Valgarður: A Database of the Petrophysical, Mineralogical, and Chemical Properties of Icelandic Rocks
Samuel ScottLéa LévyCari CovellHjalti FranzsonBenoit GibertÁ. ValfellsJuliet NewsonJulia FrolovaMaría Sigríður Guðjónsdóttir
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Abstract:
The Valgarður database is a compilation of data describing the physical and geochemical properties of Icelandic rocks. The dataset comprises 1072 samples obtained from fossil and active geothermal systems, as well as relatively fresh volcanic rocks erupted in sub-aerial or sub-aqueous environments. The database includes petrophysical properties (effective and total porosity, grain density, permeability, electrical resistivity, acoustic velocities), as well as mineralogical and geochemical data obtained by point-counting, X-ray Fluorescence (XRF), quantitative X-ray Diffraction (XRD), and Cation Exchange Capacity (CEC) analyses. The motivation behind this database is threefold: (i) aid in the interpretation of geophysical data including uncertainty estimations, (ii) facilitate the parameterization of numerical reservoir models, and (iii) improve our understanding of the relationship between rock type, hydrothermal alteration and petrophysical properties.Keywords:
Icelandic
Petrophysics
Abstract Petrology attributes of reservoir rock are fundamental elements resulting varied petrophysical responses, and controlling reservoir flowing performance. This paper presents a workflow characterizing complex sand-shale sequenced reservoir with a case study in South China Sea. An integrated approach of integrating elemental neutron capature spectroscopy, formation micro-resistivity image and nuclear magnetic resonance (NMR) data are used to characterize reservoir petrology attributes of mineral composition, grain size, sorting and layering fabric; with improved understanding of state dependency problems, such information is of more use in petrophysical evaluation and reservoir producibility simulation. The information can also be integrated into further geological study to improve the certainty of model. Such an integrated approach is proven an effective way to reveal the reservoir intrinsic properties, better to understand interrelationship of sedimentary model, petrology and petrophysics of target formation, and more accurately to delineate reservoir. The marginal reservoir of the case study presents numerous challenges such as low porosity/low permeability, complex porosity-permeability relationship, high apparent water saturation that may or may not produce water, and thin laminations. Due to the nature of these complexities, different reservoir zones with very similar looking in conventional logs behaved totally different production performance from well testing results. This created difficulties for routine petrophysical analysis which often resulted in under-estimated or overestimated reservoir zones without consistency. By integrating multi logging analysis skills with improved methods to characterize sedimentary petrology & intrinsic petrophysical properties of reservoirs, the approach has been demonstrated as an effective way of well understanding the reservoir and evaluating productivity with significantly improved accuracy. Accurate pay zone characterization gained immediate economic impacts on offshore operation. More importantly, the reservoir knowledge gathered is definitely beneficial for further appraisal and future field development planning. Introduction Tracing back to the 1950s when G.E. Archie introduced the term of "Petrophysics", this petrophysics founder had noted that the specific Rock Type, whose parts have deposited under similar conditions and undergone similar processes, would have certain effective pore-size distributions and particular capillary pressure curves, hence controlled porosity and related permeability as well as water saturation [Archie, 1950]. Rock type, which can be described in petrology with attributes such as composite minerals, grain size, sorting and fabric et al, fundamentally resulted in varying petrophysics property. Well understanding the rock petrology and petrophysics properties through the well has penetrated, is also important to geologist and reservoir engineer, to in-depth study the sedimentary facies and flow units, so as to build an accurate geological model and flow model. Conventionally, thorough delineation of the rock with characterizing the rock attributes, such as rock texture and sedimentary structure, has to resort to drilling full-bore cores, although sidewall cores and drilling cuttings are also helpful in some extents; conventional lithology logs such as neutron porosity, formation bulk density and natural gamma ray, are more often used to evaluate and correlate the formation in a continuous manner, but most of time it's difficult or not enough to reveal above rock intrinsic attributes, which result in distinguished reservoir flow performance in the root. These conventional logs may look similar for various reservoirs, as like the case presented in this paper.
Petrophysics
Igneous petrology
Formation evaluation
Economic geology
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Summary An unconventional thin-bed analysis based on logs, core, and miniperm data was needed to calculate the petrophysical properties of a reservoir under development in the Norwegian Sea. More than half of the reservoir section under investigation is composed of heterolithic facies: thinly interbedded sandstone and mudstone layers from one to several centimeters in thickness and of variable quality. By using miniperm measurements with 1-cm spacing on slabbed core, it was possible to resolve the properties of the rock far below the vertical resolution of conventional wireline logs and relate them to the bulk log measurements.
Petrophysics
Wireline
Norwegian
Core sample
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Petrophysics
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Empirical relations are found between measured petrophysical/petrologic, seismic, and electrical properties of sandstone and carbonate samples by least‐squares fitting at room pressure and ambient saturation. The measured parameters include porosity (φ), fluid permeability (k), clay content (C), grain density (ρ g ), bulk density (ρ b ), P‐wave velocity (V p ), electrical conductivity (σ), and dielectric constant (κ). The samples are from reservoir analog sites in the Ferron Sandstone in central Utah and the Ellenburger carbonate in central Texas. Crossplots and regression analysis are done separately for the sandstone and the carbonate samples. For the sandstone samples, predictions with correlation coefficients (R 2 ) greater than 0.75 include ρ b from φ, ln k from φ and C, κ from ln k and φ, κ from ρ b and C, and κ from ln k. Predictions with 0.65 < R 2 < 0.75 include κ from V p and ρ b , κ from V p and φ, V p from ln k and C, κ from ln φ, and κ from ρ b . In general, σ is difficult to predict, with the best R 2 (0.48) obtained in a prediction of σ from ln k. Relationships for the carbonate samples are generally less reliable, which is attributed to a complex history of multiple phases of karsting and burial. The largest R 2 values obtained are 0.67 for prediction of σ from κ, and 0.36 for prediction of σ from ρ g . All the other R 2 values are ≤0.19. Both the sandstone and the carbonate data show σ‐φ; relations with negative coefficients, rather than positive as predicted by Archie's law, because of the very low water saturations. In the sandstone, the water connectivity is reduced with increasing grain surface area (with increasing φ and k), so σ decreases. In the carbonate, σ correlates with the degree of dolomitization, and the water content is too low to contribute to σ.
Petrophysics
Saturation (graph theory)
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