Integration of depositional, petrophysical, and petrographic facies for predicting permeability in tight gas reservoirs

Abstract

Understanding the linkages between grain mineralogy and diagenetic and sedimentary processes enhances the reliability of petrophysical models to predict reservoir deliverability from permeability. Petrographic data within well-defined depositional facies reveal the diagenetic evolution of porosity-permeability relationships. Formation evaluation methods relying solely on petrophysical rock typing are seriously limited when predicting ultimate reservoir performance in complex pore structures. The Almond Formation, Wyoming, is characterized by three depositional facies associations — shoreface, deltaic (bay head and flood tide), and fluvial-coastal plain — which present three distinctive porosity-permeability trends. Textural features resulting from depositional processes, such as grain size and sorting, vary little between facies associations, yet permeability can vary by up to four orders of magnitude for the same porosity value. Differences between petrophysical facies are primarily driven by diagenetic (cementation and grain dissolution) effects on different framework grain compositions (petrographic facies). Therefore, the main difference between the facies associations is diagenetic, due to provenance and transport mechanisms. The characterization of depositional and diagenetic controls on pore geometry allows the narrowing of uncertainty in absolute permeability prediction. We have quantified the relationship between depositional facies, with their specific mineral composition and diagenetic overprint, and the steepness functions in porosity-permeability space. This analysis allowed us to effectively reduce the uncertainty in the prediction of initial gas production from wireline logs.

Diagenetic controls on the reservoir quality of Neogene sandstones in the offshore area of the Bengal Basin, Bangladesh

“…Micro‐fractures in the rigid particles and deformation of the soft grains into a pseudo‐matrix (Rahman & Worden, 2016) are common. Chemical compaction is more pronounced with the increasing burial depths (>2 km) and effective pressure through intergranular pressure dissolution of detrital quartz grains (Freiburg et al, 2016; Houseknecht, 1987; Mansurbeg et al, 2008; Merletti et al, 2017), and probably sourcing some silica for precipitation of quartz cements (Higgs et al, 2017).…”

“…Deep burial mechanical compaction causes brittle grain fracturing (Figure 6d) when the rate of quartz overgrowth cannot compete with the rate of stress increase at grain contacts and the presence of grain coating clays (Fisher et al, 1999). Chemical compaction is more pronounced with the increasing burial depths (>2 km) and effective pressure through intergranular pressure dissolution of detrital quartz grains (Freiburg et al, 2016;Houseknecht, 1987;Mansurbeg et al, 2008;Merletti et al, 2017), and probably sourcing some silica for precipitation of quartz cements (Higgs et al, 2017).…”

Diagenetic Controls on Tight Sandstone Reservoir Quality: A Case Study from the Huaqing Oilfield, Ordos Basin

“…Diagenetic facies is a comprehensive description of the diagenesis type, intensity, and mineral type, and represents the result of various types of complex geological process. ,, Accurate delineation of diagenetic facies can help locate hydrocarbon sweet spots in tight sandstone reservoirs. Diagenetic facies are generally described by petrographic analysis of thin sections. ,, In order to accurately delineate into diagenetic facies, in this study, multiple cast thin sections were spliced consecutively, and representative regions were estimated based on gray scale thresholding and box-counting analysis in a large field-of-view cast thin section image . Petrographic delineate and diagenetic analyses of each thin section were completed by counting at least 400 points per section under a representative area, and the intensity of diagenesis was calculated using the following equation: Compaction rate = false( V 0 − V false) / V 0 × 100 % Cementation rate = C c / false( C normalc + V normali false) × 100 % Dissolution rate = Φ d / Φ × 100 % where V 0 is the original pore volume in μm 3 ; V is the volume between grains after compaction in μm 3 ; C c is the cement content in %; V i is the intergranular pore volume in μm 3 ; Φ d is the face porosity of the dissolution pores in %; and Φ is the total face porosity in %.…”

Effects of diagenesis on natural fractures in tight oil reservoirs: A case study of the Permian Lucaogou Formation in Jimusar Sag, Junggar Basin, NW China

“…On the other hand, with an increase in burial depth and the accumulation of effective pressure, chemical compaction between particles could become a process of reducing porosity (Freiburg, Ritzi, & Kehoe, 2016;Nygård, Gutierrez, Gautam, & Høeg, 2004). The chemical compaction could enhance the pressure dissolution of quartz particles (Mansurbeg et al, 2008;Merletti et al, 2017), while insoluble clay minerals and organic matter would remain and gather to form stylolites (J. Cai, 1990;Tan et al, 2011).…”