Diagenesis exerts a strong control on the quality and heterogeneity of most clastic reservoirs. Variations in the distribution of diagenetic alterations usually accentuate the variations in depositional porosity and permeability. Linking the types and distribution of diagenetic processes to the depositional facies and sequence-stratigraphic framework of clastic successions provides a powerful tool to predict the distribution of diagenetic alterations controlling quality and heterogeneity. The heterogeneity patterns of sandstone reservoirs, which determine the volumes, flow rates, and recovery of hydrocarbons, are controlled by geometry and internal structures of sand bodies, grain size, sorting, degree of bioturbation, provenance, and by the types, volumes, and distribution of diagenetic alterations. Variations in the pathways of diagenetic evolution are linked to (1) depositional facies, hence pore-water chemistry, depositional porosity and permeability, types and amounts of intrabasinal grains, and extent of bioturbation; (2) detrital sand composition; (3) rate of deposition (controlling residence time of sediments at specific near-surface, geochemical conditions); and (4) burial thermal history of the basin. The amounts and types of intrabasinal grains are also controlled by changes in the relative sea level and, therefore, can be predicted in the context of sequence stratigraphy, particularly in paralic and shallow marine environments. Changes in the relative sea level exert significant control on the types and extent of near-surface shallow burial diagenetic alterations, which in turn influence the pathways of burial diagenetic and reservoir quality evolution of clastic reservoirs. Carbonate cementation is more extensive in transgressive systems tract (TST) sandstones, particularly below parasequence boundaries, transgressive surface , and maximum flooding surface because of the abundance of carbonate bioclasts and organic matter, bioturbation, and prolonged residence time of the sediments at and immediately below the sea floor caused by low sedimentation rates, which also enhance the formation of glaucony. Eogenetic grain-coating berthierine, odinite, and smectite, formed mostly in TST and early highstand systems tract deltaic and estuarine sandstones, are transformed into ferrous chlorite during mesodiagenesis, helping preserve reservoir quality through the inhibition of quartz cementation. The infiltration of grain-coating smectitic clays is more extensive in braided than in meandering fluvial sandstones, forming flow barriers in braided amalgamated reservoirs, and may either help preserve porosity during burial because of quartz overgrowth inhibition or reduce it by enhancing intergranular pressure dissolution. Diagenetic modifications along sequence boundaries are characterized by considerable dissolution and kaolinization of feldspars, micas, and mud intraclasts under wet and warm climates, whereas a semiarid climate may lead to the formation of calcrete dolocrete cemented layers. Turbidite sandstones are typically cemented by carbonate along the contacts with interbedded mudrocks or carbonate mudstones and marls, as well as along layers of concentration of carbonate bioclasts and intraclasts. Commonly, hybrid carbonate turbidite arenites are pervasively cemented. Proximal, massive turbidites normally show only scattered spherical or ovoid carbonate concretions. Improved geologic models based on the connections among diagenesis, depositional facies, and sequence-stratigraphic surfaces and intervals may not only contribute to optimized production through the design of appropriate simulation models for improved or enhanced oil recovery strategies, as well as for CO2 geologic sequestration, but also support more effective hydrocarbon exploration through reservoir quality prediction.

The impact of diagenesis on the heterogeneity of sandstone reservoirs: A review of the role of depositional facies and sequence stratigraphy

A model for diagenetic mass transfer between adjacent sandstone and shale

Nuclear magnetic resonance (NMR) is a useful tool in reservoir evaluation. The objective of this study is to predict petrophysical properties from NMR T 2 distributions. A series of laboratory experiments including core analysis, capillary pressure measurements, NMR T 2 measurements and image analysis were carried out on sixteen greensand samples from two formations in the Nini field of the North Sea. Hermod Formation is weakly cemented, whereas Ty Formation is characterized by microcrystalline quartz cement. The surface area measured by the BET method and the NMR derived surface relaxivity are associated with the micro-porous glauconite grains. The effective specific surface area as calculated from Kozeny9s equation and as derived from petrographic image analysis of backscattered electron micrograph9s (BSE), as well as the estimated effective surface relaxivity, is associated with macro-pores. Permeability may be predicted from NMR by using Kozeny9s equation when surface relaxivity is known. Capillary pressure drainage curves may be predicted from NMR T 2 distribution when pore size distribution within a sample is homogeneous.

/pdf/petrophysical-properties-of-greensand-as-predicted-from-nmr-43ltme9t86.pdf

Petrophysical properties of greensand as predicted from NMR measurements

Evaluation of groundwater chemistry and its impact on drinking and irrigation water quality in the eastern part of the Central Arabian graben and trough system, Saudi Arabia

Deeply buried sandstones in sedimentary basins typically have low porosity due to cementation and compaction. There are several known causes of anomalously high porosity in sandstones, one of which is microquartz coatings on sand grains that seem to inhibit growth of quartz cement. However, there has been no mechanistic understanding of why or how microquartz grows, or why it maintains high porosity in sandstones. Here we have used high-resolution scanning electron microscopy, electron backscattered diffraction, and transmission electron microscopy to study the microquartz-cemented Late Cretaceous Heidelberg Formation, Germany. We have revealed that a nanofilm of amorphous silica (50–100 nm) and a layer of chalcedony are between the detrital grain and microquartz cement. The amorphous silica insulates the detrital quartz grains and prevents syntaxial growth, while microquartz adopts the orientation of the underlying chalcedony with its fast-growth c axis parallel to the grain surface, thus preventing growth into the pore. Now that we know what controls microquartz growth and why it preserves porosity, it can be used to help identify, rank, and appraise deeply buried petroleum accumulations.

M.Namik Çaǧatay

Papers

Diagenesis of the Safaniya Sandstone Member (mid-Cretaceous) in Saudi Arabia