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Technology Update

Shale Reservoir Evaluation Improved by Dual Energy X-Ray CT Imaging

The rise of unconventional shale plays as an economically feasible oil and gas resource has created an unprecedented opportunity and challenge for laboratory core analysis providers. By some estimates, more than 80% of the core samples being extracted from North American fields are from shale formations. Core analysis has become an integral part of most unconventional exploration and development projects because the data is essential to petrophysical interpretation, reservoir modeling, and reserve estimation. A major difficulty facing operators is that shale core analysis conducted by traditional laboratories has been a slow process, with the data sometimes arriving too late for use in time-critical business decisions.

Digital rock physics (DRP) analysis (Walls and Sinclair 2011) offers a faster way of obtaining the needed data for shale reservoir evaluation. DRP analysis of shales usually involves three stages, each providing visual and quantitative information to help select a smaller representative rock volume for the next analytical stage. Stage 1 analyzes whole cores or cuttings; Stage 2 analyzes samples from cuttings to plug size; and Stage 3 analyzes samples at pore scale in 3D with ultrahigh resolution. The process takes only a few weeks for most wells.

In this report, we will examine the first stage of DRP for whole or slabbed core, using the CoreHD technique developed by Ingrain. The method is based on dual energy X-ray computerized tomo­graphy (CT) imaging and usually requires only a few days to complete. The technique has also been used at remote drillsites, with the core being analyzed within minutes or hours of being brought to the surface.

Dual Energy X-Ray CT Imaging

As X-ray CT imaging technology im-proves, so has the value of the data for the oil and gas industry. Beginning in the 1980s, petroleum literature on CT imaging such as “X-ray Computerized Tomography” by S.L. Wellington and H.J. ­Vinegar (JPT, August 1987) can be found. In the past 2 years, Ingrain has developed and refined a comprehensive workflow to analyze shale core by harnessing the value of dual energy X-ray CT imaging. From X-rays produced at different energy levels, continuous whole core scans can be calibrated to produce bulk density (RHOB) and photo­electric factor (PEF) values at about half-­millimeter resolution. At this resolution, 1 ft of core scanning produces around 500 CT images. The images show important geological details including fractures, bedding planes, fossils, and bioturbation. The high-resolution computed RHOB and PEF values can be used to interpret porosity, organic content, and mineralogy. When combined with other commonly available information such as core spectral gamma data, more complex analyses can be performed. For example, elastic properties and brittleness index can be determined.

Whole Core Imaging for Shale Geology, Petrophysics

Shale can be defined as siliciclastic sedimentary rocks composed of mud-sized particles which can be laminated or nonlaminated (Boggs 2000). Most unconventional resource “shale” plays are more accurately called organic-rich mudstones (Passey et al. 2010) and can vary from highly siliceous to mostly calcareous. From a visual inspection of slabbed cores, it can be very difficult to determine heterogeneities, especially mineralogical and density changes. By imaging whole core with X-ray CT technology, it is possible to produce 3D volumetric renderings that reveal the heterogeneity of shale cores in sharp detail. X-ray CT imaging provides a noninvasive way of describing shale core, reveals more details about rock fabric than core photos, and allows continuous RHOB and PEF curves to be computed. The process also leads to better informed decisions on where to obtain plug samples. By observing these images, it becomes clear that not all shales are homogeneous and that many are quite complex in mineralogy and structure at the whole core scale.

Bulk Density and Photoelectric Factor

X-ray CT imagers produce detailed pictures of transmitted X-ray energy, and with correct processing and calibration, RHOB and PEF can also be computed. To compute these two rock properties, the imaging requires the use of two beam energies. Although imaging in dual energy mode is more time consuming, the value of the extra data can be substantial. When a single X-ray energy is used, only relative changes in X-ray attenuation can be determined. However, dual energy imaging can be used to estimate porosity, total organic carbon, and mineralogy in most shale formations. Each mineral has a distinctive PEF value, an indicator for mineralogy, e.g., quartz PEF=1.8, dolomite PEF=3.14, and calcite PEF=5.08. More importantly, RHOB and PEF can be computed at very high resolution, which is critical for finely laminated shales.

Qualitative Facies Analysis and Plug Sample Depth Selection

Bulk density and effective PEF data can also be displayed in a crossplot with mineral trend lines of common minerals such as quartz and calcite. Depending on where the data points plot on the PEF axis, observations of the amounts of quartz and calcite in the core are possible down to a vertical resolution of less than 1 mm. Changes in RHOB values can be used as an indicator for porosity and/or organic material.

Observations from the RHOB vs. PEF plot can be used to distinguish and qualitatively separate distinct populations from each other (Fig. 1). Density and PEF cutoff values are chosen and applied to divide the data points into a qualitative color-coded CoreHD facies. On the vertical axis, data points assigned to the green- and red-coded facies express lower densities than the black- and blue-coded facies. A change in color along the horizontal axis represents a change in mineralogy from quartz-rich to calcite-rich, and vice versa.

High-resolution RHOB and PEF values also provide a greatly improved method of selecting depth locations for plug sampling. Before this technique became available, many laboratories would extract plug samples on some fixed depth interval such as one every 10 ft. This fails to account for the enormous vertical variability of many shale reservoirs. A better approach is to divide the key shale intervals into distinct facies and select a set of samples representing a range of properties for each facies. Using high-resolution RHOB and PEF data plus 3D imaging obtained by the first-stage DRP technique, geoscientists can intelligently select the exact plug sampling locations directly from their workstations.

Verification of the RHOB and facies analysis derived from the first-stage DRP technique has been confirmed by subsequent steps of the DRP process. The results of scanning electron microscope (SEM) imaging of plugs chosen from each of the reservoir facies, and the direct measurement of plug sample RHOB, are shown in Fig. 2. The SEM images show that a sample selected from the green-coded facies has substantially higher porosity and kerogen content than one selected from the blue-coded facies. Physically measured RHOB values compared with those derived from dual energy X-ray CT technology also show good agreement.


The combination of DRP and high-resolution X-ray CT imaging can provide rapid, noninvasive geological and petrophysical analysis of whole core samples while they are still inside the protective aluminum core barrel liners. Using RHOB and PEF logs derived from dual energy CT imaging, the whole core workflow enables the observation of mineralogical and lithological changes at much higher resolution than traditional well logs. The data can be qualitatively categorized into multiple color-coded facies corresponding to physical rock properties. In shale reservoirs, these facies represent varying amounts of silica and carbonate material as well as varying porosity and organic material. In addition, using dual energy X-ray CT imaging to derive RHOB and PEF values improves the selection of plug locations and provides a more representative sampling for highly variable shale formations.


  • Boggs, S. 2000. Principles of Sedimentology and Stratigraphy. Upper Saddle River, New Jersey: Pearson Prentice Hall.
  • Passey, Q.R., Bohacs, K.M., Esch, W.L., et al. 2010. From Oil Prone Source Rock to Gas-Producing Shale Reservoir—Geologic and Petrophysical Characterization of Unconventional Shale Gas Reservoirs. Paper SPE 131350 presented at the CPS/SPE International Oil and Gas Conference, Beijing, 8–10 June. 10.2118/131350-MS.
  • Walls, J.D. and Sinclair, S.W. 2011. Eagle Ford Shale Reservoir Properties From Digital Rock Physics. First Break 29 (6): 97–101.