 1997; BP unpublished data). Rosen (1997)

interpreted such occurrences in Kiskadee field as evidence

for breaching of traps, probably during recent fault move-

ments. An alternative interpretation, consistent with the

charging model presented above, is that residual gas zones

below gas accumulations are formed by shrinkage of early

trapped biogenic accumulations as they undergo subsequent

burial and pressure increase.

5.2. Samaan field

5.2.1. Field description

Samaan field is situated in the northwestern field

trend, approximately 35 km (22 miles) due east of Radix

Point on the eastern Trinidad coast. The field was

discovered in 1971 and started oil production in October

1972. Since that time, it has yielded in excess of 210

MMBO and 650 BCFG. The field occupies the crest of a

high-relief (,1500 m), NE–SW trending anticline cut by a

myriad of NW-striking, NE- and SW-dipping normal faults

that interact in the center of the field (Fig. 8a). On the SW

side of the field, beds dip toward the SW into a large-

displacement normal fault that separates the Samaan

structure from the remainder of the Galeota Ridge to the

SW (Fig. 1b). This fault was active during deposition of the

Pliocene reservoir section and rollover into it probably

helped form the initial Samaan structure. On the NE flank of

the structure, beds dip northeastward into the Columbus

basin and, as in the SEG area, this eastward-dipping panel is

bounded on the NE by a large, syn-depositional, counter-

regional fault system located near the present-day shelf edge

(Fig. 1b). Angular truncation of beds at the seafloor above

Samaan (Fig. 8a) and eastward thickening of the Pliestocene


Fig. 7. Petroleum migration model for the SEG area integrating fault-seal and geochemical observations. Filling sequence discussed in text is illustrated by the

progressive evolution of the solid horizon. Heavy black lines-faults; thin lines-horizons; heavy dashed gray lines-approximate eastern sand limit. Vertical

ruling in petroleum accumulations represents the degree of thermogenic contribution, ranging from entirely biogenic (white) to thermogenic-dominated

(black).


Fig. 8. Samaan field geochemical observations: (a) cross-section of Samaan field (after Heppard et al., 1998) with locations of five key samples discussed

in text shown (black dots); (b) GC traces, API gravities, and n-alkane/isoprenoid ratios; (c) GC-MS data (m=z 191) with TR23/H30 values highlighted; (d)

GC-MS data (m=z 231) with C20/C28R values indicated; (e) GC-MS data (m=z 192) with MPI values shown. Arrangement of samples in (b)–(e)

corresponds to relative sample position as shown in (a). Arrows in (b)–(e) indicate directions of increasing maturity based on the specified parameter

shown.


section away from the structure (Fig. 1b) reflect substantial

Pleistocene contractional modification of the initial Samaan

structure. This event was probably also responsible for the

intense internal faulting observed within the field.

At least 15 individual sands contain oil and/or gas within

the field, generally in footwall fault traps within the larger

anticlinal culmination. With a few exceptions where

displacement on the bounding fault(s) is less than the

reservoir thickness, each sand and major fault block is a

separate accumulation, characterized by distinct fluid-

contact levels (Fig. 8a). Although some individual fault

blocks appear to be filled down to local cross-fault spill

level, the Samaan structure as a whole is markedly under-

filled (,250 m columns in 1500 m of closure). Sands down

to ,6000 ft (1830 m) TVDSS contain only gas, whereas the

deeper sands are oil-dominated (Fig. 8a). Several sands,

including the ‘2’, ‘4’, and ‘9’ reservoirs have primary gas

caps, and the size of these gas accumulations relative to the

underlying oil legs is larger on the east side of the field than

the west.

The stratigraphic section within Samaan is normally

pressured above 9000–10,000 ft (2740–3050 m) TVDSS

and becomes overpressured below the ‘7A’ sand (Fig. 8a).

Pressure gradients as high as 0.987 psi/ft (22.3 kPa/m),

close to the hydraulic fracture condition for the shales, are

encountered in the deepest drilled section (Heppard et al.,

1998). This highly overpressured section is devoid of

petroleum accumulations, possibly due to failure of shale

top seals by hydraulic fracturing (Heppard et al., 1998).

Beyond the NE limit of the field, the top of overpressure

climbs stratigraphically toward the NE as the continuous

shelf sands pinch out into deeper water mudstones.

5.2.2. Geochemistry

Previous geochemical studies of Samaan field (Heppard

et al., 1990; Ross & Ames, 1988) showed the presence of

vertical and lateral variations in oil composition, based

largely on API gravity and GC analysis of a suite of

approximately 125 whole oils. Various trends, including

increasing API gravity and relative abundance of C15–C30

n-alkanes and isoprenoids with depth, were interpreted to

reflect vertical fractionation processes during secondary

migration (Heppard et al., 1990). In this model (Fig. 1a),

vertical migration out of the deep, overpressured section

through the faulted Samaan structure led to the progressive

loss of high molecular weight n-alkanes. In addition, a

limited tri-aromatic sterane data set was presented by Ross

and Ames (1988) to show that Samaan oils over the entire

depth range are of uniform low thermal maturity. New

analyses done for the present study indicate that co-elution

of additional compounds with the tri-aromatic steranes (m=z

231, Fig. 8d) gave the false impression of constant maturity

reported by Ross and Ames (1988).

For the present study, we have re-examined previously

collected data and re-analyzed a subset (15) of the sample

suite, focusing on the collection of both GC and GC-MS data.

Because of the size and complexity of the entire data set, the

following discussion concentrates on five oil samples

selected to represent the data from various parts of the field

(locations in Fig. 8a). Three samples from the center of the

field (‘2’, ‘6’, and ‘9’ sands) are the same ones used by Ross

and Ames (1988, Figs. 10–13) to illustrate the vertical

compositional variations. The additional two samples

presented here come from the ‘2’ sand series on the eastern

and western flanks of the field. Using these five samples, we

illustrate both the vertical and lateral geochemical variations

within Samaan field.

Fig. 8b–e summarizes the geochemical data for the five

representative samples. The saturate GCs clearly illustrate

the downward increase in C15þ n-alkane content (Ross &

Ames, 1988), and also show a similar trend from the field

core toward both flanks in the ‘2’ sand. API gravity clearly

correlates with wax content in the oils. Although not shown,

similar trends are observed in the ‘4’ (see Heppard et al.,

1990) and ‘7’ sand data. The shallow flank samples show

some removal of low molecular weight n-alkanes, indicative

of slight biodegradation. N-alkane/isoprenoid ratios (nC17/

pristine, nC18/phytane) increase downward and toward the

eastern flank of the field. We interpret these ratios to

indicate increased maturity with depth and toward the

eastern flank.

GC-MS traces illustrating three key biomarker ratios

(TR23/H30, C20/C28R, MPI) are also shown in Fig. 8c–e.

Each of these biomarkers has dynamic ranges for maturity

determination within the upper oil to gas windows. In all

three cases, the ratios increase toward shallow depth and

toward the eastern flank. These biomarkers imply that the

highest maturity petroleum reached the shallowest reser-

voir, especially on the NE side of the field.

The apparent contradiction between the n-alkane/isopre-

noid maturity parameters and the biomarkers is shown in

Fig. 9a. In contrast to the SEG data (Fig. 6b), the various

maturity indicators do not correlate with one another and,

instead, show crossing trends. Samples with high MPI

values and low nC17/pristine are interpreted to have

received a secondary pulse of high-maturity petroleum.

C29 S/S þ R values are lower than a typical maximum value

of 0.54 (e.g. Peters & Moldowan, 1993) and do not vary

with nC17/pristine. We interpret this as being due to mixing

of expulsion products generated from different levels of

thermal maturation. Since the expelled concentrations of

C29 isomers decrease with increasing maturity (Dzou,

Noble, & Senftle, 1995), the cumulative C29 S/S þ R

values will be biased toward values implying lower

maturity.

Stable isotope data for all Samaan gas samples show

strong methane d 13C depression (Fig. 9b), implying that a

significant component of biogenic gas mixed with the

thermogenic petroleum. Gas compositions are similar in a

variety of sands (‘0/2’–‘10’) over a large (6000–11,000 ft,

1830–3350 m) depth range.


5.2.3. Migration model

The complexity of the Samaan geochemical data implies

that mixing of various petroleum maturity fractions occurred

in different parts of the field. As indicated by n-alkane/

isoprenoid ratios, the deep sands and those on the NE flank

apparently received more mature oil than the shallow sands

in the center of the field. However, biomarkers, especially

those sensitive to maturity changes within the late oil to gas

windows, imply that the same deep sands did not capture the

highest maturity fraction to as great a degree as the

shallowest oil-bearing sands. Furthermore, these biomarkers

indicate that the NE flank of the field consistently received

more mature charge than the SW side.

We find it difficult to reconcile these complex patterns

with the previously proposed vertical migration-fraction-

ation model (Heppard et al., 1990; Ross & Ames, 1988) for

several reasons. Firstly, the variable nature of the n-alkane

profiles is a reflection of oil maturity (waxy oils are more

mature) and does not need to be explained by fractionation

of an oil of consistent low maturity. Secondly, a vertical

migration scenario cannot explain the indications of higher

maturity in shallow sands than in the deeper sands.

Fig. 10 shows our preferred model for petroleum

migration into Samaan field. Because of the overall

similarities between the SEG and Samaan areas, we have

used our understanding of the SEG charging history as a

guide for developing this model. The filling history is

evaluated in terms of two distinct phases, one corre-

sponding to the extensional origin of the Samaan

structure and the second occurring during contractional

modification of the structure. Based on the source-rock

thermal history (Gibson et al., 2004), charging of the

field probably began in the Pliocene, not long after

deposition of the reservoir sands. At this time, the

structure was solely of extensional origin and probably of

relatively low-relief, similar to the SEG complex today.

Prior to the input of thermogenic petroleum, the structure

is inferred to have contained accumulations of biogenic

gas. As oil entered the structure from the NE by lateral

migration along carrier beds, it mixed with the biogenic

gas, which went partially or entirely into solution within

the oil. The maturity trends in the field at this time were

likely to be similar to those observed in the SEG

complex today, increasing downward due to closer

proximity of the traps in the deep sands to the point of

petroleum input (shelf edges) to the carrier beds. This

would have established the maturity trends currently

preserved by variations in API gravity, n-alkane profiles,

and n-alkane/isoprenoid ratios.

Several lines of evidence, including anomalously deep

hydrocarbon–water contacts and C15þ enriched oils on

the west side of the Samaan structure (Heppard et al.,

1990), imply that some fraction of the Samaan oil

migrated in from the west, rather than from the east.

These observations can be explained by the fact that the

growth fault located immediately west of Samaan has

extremely large displacement (.10,000 ft, 3050 m) and

growth. Thus, it locally juxtaposes west-dipping shelf

sands against older, mud-dominated strata in the foot-

wall, creating a small area where charge can access

southwest-dipping Samaan reservoirs (Fig. 10).

The second phase of migration into Samaan coincided

with NW–SE shortening during the Pleistocene. During this

time, uplift of the Cretaceous source rocks immediately

beneath the field caused petroleum generation in this area to

slow or completely shut off (Gibson et al., 2004). However,

the Cretaceous source in the area northeast of the field

continued to be buried and to supply petroleum into the

Samaan structure. The greater basinal extent of the shallow

sands relative to the deep sands permitted more input of the

high-maturity petroleum fraction into the shallow sands.

This second phase of migration was responsible for creating

the inverted biomarker maturity trends and the higher gas

fraction in sands on the east side of the field.

6. Regional migration model

The SEG (Fig. 7) and Samaan (Fig. 10) charging models

are essentially variations on the same general theme in that

Fig. 9. Summary of Samaan geochemical data: (a) plot showing complex

interrelationships between various maturity parameters (compare with Fig.

6b); (b) gas isotope plot for all available samples showing similar

depression of d 13C C1.


both areas are interpreted to have been charged largely by

migration along sand-prone carrier beds from the NE. The

more complex geochemical patterns in Samaan relative to

SEG are due to the fact that petroleum products generated

over the entire maturity range were captured and mixed

within the same high-relief structural closure. The varying

proportions comprising these mixtures in different reser-

voirs is a result of the interaction between differential

source-rock uplift and the contrasting areal extent of

catchment areas for each carrier bed. In contrast, the

apparently simple pattern observed in the SEG complex was

produced without differential source-rock uplift and is

largely a product of variable migration distance along each

carrier bed. The low structural relief of individual traps

within the SEG complex allowed the traps to fill to spill,

thereby preventing complete mixing of the various pet-

roleum fractions. Understanding the relatively simple

migration processes in the SEG area is a necessary first

step for unraveling the complex patterns observed within

Samaan.

The pattern of petroleum products observed at the field

scale (especially SEG) can also be seen at the regional scale.

Fig. 11 shows the distribution of petroleum product types

within the upper-Pliocene section over the entire Columbus

basin in Trinidad and Tobago waters. All occurrences of

thermogenic petroleum in this stratigraphic interval,

including accumulations and shows (liquid or C2þ gas),

are situated in a belt along the NE side of the 2–3 Ma shelf

sand fairway. The main zone of thermogenic accumulations

is located either between the shelf edges for the top and

basal surfaces of the interval, or within ,10 km southwest

of the basal shelf edge (Fig. 11). Farther to the southwest, all

gas shows consist entirely of methane and are interpreted to

be of biogenic origin.

Our model for the origin of this petroleum distribution

pattern is shown schematically in Fig. 12a. On a regional

scale, the sand-rich shelf deposits comprise an eastward

thickening, prograding wedge that, at any given location,

overlies abnormally pressured, mudstone-dominated, slope

and basin floor strata. Petroleum expelled from mature

Cretaceous source rocks beneath the structural detachment

is inferred to access the shelf sands via sub-vertical

migration routes through the mud-dominated, deep-water

sediments. The mechanism responsible for this migration is

Fig. 10. Schematic cross-section showing interpreted migration pattern for charging of Samaan field. The basic maturity pattern recorded by nC17/Pristane and

wax content was established during charging of the original extensional rollover anticline (a). Deep thrusting during the Pleistocene elevated the Cretaceous

source beneath the field and effectively shuts off expulsion from this area (b). Shallow sands receive high-maturity charge by lateral migration from the eastern

portion of the fetch area where the source continues to undergo burial throughout the Pleistocene. See text for further discussion.


unknown, but possibilities include percolation through the

pore network controlled by capillary phenomenon (e.g.

Berg, 1975; Hirsch & Thompson, 1995) and migration

through hydraulic fracture systems (e.g. Cosgrove, 2001;

Heppard et al., 1998). In detail, the migration pathways

within this section are unlikely to be strictly vertical, but are

undoubtedly more tortuous, consisting of more vertical

segments within mudstones and horizon-parallel segments

Fig. 11. (a) Map showing characteristics of petroleum accumulations and shows within the 2–3 Ma reservoir interval, superimposed with the geographic area

bounded by the shelf-edge position at approximately 2 and 3 Ma (diagonal ruled). Nearly all of the thermogenic petroleum within this stratigraphic interval occurs

within 25 km west of the inferred thermogenic charge area bounded by these shelf edges. Field locations are indicated for reference (P, Poui; T, Teak; Sa, Samaan;

SEG, SE Galeota area; F, Flamboyant; M, Mahogany). (b) Results of horizon-based flowpath modeling for a horizon approximating the SEG area ‘22’ sand. Charge

access area is a linear band at the shelf-edge position and major faults are assumed to be no-flow boundaries except at low-displacement tips. The only fields shown

are those containing thermogenic charge at this stratigraphic level. Eastern limit of the map surface is the approximate intersection of the horizon with the counter-

regional fault system. Flow vectors indicate thermogenic charge access into major fields (Samaan, Teak, SEG area) located updip and west of the charge access area.


within isolated, deep-water sand/silt layers. It is likely that

vertical and lateral fluid pressure gradients exert significant

control on the detailed geometry of the migration pathways

within this section (Heppard et al., 1998). We do not invoke

faults as migration conduits because all direct evidence

within the drilled section of the basin implies that faults

either serve as non-seals or barriers to flow, rather than

migration conduits (Gibson, 1994; Gibson & Bentham,

2003).

The vertically migrating petroleum initially encounters

the sheet-like shelf sands along a generally southwest-

dipping surface that represents the loci of successive shelf

edges (Fig. 12a). Each individual sand is charged within a

linear geographic area bounded by the shelf edge of that

sand and the shelf edge of the immediately underlying shelf

sand. Areas located southwest of the shelf edge for the

underlying sand are shielded from capturing the vertically

migrating petroleum. The relative quantity of charge

available to any sand should reflect the distance of

progradation that occurred between the deposition of

successive sands. In the case of back-stepping sand units,

migrating petroleum is captured by deeper sands, and

the younger ones are shielded from thermogenic charge.

This appears to be the stratigraphic geometry in the upper-

Pleistocene (post-1.3 Ma) of the Columbus basin (Wood,

2000) and, thus far, no thermogenic petroleum has been

discovered in this stratigraphic interval.

Once the petroleum enters the high-permeability, low

capillary-entry pressure sand units, horizon-based pet-

roleum migration becomes the favored process. Because

of the consistent northeastward dip of beds toward the

counter-regional fault system at the shelf-edge position,

the petroleum migrates updip toward the southwest under

the influence of buoyancy. However, since the onset of

overpressure climbs stratigraphically toward the NE (Wood,

2000) and generally coincides with the stratigraphic

transition from shelf to slope paleo-environments, a

hydrodynamic drive probably also assists in efficiently

transferring the migrating petroleum from slope deposits

into the shelf carrier beds. This drive acts in the same

direction as buoyancy, encouraging migration towards the

SW. Structural traps encountered during updip flow are

filled, progressively spilling into traps farther updip and

producing maturity patterns such as those preserved in

Fig. 12. Schematic cross-section view illustrating petroleum migration model, including cross-stratal migration through overpressured slope shales to access

distal edges of progradational shelf sands, westward migration along shelf sands into structural traps, and westward decrease of thermogenic petroleum

fraction: (a) basic model developed for SE trend; (b) model with minor adaptations to explain specific observations in the NW trend.


the SEG complex. Biogenic gas, derived from within the

Tertiary section and present in early formed traps, mixes

with the thermogenic petroleum in various proportions.

The northwestern limit of thermogenic petroleum found

in any specific sand may be a reflection of several factors. In

some cases, it might result from a lack of sufficient

thermogenic charge to fill a trap and allow it to spill into

the next one along the pathway. One example of this might

be the case of the SEG 22 sand at the E fault (Figs. 3 and 4b)

where the trap on the northeast side is not filled to cross-

fault spill and the trap on the southwest has only indications

of biogenic gas. Alternatively, factors related to trap

geometry, such as the presence of large-displacement

sealing faults or low vertical relief of the trap, could cause

migration to be diverted along structural strike (NW–SE)

rather than to continue toward the SW. Gibson and Bentham

(2003) discuss an example of the latter type of behavior in

Mahogany field.

The model described above, although developed primar-

ily on observations from the SE field trend, requires only

slight modification to also explain the observations in the

northwestern fields (Fig. 12b). Firstly, the NW area was

affected by Pleistocene differential source-rock uplift that

did not impact the SE trend. This increased the complexity

of the Samaan geochemistry and influenced the distribution

of oil and gas in the structure (more gas shallow and on east

side). Teak field, located in the same structural position

,15 km to the south, also shows a downward increase in

C15þ n-alkane content in oils (Ames & Ross, 1985) and a

predominance of high-maturity (Dzou, unpublished data)

gas in reservoirs on the east side of the structure. These

similarities suggest that the same migration model can be

applied to other NW trend fields.

A second modification of the model necessary to explain

some of the NW trend observations is the local capturing of

thermogenic petroleum by west-dipping carrier beds where

fault-juxtaposed against mudstone-dominated strata west of

Samaan and Teak. This geometry, which is not present in

the SE field trend, only exists because of the extraordinarily

large displacement on this fault. As a result, a narrow

window exists along the fault through which vertically

migrating petroleum can access the faulted terminations of

southwest-dipping carrier beds that continue updip into the

west flank of Samaan and Teak fields (Fig. 12b).

Fig. 11b shows the inferred petroleum flowpaths in map

view along a single upper-Pliocene map horizon using the

model outlined above. This simulation was done using the

flow-vector modeling capability in 3DMOVEw (Midland

Valley Exploration) on a present-day horizon surface.

Petroleum flow along the surface (carrier bed) is assumed

to be solely buoyancy driven and, thus, occurs along the

horizon perpendicular to structure contours. Major faults are

assumed to serve as flow boundaries and, therefore, flow is

deflected around fault tips. The area of charge access into

the sand occurs only along a narrow band at the shelf edge.

The results illustrate that the proposed model can reasonably

provide thermogenic charge to the known occurrences of

thermogenic petroleum at this stratigraphic level (Fig. 11b).

Note that, since no charge access to the horizon was allowed

from the west (see above), the thermogenic accumulations

located immediately west of Teak and Samaan fields are not

charged in this simulation. Simulations done on sequentially

restored 3D surfaces show that similar migration directions

and patterns persist throughout the Plio-Pleistocene evol-

ution of the Columbus basin.

Demaison and Huizinga (1991) developed a genetic

classification of petroleum systems based upon charge

factor, migration style, and entrapment style. They defined

‘vertically drained’ and ‘laterally drained’ as terms

describing the predominant direction of petroleum

migration within basins. It is interesting to attempt to

classify the Columbus basin petroleum system within their

scheme. The model outlined here is a hybrid system,

consisting of initial vertical drainage through the mud-

stone-dominated, deep-water section followed by lateral

drainage within the spatially continuous shelf deposits.

Petroleum migration distances in the cross-stratal direction

were on the order of 2–6 km, whereas lateral flow along

carrier beds occurred over distances of 5–25 km in rather

tortuous routes dictated by the horizon geometry and fault

patterns. For both migration styles, the abundance of seals

and potential traps along any migration pathway imply

‘high impedance’ in their classification. Demaison and

Huizinga (1991) evaluated charge factor based on an

estimate of source-rock expulsion potential. Although we

have no direct, quantitative evidence of the source

potential in the Columbus basin, we do observe that

some valid traps along migration pathways are not charged

with thermogenic petroleum (e.g. Cassia 22 sand). Thus,

we are tempted to conclude that the system is, at least

locally, undercharged. This conclusion does not, however,

necessarily imply low source-rock expulsion potential.

Instead, the apparent undercharging in this system probably

reflects the abundance of available traps (large available

trap volume) combined with the fact that individual

reservoir horizons capture thermogenic charge from rather

small, linear areas bounded by successive positions of the

shelf edge. In addition, significant migration losses are

possible within the cross-stratal portion of the migration

pathway since large-scale migration focusing does not

occur until the Plio-Pleistocene shelf carrier beds are

encountered.

7. Exploration implications

The concepts outlined in this paper, and its companion

(Gibson et al., 2004), provide a framework within which

to evaluate the petroleum products likely to be

encountered in reservoirs within undrilled prospects in

the Columbus basin. Reservoir-specific phase prediction

requires understanding (1) the nature of the thermogenic


charge expelled within the fetch area of the prospect and

(2) the factors likely to control the relative abundances of

thermogenic and biogenic petroleum reaching the trap.

The primary control on thermogenic product type in the

basin is the position of the Cretaceous shelf edge

(Gibson et al., 2004). The southward decrease in

source-rock hydrogen index across this shelf margin

makes the thermogenic fraction in prospects located in

the northwest part of the basin more likely to be oil than

those to the southeast.

Biogenic gas is a ubiquitous component in all of the

petroleum so far discovered in the Columbus basin. For any

potential accumulation, the relative contributions of the

thermogenic and biogenic fractions are controlled by post-

expulsion migration pathways, especially the position of

any trapped reservoir relative to the point of thermogenic

charge input into that sand. Reservoirs in traps situated close

to or outboard of the shelf edge at the time of sand

deposition are expected to contain thermogenic-dominated

products of high-maturity. Moving landward (SW) along a

reservoir horizon from the shelf edge increases the

likelihood that trapped accumulations will become more

biogenic gas dominated. The extent to which a thermogenic

component is incorporated within an accumulation depends

on the amount of thermogenic charge available to the sand

and the geometry of the migration pathway between the trap

of interest and the shelf edge.

Since the thermogenic fraction in the northwestern part

of the basin is dominantly oil, undiscovered accumulations

in this area are likely to be either oil- or biogenic gas-

dominated, with thermogenic-dominated gas accumulations

expected to be subordinate. In contrast, undiscovered

accumulations in the southeastern areas are likely to consist

of biogenic and thermogenic gas mixed in various

proportions. Oil in this area may or may not accompany

larger gas accumulations, but is unlikely to exist as the only

phase in a trap. We expect that oil legs below gas caps are

most likely to be found in volumetrically large traps with

low initial biogenic gas quantities, most probably in

proximal positions along migration pathways. Late trap

formation, after substantial burial, is a likely mechanism to

minimize the accumulation of biogenic gas. In these traps,

the early migrating oil fraction of the thermogenic charge

will not have been able to go completely into solution in a

pre-existing biogenic accumulation.

Using a model of fractionation during vertical migration,

Persad et al. (1993) concluded that oil accumulations are

likely to exist beneath the offshore gas-condensate (SE

trend) fields. Based on the models presented here, we expect

to see an overall increase in the maturity of trapped products

with depth. However, because we believe that the oil

fraction is controlled by source-rock characteristics (Gibson

et al., 2004), not secondary migration, we see no reason that

oil-dominated accumulations should exist at great depths

below these fields.

8. Conclusions

In this paper, we have developed a regional petroleum

migration model for the Columbus basin by integrating a

geochemical data set with an understanding of fault-seal

behavior, abnormal pressures, basin structure, and strati-

graphic architecture. The result is a simple, unified

petroleum migration model for the Columbus basin shelf

in which thermogenic charge access is ultimately con-

trolled by the geographic distribution of sand carrier beds

and how these vertically stacked stratigraphic units relate

spatially to one another along their basinal limits.

Migration in this system consists of two components,

vertical migration through mud-dominated, deep-water

sediments followed by horizon-parallel flow along laterally

extensive carrier beds. Thermogenic charge access to any

individual sand occurs only in a linear geographic area

where that sand is not shielded from vertical migration by

stratigraphically older sands.

The geochemical characteristics of the trapped petroleum

in this system are primarily a reflection of migration distance,

with the earliest-expelled (lowest maturity) products having

progressed farthest along the migration pathway. Because of

the stratigraphic and structural geometries involved, this

creates a pattern of increasing thermogenic content and

maturity with depth at any location, despite the fact that much

of the migration is horizon-parallel. In parts of the basin, this

simple pattern has been overprinted by complex mixing of

maturity fractions in single accumulations as a result of late-

stage differential source-rock uplift. We are unable to

reconcile the observations in this basin with previously

proposed models that emphasize petroleum fractionation

accompanying vertical migration (Heppard et al., 1990;

Persad et al., 1993).

Although this study is specific to the Columbus basin,

many complex aspects of the geology of this basin are

similar to other offshore Tertiary basins. Specifically, the

structural style, stratigraphic architecture, and presence

of a petroleum source-rock stratigraphically separated

from the reservoir-bearing section are not unique. We

have shown how these aspects interact with one another

in the Columbus basin petroleum system and hope that

these ideas may stimulate a re-evaluation of petroleum

systems in other geographic areas with similar

complexities.

Acknowledgements

The work presented here would not have been possible

without the large body of work done by BP (Amoco) Energy

Company of Trinidad and Tobago personnel over the past

30 þ years. Numerous members of the extended 1997–

2000 Trinidad Exploration team contributed to the evolution

of our ideas, including J. Sydow, R. Marksteiner,

W. Phillips, P. Bentham, and A. Pepper. Serena Jones


from Midland Valley Exploration assisted with use of

3DMOVEw for map-based petroleum flow simulation. A

thorough review by K. Meisling substantially improved the

manuscript. BP Energy Company of Trinidad and Tobago is

thanked for permission to publish this paper.

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