Regional Distribution and Controls of Heavy Oil and Oil Sand in the Eastern Venezuelan and Trinidad Basins

Grant D. Wach¹, Curtis Archie², and Hasley Vincent^1,3
¹Dalhousie University, Halifax, Nova Scotia, Canada
²Petrotrin, Point a Pierre, Trinidad and Tobago
³Ministry of Energy and Energy Industries of Trinidad and Tobago

Introduction- Hydrocarbon occurrences range from the Cretaceous to Pleistocene in the Eastern Venezuelan and Trinidad basins. Distribution and occurrences of heavy oil and oil sands form an apparently random stratigraphic pattern within the Tertiary succession in the Trinidad basins. Regional controls on the distribution of heavy oil and oil sand include the age and stratigraphy of the deposit, history of uplift and faulting, and lithofacies variability keyed to depositional environments. Heavy oil and oil sand reservoirs within the same stratigraphic interval exhibit a variety of API values. Tectonic regional controls produce thermal events that effect source rock maturation. Faults control migration, provide trapping mechanisms and can compartmentalize reservoirs. Depositional controls impact source rock quality, reservoir distribution and reservoir quality. Biodegradation and water washing of deposits can occur within separate reservoir compartments in the same stratigraphic reservoir interval. This paper will examine the distribution of heavy oil and oil sand reservoirs, summarize the potential controls on the distribution of lower API reservoirs and provide examples from the Trinidadian basins. We will define heavy oil as having API gravity below 22.3 ° and oil sand with less than 10 °API.

Regional setting- Trinidad lies in the eastern reaches of the eastern Venezuelan Basin (Fig. 1) subjected to compressive stresses from the NNW producing transpressional faults and NE-SW trending folds and thrust faults, dividing Trinidad into three discrete basins - a Northern, Southern and Southwestern. Most hydrocarbon occurrences are found in the Southern Basin associated with late Tertiary structures. At least three tectonic phases account for the deformation across the Southern Basin (Lorcan and Pindell 2007); 1) southeast directed thrusting during the Miocene; 2) Pliocene strike slip along the NE-SW faults and growth faulting; and 3) Pliocene-Recent strike slip faulting and normal faulting. These phases account for the major tectonic elements in and around the Southern Basin and their associated oil accumulations in predominantly Miocene and Pliocene reservoirs.

Source rock- Oils found onshore and offshore Trinidad are attributed to the same geochemical family, with differences in geochemical composition due to variations in maturity, source type facies, and alteration (Talukdar et al. 1998). Oil is sourced primarily from the Gautier and Naparima Hill formations and possibly the Cuche. Fractionation of these marine source rocks produced excellent oils that accumulated in the Tertiary reservoirs. Geochemical work by Rodrigues (1988) indicates that oil produced from the Naparima Hill formation is paraffinic, generated from mixed terrestrial and marine kerogens. The oblique collision of the Caribbean and South American plates resulted in the Naparima and Gautier formations entering the hydrocarbon generating window. Hydrocarbon migration likely occurred in the over-thrusting phase that followed (Persad 2003) forming the fold belt which extends from the Southern Range to the El Pilar fault in the north.

Structure and tectonic controls - Structural controls on heavy oil sand distribution are evident by varying oil-water contacts between and within oil fields and can be directly observed at outcrop (Wach and Vincent, this volume). API and oil water contacts can vary between fault blocks within the same hydrocarbon reservoir. For example in the intermediate Herrera Sands faults and associated anticlinal structures provided the traps for oil accumulation (Hosein, 1991). Thrust faults and (NW-SE trending) normal faults act as flow barriers, forming separate hydrocarbon accumulations with different formation pressures and water contacts. Similar differences occur between stratigraphic intervals and are influenced by the structural controls.

Stratigraphic distribution- In Trinidad the heavy oil and oil sand distribution is generally constrained within the Miocene and Pliocene reservoirs of the Southern Basin (Table 1) with oil sands apparently restricted to the Pliocene reservoirs. Producing reservoirs occur from 300 feet to 12,000 feet drilled depth, and are from shallowest to deepest Morne L'Enfer, Forest, Cruse, Karamat and Herrera (Russell, no date). Porosity decreases with depth from 30-33% for shallow Morne L'Enfer Formations, to 30 to l8% for Cruse reservoirs. Permeabilities vary from 10 to 1495 md depending on reservoir shale content. Shallow formations exhibit high permeability's of 0.5 to 1.5 Darcies and unconsolidated reservoirs are typical. Permeability generally decreases with depth and at Cruse level, averages 50 md. Hydrocarbon gravities vary from <10° API oil sand (tar/bitumen) to medium gravity crude oils of l4-28°API. Crude oil recoveries range from <1% for the shallow heavy oil to 15 to 25% for the medium gravity crude oils (Russell, no date).

Reservoir Lithology and Depositional Environment- The sandstones forming the uppermost Miocene through Plio-Pleistocene reservoirs are immature litharenites with evidence of sediment recycling with grains dominantly fine-lower medium grained and subrounded. Overall the sands were deposited within a deltaic setting.

API Oil Variability- Table 2 illustrates the variability in the API of oils within fields, in this case the Guapo block of the Pliocene Morne L’Enfer formation exposed in the Stollmeyer Quarry that will be discussed in Wach and Vincent (this volume). Shallower reservoir intervals have excellent porosity and permeability but API is poor in the younger Cruse interval.

Hydrocarbon alteration- Several studies have attempted to evaluate the controls of gravity variations among crude oil in Trinidad. These studies conclude that oil gravity distribution is highly variable and appear independent of depth, age, temperature and geographic location of reservoirs (Rodrigues and Deokie 1998). Common to all studies is that the complex distribution may be a function of multiple alteration processes (Heppard et al. 1991; Talukdar et al. 1998, Rodrigues and Deokie 1991; Persad 2003). These include biodegradation, water washing, gas-condensate mixing, gas stripping, evaporative fractionation, thermal alteration and alteration imposed by secondary migration. If alteration processes are the major controls on API gravity distribution, accurate API gravity prediction will entail an understanding of geochemical changes, migration pathways and history, source kitchens and subsurface temperature variations which should be reflected in reservoir crude qualities.

Reservoir Depth- Rambarran (1987) showed the significance of gravity segregation of heavy oil distribution in the Parrylands Forest “A” reservoir. Sininan also shows some gravity segregation and API variation with depth. Shallow reservoir intervals can have heavy oil in the Penal area and the deep Herrera can be either heavy or gas/condensate (Higgins 1955; Requejo et al. 1994 and 2004). In Table 2 it can be argued that the shallower reservoir interval, the Cruse, may have been subjected to biodegradation of the oils leading to the lower API. However, previous work by Vincent (2001) suggested there is not necessarily a direct correlation to depth and higher API values.

Conclusions-Table 3 is a summary of the geological controls that are apparent in the distribution of heavy oil and oil sand within the formations in the Trinidad basins. Heavy oil and oil sand distribution in the Pliocene and Pleistocene reservoirs of the Eastern Venezuelan and Trinidad basins appears to be controlled by several factors that have contributed to biodegradation of the lighter ends leaving accumulations of lower API heavy oil and oil sand deposits. Biodegradation is enhanced by the Plio-Pleistocene reactivation of pre-existing fault structures. This fault control is evident within fields such as Guapo with uplifted blocks comprising oil sand.

Figure 1. Structural features of the eastern Venezuelan and Trinidadian Basins. A) The location of Trinidad relative to northeastern South America (BAR: Barbados Accretionary prism, LA: Lesser Antilles island arc). B). Geological provinces of Trinidad.