Abstract Neogene shelf, slope, canyon, and slope-to-basin-floor transition plays in the southern Laguna Madre–Tuxpan (LM-T) continental shelf reflect a variety of structural and stratigraphic controls, including gravity sliding and extension, compression, salt evacuation, and lowstand canyon and fan systems. The Neogene in the LM-T area was deposited along narrow shelves associated with a tectonically active coast affected by significant uplift and erosion of carbonate and volcanic terrains. This study characterizes 4 structurally defined trends and 32 Neogene plays in a more than 50,000-km 2 (19,300-mi 2 ) area linking the Veracruz and Burgos basins. Copyright © 2009 by The American Association of Petroleum Geologists. Reprinted from AAPG Bulletin, v. 89, no. 6, (June 2005), pp. 725 – 751. DOI:10.1306/13191099M903340 The Cañonero trend in the southern part of the LM-T area contains deep-seated basement faults caused by Laramide compression. Many of these faults are directly linked to the interpreted Mesozoic source rocks, providing potential pathways for vertically migrating hydrocarbons. In contrast, the Lankahuasa trend, north of the Cañonero trend, contains listric faults, which detach into a shallow horizon. This trend is associated with thick Pliocene shelf depocenters. The dominant plays in the Faja de Oro–Náyade trend in the central part of the LM-T area contain thick lower and middle Miocene successions of steeply dipping slope deposits, reflecting significant uplift and erosion of the carbonate Tuxpan platform. These slope plays consist of narrow channel-fill and levee sandstones encased in siltstones and mudstones. Plays in the north end of the LM-T area, in the southern part of the Burgos basin, contain intensely deformed strata linked to salt and shale diapirism. Outer-shelf, slope, and proximal basin-floor plays in the Lamprea trend are internally complex and contain muddy debris-flow and slump deposits. Risk factors and the relative importance of play elements vary greatly among LM-T plays. Reservoir quality is a critical limiting play element in many plays, especially those in the Cañonero trend directly downdip from the trans-Mexican volcanic belt, as well as carbonate-rich slope plays adjacent to the Tuxpan platform. In contrast, trap and source are low-risk play elements in the LM-T area because of the abundance of large three-way and four-way closures and the widespread distribution of organic-rich Upper Jurassic Tithonian-age source rock. The potential for hydrocarbon migration in LM-T plays is a function of the distribution of deep-seated faults inferred to intersect the primary Mesozoic source. Their distribution is problematic for the Lankahuasa trend, where listric faults sole out into the Paleocene. Seal is poorly documented for LM-T plays, although the presence of overpressured zones and thick bathyal shales is favorable for seal development in middle and lower Miocene basin and slope plays. Reprinted from AAPG Bulletin, v. 89, no. 6, (June 2005), pp. 725–751.

Abstract The Cretaceous interval in the Maracaibo consists mainly of fine-grained clastic and carbonate sediments deposited during a period of passive margin development. Stratigraphically, the early Cretaceous Apon Formation of Aptian age contains interbedded rich organic dolomitic and calcareous shale and black bituminous limestone (Mercedes, Tibu, Guaimaros and Machiques Members). Not only do these constitute important source and reservoir rocks in the southwest region of the Maracaibo Basin, but also represent maximum flooding surfaces within the overall depositional characteristics in the Basin. To the north, the Apon along with the Lisure and Maraca Formations of the Aptian-Albian Cogollo Group, consisting mostly of limestone and fine-grained sandstone, represent a shallow to middle shelf environment transgressive systems tract. In the south, the Cretaceous Capacho, consisting of black shale and the La Luna Formation comprised of interbedded calcareous shale and black cherty limestone, were deposited during a period of relative sea level rise. The La Luna Formation is the primary source rock in the basin as well as a reservoir in places where microfractures produce the necessary permeability for hydrocarbon flow. Numerous geochemical studies performed in the Maracaibo Basin provide evidence for the existence of multiple stratigraphic intervals containing hydrocarbon generating organic-rich shale and calcareous mudstone within the Cretaceous. Integrated reservoir studies and production data indicate that some of the same intervals are excellent oil and gas producers where fracture systems exist. The above-mentioned stratigrahic and depositional characteristics are responsible for making the Maracaibo Basin one of the most prolific producers of hydrocarbons in the world.

Abstract The La Luna-Misoa(l) petroleum system covers an area of about 47,500 km 2 and contributes more than 98% of the total recoverable oil reserves of 52.20 billion bbl and gas reserves of 51.97 tcf in the Maracaibo basin. The system developed in two phases, with each phase having the characteristics of a unique petroleum system but both sharing the Upper Cretaceous La Luna source rock. The development of each phase is related to two separate mature to overmature pods of the La Luna source rock. Biological markers indicate that the oil in this system is correlated to the oil-prone type II kerogen of the La Luna Formation, a marine source rock. Reservoir rocks of Eocene and Miocene age are the most important, contributing 50% and 44%, respectively, of the total recoverable oil in the basin. Based on average TOC content and consumed hydrogen from hydrogen indices, the mass of hydrocarbons generated by the La Luna source rock is 2.50 x 10 14 kg and the in- place hydrocarbon in known oil fields is estimated at 352.25 x 10 11 kg. These calculations indicate that 14% of the hydrocarbons generated from the La Luna source rock actually accumulated in known traps. The Orocue(.) petroleum system, located in the southwestern part of the basin, contributes less than 2% of the total hydrocarbon reserves in the basin. It covers 10,500 km 2 and encompasses the mature to overmature pod of Paleocene Orocue Formation, a coaly source rock containing type III kerogen and genetically related oil accumulations. Some of these accumulations contain a mixture of oils from the Orocue and La Luna source rocks.

ABSTRACT Oil accumulations in Trinidad were sourced by the Upper Cretaceous calcareous siliceous shales deposited along the Cretaceous passive margin of northern South America. Maturation of these source rocks, oil generation, migration and re-migration occurred in a foreland uplift-foredeep setting that resulted from interaction between Caribbean and South American plates during Lower Miocene to Recent times in the Trinidad area. During Lower Miocene-Recent times, the foreland basin experienced strong compressional events, which controlled generation, migration, and accumulation of oil in Trinidad. A series of mature source rock kitchens formed in Lower Miocene-Recent times in the Southern and Columbus Basins southward of the Central Range Thrust which trends generally NE/SW. The thrusts and associated fractures first developed around 22 m.y.b.p. and served as near vertical migration paths for the oil generated in penecontemporaneous kitchens. This oil migrated into submarine fans deposited in the foredeep basin axis and older reservoirs deformed into structural traps. Further generation and migration of oil, and re-migration of earlier oil took place during Pliocene-Holocene times, when later thrusting and wrench faulting served as the migration paths. Extremely high sedimentation rates in Pliocene-Pleistocene time, concurrent with active faulting, was responsible for very rapid generation of oil and gas. Vertically migrating gas often mixed with earlier migrated oil in overlying reservoirs. This caused depletion of oil in light hydrocarbons with accompanied fractionation among hydrocarbon types resulting in heavier oil in lower reservoirs, and enrichment of light hydrocarbons and accumulation of gas-condensates in upper reservoirs. This process led to an oil-gravity stratification within about 10,000 feet of section. These concepts enable prediction of petroleum occurrences onshore and offshore Trinidad.