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Accurate description of mineralogy bears on oilfield operations and can be used to calibrate downhole logs and develop petrophysical models for oilfield exploration and development. X-ray diffraction (XRD) is the industry-standard for quantitative mineral analysis, but the accuracy of the method varies substantially due to differences in sample preparation, sample measurement, and data-analysis techniques. This paper reviews the alternative transmission Fourier transform infrared (FTIR) spectroscopy technique for quantitative analysis of sedimentary formations including recent analytical improvements, and examines the differences between XRD and FTIR mineralogy in several case studies. The FTIR procedure has been modified to address two challenges, namely cloudy pellets and the presence of adsorbed water in FTIR spectra. Quantitative mineral analysis by FTIR is enabled using a generalized least-squares inversion against a library of mineral standards with unique IR spectra. Mineralogy results from FTIR are compared with those obtained using XRD techniques commonly practiced by commercial XRD laboratories on over one hundred sedimentary samples spanning carbonate, sandstone and shale lithologies. Accuracy of the mineralogy is evaluated using whole-rock chemistry. Bulk major-element (Si, Ca, Al, K, Na, Mg, Fe, and S) concentrations are reconstructed from the mineralogy by assigning chemical compositions to each mineral, and are then compared against measured elemental concentrations obtained on identical splits of the samples using independent and validated chemical-analysis techniques. Conformance between the reconstructed and measured elemental concentrations is assessed by quantifying the difference between the two. For the sets of samples examined here, FTIR results are consistently better than those from XRD using this conformance criterion. The data indicate that FTIR can provide quantitative and accurate mineral analysis of sedimentary formations, which can be used, for example, to calibrate and validate quantitative petrophysical interpretations in oilfield operations.

Methods for predicting mineralogy from logging tool measurements have been an active area of research for several decades. In spite of these efforts, methods for predicting quantitative mineralogy including clay types from well logging data were not fully achieved. The introduction of geochemical logging tools in the 1980s offered promise; however, early versions of geochemical logging tools did not measure elemental chemistry with enough accuracy and precision to enable reliable and quantitative determination of mineralogy. Recent advances in geochemical logging tool technology now enable accurate and robust measurements of the chemical elemental concentrations that are needed to determine continuous quantitative and detailed logs of mineralogy. This paper presents a novel approach for determining more accurate, detailed mineralogy from an elemental spectroscopy logging tool. This work was made possible by three recent developments: the introduction of a new high-performance neutron-induced gamma ray spectroscopy logging tool, a new high-quality research database consisting of chemistry and mineralogy measured on cores acquired worldwide from conventional and unconventional reservoirs, and a new model-independent inversion method that overcomes the limitations of previous model-dependent methods. The model-independent inversion makes use of the database which includes clean sands, shaly sands, shales, carbonates, and complex mixed lithologies. The database contains laboratory measurements of dry-weight elemental chemistry and mineralogy measured by transmission Fourier transform infrared spectroscopy. The database is used to derive a model-independent mapping function that accurately represents the complex functional relationship between the elemental concentrations and the mineral concentrations. Once the mapping function is determined from the database, it can be used to predict quantitative mineralogy from elemental concentrations derived from the logging tool measurements. Unlike previous inversion methods, the model-independent mapping function does not have any adjustable parameters or require any user inputs such as mineral properties or endpoints. The mapping function is used to predict continuous logs of matrix densities plus concentrations of 14 minerals (i.e., illite, smectite, kaolinite, chlorite, quartz, calcite, dolomite, ankerite, plagioclase, orthoclase, mica, pyrite, siderite, and anhydrite) from eight dry-weight elemental concentrations derived from the logging tool. The new method has been applied to well log data acquired worldwide in numerous conventional and unconventional reservoirs having a wide variety of complex mineralogies. The predicted mineralogies and matrix densities are generally found to be in good quantitative agreement with core-derived mineralogies and matrix densities.

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, sonic-resistivity 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.

The accurate determination of formation hydrocarbon or water saturation is an essential step in the petrophysical evaluation of petroleum reservoirs. A novel method has been developed for estimating hydrocarbon saturation directly from a total organic carbon (Corg) log and a porosity log. The method is enabled by the recent development of a pulsed-neutron logging tool that combines inelastic and capture gamma ray spectroscopy measurements to provide a robust and accurate total organic carbon estimate. The method differs from the well-known approach of using carbon-to-oxygen ratios that is most often applied in cased-hole evaluation. The main advantages of this new method are that it does not require knowledge of formation water resistivity, it does not rely on a resistivity model, it does not require an extensive calibration database, and it is largely independent of clay or other lithology effects. Calculations are available to explore uncertainties in the saturation estimates arising from uncertainties in the log inputs. The statistical uncertainty in the estimate of hydrocarbon saturation is as good as 10 saturation units (s.u.) in conventional reservoirs with porosities of 15 p.u. or greater. The method has been applied to the determination of hydrocarbon saturation in a variety of formations, including bitumen-filled dolomite, heavy oil sand, and shaly sands with both open-hole and cased-hole wells. The method works equally well in formations drilled and logged with either oil- or water-based mud. The saturation estimates have been benchmarked against a combination of conventional and new logging approaches (e.g., resistivity, magnetic resonance, and dielectric logs) and core measurements, with generally excellent agreement among independent determinations. Hydrocarbon saturations can be determined accurately using the method in a number of formation types where conventional methods and models for estimating fluid saturation commonly fail, such as freshwater and unknown water salinity in formations under enhanced oil recovery. The case studies demonstrate that a Corg log derived from geochemical spectroscopy logs can be used to obtain reliable estimates of hydrocarbon saturation in a wide range of environmental conditions and formations.

A well drilled in the Green River formation in Colorado on the Bureau of Land Management RD&D lease of American Shale Oil LLC (AMSO), provides an opportunity to compare core measurements and log-derived properties in a unique unconventional resource reservoir. The core was analyzed for matrix density, Fischer Assay, total organic carbon (TOC), mineralogy, and 58 inorganic elemental concentrations. Logs include neutron, density, gamma ray, resistivity, magnetic resonance, and inelastic and capture nuclear spectroscopy. The data from this well are used to demonstrate new methodologies to estimate the TOC content and Fischer Assay oil yield.The TOC content is estimated in three ways. The first is a multitool petrophysical evaluation. The second is an estimation of kerogen from the difference between density and magnetic resonance (MR) porosities where MR porosity corresponds to the water-filled porosity and density porosity to the sum of kerogen-and water-filled porosity. The third method combines inelastic and capture nuclear spectroscopy log data to compute elemental concentration logs of total carbon, inorganic carbon, and TOC.For comparison of core mineralogy and chemistry with log data, over 200 intervals of core from this well were sampled as 2-ft-long slabs that were ground and homogenized, approximating the vertical resolution of log responses. The agreement between the logs and core values for total carbon, total inorganic carbon, and TOC is very good. The TOC log is used to activate empirical relationships such as Fischer Assay oil shale grade from TOC, again with good results.

Summary Geochemical logs run through a complex carbonate formation yield accurate elemental concentration logs. These are instrumental to the computation of detailed formation mineralogy and derivative properties, such as matrix density and sigma. The quantitative mineralogy logs also are used to estimate permeability empirically with a correlation observed from core data. Introduction The Utility of geochemical logging was evaluated in a Middle East reservoir described as extremely complex and heterogeneous in terms of its degree of dolomization, argillaceous content, secondary porosity, and porosity distribution. Geologists, reservoir engineers, and petrophysicists working in this reservoir identified well-to-well correlation as a problem, and for log interpretation, they specifically cited problems with the accuracy of (1) porosity determination, (2) degree of dolomitization, (3) characterization and quantification of clay minerals and clastics, and (4) permeability estimations. It appeared that these problems were interrelated, and it was anticipated that, by providing a detailed interpretation of the rock composition, geochemical logging might aid in geologic characterization, petrophysical interpretation, and ultimately, interwell correlation. The objectives of the study were to determine the quality of the primary geochemical interpretation products (elements and minerals) and to investigate the effects these answers had on geological and petrophysical interpretation. The study was composed of a combined logging and core analysis program. The pertinent core analysis was divided into two parts, with standard petrophysical measurements of grain density, porosity, and permeability made on plugs spaced approximately at 1-ft intervals throughout the reservoir, and a subset of samples analyzed for chemistry and mineralogy. The logging program included the Geochemical Logging Tool (GLTSM), which measures elemental concentrations of aluminum, silicon, calcium, iron, sulfur, gadolinium, titanium, thorium, uranium, potassium, and magnesium.1 In addition to a full suite of resistivity and nuclear logs. Results show that the geochemical elemental concentration and mineral concentration logs describe the formation with an accuracy that could not be obtained previously without extensive core analysis. The new logs clearly delineate the zones of dolomitization and quantitatively interpret the amount of noncarbonated minerals. The mineral logs were used to compute a continuous matrix density, which was in turn used to determine porosity. The results of the mineralogy and porosity interpretations are compared directly with core measurements and also with the results of a volumetric log interpretation that does not include geochemical data. The elemental concentration logs and mineral concentration logs were used together to derive matrix sigma and apparent fluid signs, which were in turn used to estimate near-wellbore saturation. Finally, the core and log data also were used to illustrate a relationship between mineralogy and permeability. The result is an accurate formation description in terms of composition and petrophysics, which should enhance correlation and reservoir evaluation. The interpretation is a scientifically based analysis that does not require numerous log-analyst picks or a large degree of regional modification. Instead, the elemental concentrations are transformed through a fixed composition matrix into mineral concentrations. Many of the petrophysical components, such as grain density and matrix sigma, are natural consequences of the mineralogy, and therefore, can be directly computed from the mineralogy. Other properties, such as permeability, can be more affected by diagenetic events and fracturing. Some diagenetic events, like dolomitization, are implicit in the mineralogy, and in this case, the degree of dolomitization can be used to estimate the permeability.

Rapid petrophysical evaluation is critical in such expensive venues as the deepwater Gulf of Mexico. Recently, a real-time petrophysical analysis program was introduced based on the combination of elemental concentrations from spectroscopy and standard triple-combo logging1. The application consists of a spectroscopy-based quantitative lithology consisting of total clay, sand, carbonate and pyrite2. Elemental concentrations are used to correct neutron and density for matrix effects3 to directly compute total porosity and to correct for lithology and thereby enhance neutron-density crossover in the case of gas. Intrinsic permeability is computed from the lithology and total porosity using the k-Lambda approach4. Water salinity is input and water saturation is computed using the Waxman-Smits-Thomas equations and porosity and lithology5,6. Finally, irreducible water saturation is computed from the Coates-Timur7,8 equation using the calculated porosity and permeability. This rapid, automatic petrophysical interpretation has been applied to data from a cored well in the deepwater and comparison with core data demonstrates the validity of the porosity, permeability, and saturation evaluations. Computed total porosity is in very good agreement with core values. Computed permeability is generally within a factor of three of measured permeabilities. Computed water saturation is also in good agreement with core values, partially due to the use of oil-based mud. However, in spite of the accurate petrophysical evaluation, the interpretation was initially suspect due to a significant discrepancy between the computed clay content and the core values measured by x-ray diffraction (XRD). XRD clay averages less than half of the values computed from spectroscopy using the default subarkose model. In order to investigate this discpreancy, twenty plugs were analyzed for major and minor element chemistry and for mineralogy by dual-range Fourier Transform Infrared (DRFT-IR). DRFT-IR mineralogy is independently validated by comparison with chemistry and is in good agreement with wireline computed total clay. Finally, these DRFT-IR and chemistry data are used to produce an optimized total clay from chemistry model that can be used in existing or future wells in this field with spectroscopy data.

There is a long history of wanting to provide a petrophysical answer, comprising at least porosity and saturation, either in real time or within, at most, a couple of hours after logging. Past attempts to provide such a product have been plagued by the need to define numerous parameters and well zonations that would ordinarily be selected by a skilled interpreter. With the introduction of elemental concentration logs obtained from nuclear capture spectroscopy tools, the number of interpretation parameters can be dramatically reduced. This is because the accuracy of the lithology and matrix properties is a significant advance over values determined from conventional techniques. Consequently, it is much easier to directly apply scientific conductivity and permeability models for petrophysical evaluation.

The stratigraphie record of melt features in intermediate depth polar ice cores has provided valuable data on past summer climate1–3. The thermal drilling technique used in previous studies precluded extending this record beyond a few hundred years. Recently, however, a 901-m deep ice core was mechanically drilled in southern Greenland. The excellent core quality and improved techniques for measuring melt features have resulted in an ∼2,200 yr record with consistently high quality data. We report here that the temporal variations in melt feature abundance, expressed as annual melt per cent (AMP), provide proxy data on summer climate that can complement other records extending back thousands of years. The AMP profile indicates that relatively warm summers prevailed from about AD 950 until AD 1500 culminating in the thirteenth and fourteenth centuries. The periods from about 300 to 150 BC, AD 350 to 550, and AD 1550 to 1800 had relatively little summer melting.