Deep diagenesis of the Pimienta Formation (Tithonian-Berriasian): Petrophysical, petrographic, and geochemical characteristics of the source rock

• Published in: Applied geochemistry 2022-05, Vol.140, p.105290, Article 105290
• Main Authors: González-Betancourt, Aurea Yahaira, González-Partida, Eduardo, Martínez, Luis, Vega, Sandra, Núñez-Useche, Fernando, González-Ruiz, Daniel
• Format: Article
• Language: English
• ISSN: 0883-2927; 1872-9134
• DOI: 10.1016/j.apgeochem.2022.105290

In this work, the goal is to understand the diagenetic history of a Tithonian-Berriasian hydrocarbon generating rock (Pimienta Formation), belonging to the Tampico-Misantla Basin. This sedimentary formation is differentiated into two facies, the former consists of clay-carbonate deposits and flint, and the latter consists of calcareous deposits and bentonites. Through geochemical analysis, petrographic descriptions, and observations in computerized digital tomography, we can observe that the fluids of marine origin, trapped in the clays, were expelled along with organic acids and oils. These fluids migrated slowly through the sedimentary sequence and precipitated into a closed flown system, forming authigenic minerals with fluid inclusions. Subsequently, this system, initially closed due to low porosity and permeability, was opened due to secondary fracturing and diagenetic processes (re-crystallization and dissolution) within the rock, which currently allows a flow of up to 300 nD in surface exposures. In addition, the temperatures measured through microthermometry of fluid inclusions and the reflectance spectra of organic matter, show temperature data between 109° and 272 °C. In consequence, it is estimated that the Pimienta Formation could reach depths between 3 and 4 km before erosion and uplift. These conditions allow a source rock with type II and III organic matter to acquire the capacity to generate wet gas and later dry gas. However, we can observe a variety of light and intermediate hydrocarbons within the pore spaces which suggest migration of hydrocarbons from another origin towards this formation. This is relevant because it could indicate a conventional/unconventional variable behavior in the course of its geological history. [Display omitted] •Microthermometry of fluid inclusions.•Isotopes δ18O vs δ13C in hydrocarbon source rock.•Rv max%, Ro% of bitumens and cracked organic matter.•Deep diagenesis of gas shales.•Computerized digital microtomography in unconventional reservoirs; storage and migration.