computed tomography, Oil & Gas Glossary

What Is Computed Tomography in Petroleum Geoscience?

Computed tomography (also called CT scanning, X-ray CT, or industrial CT) is a non-destructive imaging technique that uses a rotating X-ray source and detector array to measure X-ray attenuation through a sample at hundreds of angles, then applies backprojection reconstruction algorithms to generate three-dimensional density maps revealing internal pore structure, natural fractures, bedding planes, fluid distributions, and sedimentary features in core samples, drill cuttings, or wellbore plugs without cutting or altering the specimen.

Key Takeaways

CT scanning is entirely non-destructive — a full core plug or whole core section can be scanned at 0.1 to 1 mm resolution before any cutting, trimming, or fluid extraction, preserving sample integrity for subsequent conventional analysis.
CT density values are expressed as Hounsfield units (HU): water is defined as 0 HU, air as -1,000 HU, and dense minerals such as pyrite or barite range from +2,000 to +3,500 HU, allowing quantitative density mapping across the sample interior.
Industrial core scanners achieve voxel resolutions of 0.1 to 1 mm, roughly 10 times finer than medical CT scanners (which have 1 to 10 mm slice thickness), enabling visualization of fractures as narrow as 0.2 mm and pore throats in the millimeter-scale range.
CT scanning is the standard technique for characterizing natural fractures in tight carbonate and shale core before any plugging or slabbing, because cutting through the core destroys the three-dimensional fracture connectivity that CT preserves.
Dynamic CT experiments — scanning a core while displacing one fluid with another — allow direct visualization of fluid front advancement, capillary trapping, and residual saturation distributions at the pore-network scale without dismantling the flooding apparatus.

CT Scanning Principles and Application to Core Analysis

In a CT scanner, a fan-shaped X-ray beam passes through the sample at a series of angles as the sample (or the source-detector assembly) rotates through a full 360 degrees. At each angle, the detector array records the intensity of X-rays that have passed through the sample; intensity reduction (attenuation) depends on the density and atomic composition of the material in the beam path. A computer assembles these attenuation profiles from all angles and applies a filtered backprojection algorithm — or, in modern systems, an iterative reconstruction algorithm — to calculate the three-dimensional attenuation distribution inside the sample. The result is a volumetric dataset of voxels (volume elements), each assigned a CT number in Hounsfield units that reflects the average density and effective atomic number of the material within that voxel.

For petroleum applications, the CT number correlates directly with the bulk density of the rock at each voxel location. Dense minerals such as calcite (approximately 2.71 g/cm³) and dolomite (2.87 g/cm³) produce high CT numbers (700 to 1,200 HU in typical core), while pore space filled with air produces values near -1,000 HU and pore space filled with water produces values near 0 HU. This density contrast is the fundamental discriminant that allows CT images to identify pores, fractures, and mineral heterogeneity. In practice, geoscientists calibrate CT number to bulk density using companion measurements from a gas pycnometer and routine core analysis, establishing a linear conversion specific to each formation's mineralogy.

Whole core CT scanning is now standard practice at many major core analysis laboratories worldwide, conducted on the core immediately after it arrives from the wellsite and before any plugging or slabbing. This pre-analysis scan establishes a digital record of the core's internal structure in its received condition, which is invaluable because subsequent handling — even careful transport — can damage natural fractures and disturb sedimentary structures. The CT image guides plug selection (directing the analyst to plug through representative matrix away from fractures unless fracture permeability is the study objective), identifies rubble zones unsuitable for conventional analysis, and reveals lamination or bioturbation patterns that would be invisible on the slab face alone.

Fast Facts: Computed Tomography in Petroleum Geoscience

Typical core scanner resolution: 0.1 to 1.0 mm voxel size (versus 1 to 10 mm for medical scanners)
CT number scale: Air = -1,000 HU; water = 0 HU; quartz = ~1,800 HU; calcite = ~1,000 HU; pyrite = ~3,500 HU
Sample sizes: Whole core (up to 5.5 in. diameter), half-core slabs, 1.5 in. plugs, sidewall cores, and drill cuttings
Key applications: Fracture characterization, fluid saturation mapping, preserved core description, plug selection, flow experiment monitoring
X-ray energy range: Industrial core scanners use 100 to 450 kV sources; medical scanners use 80 to 140 kV
Scan time: 1.5 in. plug scan takes 5 to 15 minutes; whole core section scan may take 30 to 90 minutes
Related technique: Micro-CT (microcomputed tomography) achieves 1 to 50 micron resolution for pore-network analysis on 2 to 25 mm diameter samples
Integration: CT images are co-registered with porosity, permeability, and thin-section data using core depth to build integrated reservoir models

Core Analysis Tip:

Always scan whole core before plugging. Drilling-induced fractures — which have no reservoir significance but dramatically alter permeability measurements — look identical to natural fractures on a slab face but are distinguishable in CT cross-sections: drilling-induced fractures are typically parallel to the core axis and have planar, clean faces, while natural fractures are inclined, rough, and often mineralized. Mistaking a drilling-induced fracture for a natural one leads to incorrect fracture permeability estimates and flawed completion designs in tight formations.

Computed tomography is also referred to as:

CT scanning — the universal shorthand used in both medical and industrial contexts; in petroleum geoscience, "CT scan" almost always refers to industrial X-ray CT of core or rock samples
CAT scan — computed axial tomography, the original medical term coined in the early 1970s; rarely used in petroleum engineering contexts but occasionally appears in older literature
X-ray CT — used to distinguish from other tomographic methods (neutron tomography, positron emission tomography) and to emphasize the radiation source type, particularly relevant when discussing safety protocols for radioactive source handling
Industrial CT — distinguishes petroleum and manufacturing applications from medical diagnosis; industrial CT scanners are typically higher-energy and not constrained by patient dose limits, enabling denser material penetration

Frequently Asked Questions About Computed Tomography

What is the difference between CT scanning and micro-CT in petroleum applications?

Standard industrial CT scanning — the kind used for whole core and plug description — achieves voxel resolutions of 0.1 to 1 mm, which is sufficient to image fractures, bedding, and centimeter-scale heterogeneity, but too coarse to resolve individual pores in most reservoir rocks. Micro-CT (microcomputed tomography, or microCT) achieves resolutions of 1 to 50 micrometers on 2 to 25 mm diameter samples, which is fine enough to image the three-dimensional pore network directly. From micro-CT data, researchers compute pore-network models and simulate single-phase and multiphase flow using lattice-Boltzmann methods, producing absolute and relative permeability estimates directly from pore geometry without flooding experiments. The trade-off is sample size: micro-CT samples are so small (often less than 5 mm diameter) that they may not represent reservoir-scale heterogeneity, and results must be upscaled carefully.

Can CT scanning measure fluid saturation during a flooding experiment?

Yes, and this is one of the most powerful applications of CT in enhanced oil recovery research. Because water, oil, and gas have different X-ray attenuation values (different densities and effective atomic numbers), a CT scan taken during a coreflooding experiment shows where each fluid phase is located within the pore network at that moment. By scanning the core repeatedly as a displacing fluid front advances — for example, CO2 injected to displace resident brine in a carbon storage experiment — researchers can map the saturation distribution at each scan time, observe channeling and fingering in real time, and measure residual saturation directly by comparing fully saturated and post-flood scan datasets. Iodinated brine (potassium iodide added to water) is commonly used to enhance contrast between the aqueous and non-aqueous phases because iodine has a high atomic number and greatly increases water-phase attenuation.

How are CT images integrated with conventional core analysis data?

CT images and conventional plug measurements are co-registered using core depth — a shared reference frame tied to either the drill pipe depth at which core was cut or a depth-corrected core gamma ray log measured at the wellsite before boxing. Once co-registered, each plug's measured porosity, permeability, and capillary pressure can be spatially located within the CT volume, allowing analysts to check whether a low-permeability plug sits in a visibly tight zone on the CT image or whether an anomalous measurement is associated with an unresolved fracture or lamination. Statistical correlations between CT number (bulk density) and porosity are used to populate porosity values throughout the entire CT volume, effectively extending the sparse plug measurements into a continuous depth profile at CT resolution — a technique called CT-derived porosity profiling that is standard practice in many major oil company core analysis workflows.

Why Computed Tomography Matters in Oil and Gas

Computed tomography has become a fundamental tool in petroleum geoscience because it solves the central problem of core analysis: how to extract maximum information from a finite and irreplaceable sample without destroying it. Every conventional measurement — porosity, permeability, thin section, SCAL — consumes or alters part of the core, so the order in which analyses are performed determines what information is recoverable. CT scanning sidesteps this constraint by capturing the full internal geometry non-destructively before any intervention, creating a digital archive of the core at its received condition that can be interrogated indefinitely. In tight formations where fracture connectivity governs producibility, in carbonates where vuggy porosity is invisible on conventional logs, and in enhanced oil recovery research where pore-scale fluid distribution controls recovery efficiency, CT imaging provides insight that no other practical technique can match at comparable scale and resolution.

Computed Tomography: Non-Destructive Core Analysis by X-Ray CT