Rock typing of diagenetically induced heterogeneities – A case study from a deeply-buried clastic Rotliegend reservoir of the Northern German Basin. (March 2020)

• Record Type: Journal Article
• Authors: Monsees, Alexander C.; Busch, Benjamin; Schöner, Nadine; Hilgers, Christoph
• Is Part Of: Marine and petroleum geology. Volume 113(2020)
• Publication Date: 2020-03
• Subjects: Reservoir quality evolution -- Diagenesis -- Matrix permeability -- Sandstone -- Rotliegend -- Northern German Basin; Submarine geology -- Periodicals; Petroleum -- Geology -- Periodicals; Géologie sous-marine -- Périodiques; Pétrole -- Géologie -- Périodiques; Petroleum -- Geology; Submarine geology; Periodicals; Electronic journals; 551.468
• DOI: 10.1016/j.marpetgeo.2019.104163
• Languages: English
• ISSNs: 0264-8172

Abstract

Abstract: Reservoir quality of sandstones is mainly derived from their permeability and porosity. As a result, porosity-reducing processes need to be understood in order to evaluate and model reservoir quality in sandstones. This case study from a Rotliegend gas reservoir in the Northern German Basin utilizes petrophysical measurements in conjunction with petrography in order to assess reservoir qualities and define rock types. The most significant diagenetic factors influencing the development of the IGV (intergranular volume) are quartz cementation due to low illite grain coating coverages on grain to IGV interfaces and chemical compaction due to pronounced illite grain coating coverages on grain to grain interfaces. Where large proportions of the interface between adjacent grains are coated by illite, stronger chemical compaction (pressure dissolution) was observed to occur. This chemical compaction reduces the IGV, and thus open pore space. Permeabilities measured under decreasing confining pressures from 50 to 2 MPa were used to determine the pressure sensitivities of permeability (David et al., 1994), which ranged from 0.005 to 0.22 MPa −1 . The pressure sensitivity of permeability, porosity and permeability were linked to the petrographic texture, implying three different major rock types: Type A is characterized by an uncemented petrographic texture with high porosities (avg.: 9.8%), high permeabilities (avg.: 126 mD), and low pressure sensitivities of permeability (avg.: 0.019 MPa −1 ). Type B is intensely cemented with reduced porosities (avg.: 4.0%), reduced permeabilities (avg.: 0.59 mD), and increased pressure sensitivities of permeability (avg.: 0.073 MPa −1 ). Type C is characterized by intense chemical compaction leading to the lowest porosities (avg.: 1.8%) and permeabilities (avg.: 0.037 mD) in concert with the highest pressure sensitivity of permeability (avg.: 0.12 MPa −1 ). The heterogeneity induced by diagenesis will have an impact on recoverable resources and flow rates in both hydrocarbon and geothermal projects in similar siliciclastic reservoirs. Highlights: Reservoir quality mainly controlled by mechanical compaction, authigenic quartz overgrowth cements, and chemical compaction. Three rock types defined based on petrophysical and petrographic measurements and observations. Differentiation between two kind of clay mineral coating: grain-to-IGV (GTI) and grain-to-grain (GTG). Type A: high porosity due to continuous illite coatings on GTI interfaces preventing quartz cementation. Type B: significant porosity loss by authigenic quartz due to discontinuous illite coatings on GTI interfaces. Type C: highest coverage of illite GTG grain coatings driving chemical compaction, thus highest IGV and porosity reduction.