The increasing complexity of today's reservoirs requires a good understanding of a formation's mineralogy to make an accurate petrophysical analysis. This is particularly true in the case of unconventional reservoirs, for which the quantification of both mineralogy and organic carbon content is critical to confidently appraise and develop new prospects.A new spectroscopy tool is being applied to evaluate challenging shale gas reservoirs. The new measurements quantify key mineral-forming elements with higher precision and accuracy than previously possible. The new technology provides a direct determination of total organic carbon (TOC), which is an important parameter in the evaluation of kerogen-rich unconventional reservoirs.Accurate lithology and kerogen volumes ultimately affect the estimation of porosity and free and adsorbed gas saturations, which are critical for evaluating resources and planning for further field development. Mineralogy can also be used in geomechanical models to determine completion quality, design stimulation operations, and specify intervals for perforation.The results obtained show excellent agreement with core data for TOC, elemental concentrations, and mineral abundances. One of the main advantages of computing TOC directly from carbon is that it does not require calibration to core data as do empirical methods based on local correlations that use more indirect measurements such as bulk density, sonicresistivity overlay, or uranium concentration. The robustness of the proposed direct carbon approach is illustrated by comparing it with core and well-established methods for estimating TOC, such as the Schmoker technique.

Recently, Saudi Aramco upstream activities in unconventional gas, and in particular tight gas sands, have been identified as a focus area. Integral to understanding the potential of tight gas as a resource, is an understanding of the petrophysical characterization of tight gas intervals. This paper presents a review of the petrophysical challenges in the evaluation of tight gas intervals encountered within an existing producing field producing from formation U. This formation can be highly variable and although it can be highly productive, in some areas the geology has produced poorer reservoir quality rock. Production from wells which penetrate these areas can exhibit "Tight Gas" characteristics. Core and log data from existing fields are abundant and cover both good and poorer quality reservoir intervals. The factors which impact the evaluation of these "Tight Gas" intervals, in this relatively well sampled environment, can be generalized to the evaluation of less well studied tight gas formations. The results of this review identify many areas where current techniques and tools fall short of providing an adequate characterization. In particular, the quantification of mineralogy and diagenesis is seen as important, as is the quantification of saturations and accurate measurement of micro-Darcy permeabilities. Areas where current techniques require improvement are highlighted and projects that are in progress to address these issues and improve the evaluation of tight gas are detailed. One area which is highlighted as holding potential is rock typing, which can categorize different types of tight gas interval based on clay content or mineralogy. Three wells have been selected for a fracturing exercise as a proof of concept to assess the production potential. The results of the fracturing exercise are presented relative to the petrophysical evaluation of these wells.

The mixed-salinity environment poses a challenge in petrophysics. Many efforts have been made, but the industry still lacks a workable solution for accurate formation measurements in the presence of variable or unknown water salinity, especially in reservoir surveillance when well completion restrictions require running slim logging tools. A pulsed-neutron (PN) spectroscopy tool was characterized using laboratory limestone formations and with data generated through Monte Carlo simulation. Seventy-six measurements were conducted with conditions of openhole (OH) and cased-hole (CH) completion, porosities of 15.4 and 42.9%, borehole fluids of water and oil, and borehole and formation water salinities of 0, 20, 50, 100, and 200 ppk. These were supplemented with 88 modeled points to better define the porosity (extending down to 0%) and salinity dependence of the tool response. Twenty additional measurements were taken in a dolomite formation to investigate lithology dependence and ten additional measurements were taken with oil in a 43.9% porosity formation to investigate fluid saturation dependence. Salinity is derived from data obtained with a PN tool operated in the carbon/oxygen (C/O) mode. Ratios of the elemental yield of chlorine (Cl) to that of hydrogen (H) are computed from the near- and far-detector capture gamma-ray spectra. Using a scheme similar to C/O log interpretation for oil saturation, crossplots of the near- and far-detector Cl to H ratios were generated. A quadrilateral is formed on this crossplot by separately varying the borehole and formation water salinities. The established quadrilaterals, a newly developed algorithm to handle intermediate values of near and far ratios and of porosity, and independently obtained borehole water holdup (Yw) and reservoir water saturation (Sw) are then used to compute the borehole and formation water salinities that produced the measured Cl to H ratios. Results obtained were compared with values determined from formation tester samples, demonstrating that a solution for accurate formation water salinity determination is established, thus resolving the challenge of mixed salinity in formation evaluation and reservoir surveillance.

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Elemental Spectroscopy measurements have become a standard component of the logging program in Exploration, Delineation and special Evaluation wells for Saudi Aramco. Elemental Spectroscopy data has proved critical when evaluating complex lithology formations in both siliciclastic and carbonate rocks to produce an accurate mineralogy analysis, resulting in good understanding of the subsurface lithology in a cost effective way. A rigorous qualification protocol is applied to novel services when they are introduced to Saudi Aramco. New measurements are compared to existing equivalent services if available and to core data if applicable. For the specific case of the new Elemental Spectroscopy device, the elemental outputs were compared to a previous generation tool and to elemental concentrations from core measurements in a wide variety of formations and lithologies in clastic and carbonate reservoirs. Clastic reservoirs were covered in previous publications; in this work we show the results for carbonate rocks. Initial comparisons between the previous and new generation tools showed good agreement for most of the elements except for Mg (Magnesium) at low concentrations. Several samples were selected from Jurassic carbonate reservoirs to understand better differences at low Mg concentrations. All samples were taken as 1 foot side trims from a full core slab. The samples were crushed and homogenized to minimize the effects of heterogeneity. The prepared samples were analyzed using X-ray fluorescence (XRF) for elemental concentrations and Dual Range Fourier Transform Infrared Spectroscopy mineralogy (DT-FTIR) for mineralogy. The elemental results from both tools and the core samples were then plotted and compared. While existing measurements work in many areas, there are specific cases where the new technology can generate improved formation evaluation in carbonate formations or increase efficiency by logging faster.