--> New constraints on the tectono-sedimentary evolution of the San Pedro Basin (south-eastern Dominican Republic offshore margin): Implications for its hydrocarbon potential

Hedberg: Geology of Middle America – the Gulf of Mexico, Yucatan, Caribbean, Grenada and Tobago Basins and Their Margins

Datapages, Inc.Print this page

New constraints on the tectono-sedimentary evolution of the San Pedro Basin (south-eastern Dominican Republic offshore margin): Implications for its hydrocarbon potential

Abstract

The San Pedro Basin (SPB) is an E-W-trending bathymetric depression located the south-eastern offshore margin of Hispaniola Island. With an approximately extension of 6000 km2, SPB limits to the south with Muertos Thrust Belt (MTB). In the scientific literature, the SPB has been usually interpreted as a local “forearc basin” containing sediments from Middle Miocene to Present. Although it is located close to confirmed onshore petroleum systems (Maleno and Higuerito former oil fields at Azua Basin), several attempts of onshore-offshore stratigraphic correlations with the San Cristobal (considered as the onshore extension of SPB) and Azua Basins have shown discrepancies and then SPB evolution is still unclear. The MTB deformed belt is considered as an imbricate thrust system product of an effective southward transfer of the compressive stresses from the oblique collision/underthrusting between the continental crust of the North American Plate (i.e., the Carbonate Bahamas Province), and the north-eastern segment of the island (i.e., the Lower and Upper Cretaceous island arc terrains, mainly consisting of volcanic and volcano-sedimentary sequences). Our study has been focused on the detailed revision and synthesis of the systematic geological mapping (SYSMIN I & II Programs) together with the integration of a large volume of sub-surface geophysical data (figure 1). This includes the analysis of up to 60 exploration wells provided by Banco Nacional de Datos de Hidrocarburos (BNDH) of the Dominican Republic, the processing of new 2D multi-channel seismic data from the Spanish Research Project NORCARIBE, the reprocessing of vintage seismic profiles and the interpretation of gravity and magnetic data. Preliminary results have provided new constrains which lead us to propose a tentative new evolution model for the SPB. In the new model the basement of the SPB is formed by the Cretaceous sedimentary and volcanic rocks, deposited in an intra/back-arc context. A subsequent change in the stress regime at the K/T limit led to the partial inversion of the basins and the volcanic arc and Paleocene?-Eocene sediments were deposited into a submarine foreland setting. Due to the collision between the Carbonate Bahamas Province and Hispaniola in Upper Eocene, compressional stresses were transferred to the south where Cretaceous and Paleogene sediments were deformed forming the MTB and generating a new accommodation space where SPB was developed since Upper Eocene / Oligocene until Present. This new model agrees with outcrops from San Cristobal Basin and could have important implications for the exploration in the area. Note that dating the oldest rocks of the basin in Upper Cretaceous instead of Middle Miocene as was traditionally considered in the scientific literature, opens a new window for searching potential source rocks and other elements of the petroleum system. B A Figure 1. A, Correlation of synthetic columns from geological maps and onshore exploration wells in the nearby of the basin. B, Interpretation of the SPB. Colored surface represents the basement for post Upper-Eocene sediments. Results and Discussion We have gathered all the information available from BNDH and Robertson Research Reports (1984), and then we have identified potential source rocks, reservoirs and seals which should be presented in the SPB. The information extracted from these reports has been combined with onshore studies and our model in order to determine the burial history, the geothermal gradient, trap mechanisms and the critical point. A brief review of the preliminary potential petroleum system (figure 2) would be as follows: Source rock Most of studies in Hispaniola have focused on Miocene source rocks in an intra-Miocene petroleum system, trying to check the source for the oil generated in Maleno and Higuerito oil fields. Nevertheless, these samples show low values for vitrinite reflectance and seem to be immature in most cases. Despite the number of samples is not significant for other rocks of the island, there are intervals which could be available of generate hydrocarbons. In this sense, we have considered that may be of interest: Upper Cretaceous and Oligocene. Deep Sea Drilling Project (DSDP) describes Turonian to Santonian sediments with good TOC values (ranging from 1.06% to 6.81%) in the Venezuelan Basin. Although immature, these Type II and III rocks are classified from good to excellent in terms of their genetic potential. It is not clear the presence of this rocks in Hispaniola due to the lack of studies of Cretaceous sedimentary sections. However, there are similitudes between sequences in Central and Oriental Cordilleras for this period and the DSDP ones. It is possible to follow the horizon corresponding to these sediments (B’’) to the frontal part of the MTB, and according to our evolution model should be present below Paleogene deposits. On the other hand, Oligocene samples with TOC values between 0.5% and 4.18% have been characterized by Robertson Research (1984) not only in Hispaniola but also in Puerto Rico and Saba. Geochemical analysis reveals Type III kerogen, vitrinite reflectance from 0.34 to 1.07 %R0 and a good-very good genetic potential in some cases. In the Cibao Basin, northwards SPB, Ca.o Azul #1 well reached a shale interval with TOC ranging from 0.32% to 1.05% and some lignite intervals with high TOC values. Regarding to SPB, there are only two samples in the San Crist.bal Basin with TOC values of 4.18% and 0.62%. Vitrinite reflectance places them near to the oil generation window (note this part of the basin has been exhumed). Figure 2. Schematic chronostratigraphic column for the SPB. From red to green, colours represent quality for the different elements of the petroleum system. Reservoir Reservoirs have been tested by several wells in Lower-Middle Miocene carbonates. Good reservoir quality is mainly associated to shallow marine limestone sections. Maleno DT-1 well (which may be considered as a representative well of the Azua Basin) penetrated a thick section with an estimated average porosity of 12% from wireline logs. Hydrocarbon shows and loss of circulation throughout the well were reported. Finally, a water blowout from vugular and cavernous porosity at TD ended the AAPG HEDBERG CONFERENCE 2-5 July, 2018. Sig¸enza. Spain 42 perforation and the well was abandoned. These kinds of carbonates have been described along southern area of Hispaniola. Backreef, reefal, forereef and shallow-marine carbonates change into deep water marls and lime mudstones in a carbonate ramp model. Our seismic stratigraphy study for SPB interprets this system since Upper Oligocene times, having a good development in Lower to Middle Miocene. Porous and permeable sands of Late Miocene to Present are present in outcrops and wells. Their reservoir quality is very low due to the high content of volcanoclastics. For older levels, reservoir potential seems that only could be possible related to fractures. Seal Several intervals have been described as good regional seals in all exploration wells along Hispaniola. Impermeable carbonates and clastics, Oligocene to Miocene in age, have worked as so according to well reports in Azua and Cibao basins. Tight marls, lime mudstones and wackstones alternate with porous sections in Maleno DT-1. The key factor is fractures related to compressional folds and thrust which could lead in a loss in seal integrity. Above limestones, Neogene deep marine shales and silts are thick enough to act as regional seals. Trap Traps should be divided into two groups: stratigraphic and structural traps. The former is based on the depositional model of a carbonate ramp where proximal facies -shallow-marine carbonates- onlap landwards while basin-wards, deep water sediments -marls, lime mudstones, wackstones and shales- were deposited above older sediments. In the case of SPB, a back-stepping of this carbonate system is observed, being covered proximal sediments by deep water ones. For the latter, our model proposes the generation of structural compressional traps since the inversion of the Paleogene basin in Upper Eocene times and its evolution in a transpressional regime. The key factor is to determine the preservation of traps due to the development of strike-slip faults in the basin.