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Magnetic Resonance Logging

What Is Magnetic Resonance Logging?

Magnetic resonance logging (also called nuclear magnetic resonance logging, or NMR logging) is a petrophysical measurement technique that applies pulsed magnetic fields to the formation surrounding the borehole and measures the response of hydrogen nuclei (protons) in formation fluids to determine total porosity, pore size distribution, permeability, bound vs. free fluid volumes, and fluid type without requiring knowledge of the formation's mineral composition. Because the NMR response depends only on the hydrogen nuclei in pore fluids and is independent of rock mineralogy, NMR logging is the most lithology-independent porosity measurement available in wireline and logging-while-drilling (LWD) suites, making it especially valuable in complex carbonate reservoirs, volcaniclastics, and mixed-lithology sequences where density-neutron crossplots are unreliable.

Key Takeaways

  • NMR logging measures T1 (longitudinal) and T2 (transverse) relaxation times of hydrogen nuclei in pore fluids; T2 measurements from the CPMG pulse sequence are the primary product of most commercial NMR tools.
  • The T2 distribution from a single NMR measurement encodes total porosity, pore size distribution, bound water volume, free fluid index, and permeability in a single acquisition without requiring lithology input.
  • T2 cutoffs separate bound from free fluids: 33 milliseconds for sandstones and 92 milliseconds for carbonates are the most widely used industry defaults.
  • NMR permeability is estimated from empirical transforms: the Schlumberger-Doll Research (SDR) model uses mean T2 and total porosity, while the Coates (free fluid) model uses the ratio of free fluid to bound fluid volumes.
  • In shale formations, NMR detects solid kerogen in addition to pore fluids, and the kerogen signal overlaps with clay-bound water in the short T2 range, requiring specialized processing to separate organic porosity from inorganic pore space.

How Magnetic Resonance Logging Works

The NMR measurement begins by applying a strong static magnetic field B0 from permanent magnets in the tool body, which aligns the magnetic moments of hydrogen protons in the formation fluids along the field direction in a process called polarization. The time required for protons to reach full polarization is governed by the longitudinal relaxation time T1, which ranges from a few milliseconds for clay-bound water to several seconds for light oil and gas. After polarization, the tool fires a series of oscillating radio-frequency (RF) pulses perpendicular to B0, tipping the proton magnetization into the transverse plane where it can be detected as a time-decaying voltage signal called a spin echo. The most widely used RF pulse sequence is the Carr-Purcell-Meiboom-Gill (CPMG) sequence, which refocuses the transverse magnetization at regular intervals (the inter-echo spacing TE) to generate a train of echoes whose amplitude decays according to the transverse relaxation time T2.

The amplitude of the initial echo train is proportional to the total number of hydrogen protons in the pore fluid and is therefore proportional to total porosity, calibrated in porosity units (p.u.) just like a conventional neutron porosity tool. The rate of echo amplitude decay encodes the T2 distribution of the pore fluid: hydrogen in large, water-filled pores decays slowly (long T2), while hydrogen in small pores or bound to clay surfaces is strongly relaxed by the solid-liquid interface and decays rapidly (short T2). Inversion of the echo train into a T2 spectrum using a regularized least-squares algorithm produces a T2 distribution curve that is the fundamental output of the NMR measurement. The area under the T2 distribution equals total porosity. The area under the distribution below the T2 cutoff equals bound fluid volume (irreducible water saturation plus clay-bound water), and the area above the cutoff equals the free fluid index (FFI), which represents the mobile fluid that will produce to the wellbore.

Permeability is not measured directly by NMR but is estimated from the T2 distribution using empirical transforms calibrated to core data. The SDR (Schlumberger-Doll Research) transform calculates permeability as proportional to total porosity raised to the fourth power times the mean T2 (T2lm) squared, and performs well in water-saturated sands and carbonates. The Coates (or Timur-Coates) transform calculates permeability as proportional to total porosity squared times the square of the ratio of free fluid to bound fluid volumes, and is better suited to intervals with mixed wettability. Both transforms require local calibration against core permeability measurements for the highest accuracy, but even uncalibrated, they consistently outperform neutron-density permeability estimates in complex lithologies.

Fast Facts: Magnetic Resonance Logging
  • Physical principle: T1 and T2 nuclear magnetic relaxation of hydrogen protons in pore fluids
  • Primary pulse sequence: CPMG (Carr-Purcell-Meiboom-Gill); T2 decay train inversion
  • T2 cutoff, sandstone: 33 ms (default); separates bound water from free fluid
  • T2 cutoff, carbonate: 92 ms (default); larger pores require longer cutoff
  • Permeability transforms: SDR model (porosity + T2lm); Coates model (FFI/BVI ratio)
  • Schlumberger tool: CMR (Combinable Magnetic Resonance), 6-inch depth of investigation
  • Baker Hughes tool: MRIL (Magnetic Resonance Imaging Log), 1.5-inch annular volume
  • LWD capability: ProVision (Halliburton), MagTrak (Baker Hughes) for real-time NMR while drilling
Field Tip:

When running NMR in a gas-bearing interval, be aware that hydrogen index (HI) of gas is significantly lower than 1.0, causing NMR to underestimate total porosity compared to a calibrated neutron-density measurement. The shortfall between NMR total porosity and density porosity in a gas zone is a useful gas indicator. Additionally, gas has a very long T1 relaxation time (1 to 10 seconds); use a long wait time between CPMG sequences (TW greater than 5T1,gas) or run a dual-TW acquisition to ensure complete polarization of the gas and avoid underestimating free gas volume in the FFI.

T2 Cutoffs and Fluid Typing

The T2 cutoff is the single most important calibration parameter in NMR petrophysical analysis. In water-wet sandstones, core measurements at irreducible water saturation consistently show that the T2 cutoff separating irreducible (bound) water from free fluid falls near 33 milliseconds, a value established by the seminal work of Kleinberg and Vinegar at Schlumberger in the 1990s and now an industry default. In carbonates, where pore geometry is dominated by vugs, molds, and fractures with much larger characteristic pore sizes, the T2 relaxation of bound water is slower and the appropriate cutoff is approximately 92 milliseconds. These defaults are starting points; rigorous analysis requires measuring T2 cutoff on preserved core plugs centrifuged at reservoir capillary pressure for the specific formation being logged.

Beyond bound vs. free fluid, NMR can distinguish between oil and water using diffusion-based fluid typing methods. Light oils and condensates have T2 values that overlap with water but have very different diffusion coefficients; by running acquisitions at two different echo spacings (TE), the diffusion coefficient can be extracted and used to separate oil from water in the T2 spectrum. Gas can be identified by its combination of very long T1, short T2, and high diffusion coefficient relative to water. In heavy oil formations, the high viscosity of the oil dramatically reduces the T2 of the oil signal into the bound-water range, causing NMR to misclassify heavy oil as bound water unless viscosity-corrected fluid typing methods are applied.

NMR Logging in Shale Formations

Application of NMR logging to organic-rich shale reservoirs (Permian Basin, Bakken, Marcellus, Haynesville) requires additional interpretation care. Solid kerogen within the organic matter contains hydrogen atoms that produce a short-T2 NMR signal indistinguishable from clay-bound water at standard acquisition parameters. The kerogen signal inflates the apparent bound water volume and biases the free fluid index downward if not corrected. Operators use a combination of standard NMR (with short TE to capture kerogen) and an organic carbon content estimate from the resistivity-density transform (delta-log-R method) or a geochemical log to separate organic hydrogen from pore fluid hydrogen. Despite this complexity, NMR remains the preferred porosity measurement in shale because it is unaffected by the high clay content that causes neutron porosity tools to over-read and density porosity tools to require large grain-density corrections in clay-rich lithologies.

  • NMR logging — the most common shorthand for nuclear magnetic resonance logging; used interchangeably with magnetic resonance logging
  • CMR — Combinable Magnetic Resonance tool, Schlumberger's wireline NMR platform; runs combinably with other wireline tools on the same pass
  • MRIL — Magnetic Resonance Imaging Log, Baker Hughes's wireline NMR platform; uses a different magnet geometry than the CMR
  • free fluid index (FFI) — the fraction of total NMR porosity above the T2 cutoff representing mobile pore fluids that can be produced

Related terms: porosity, permeability, wireline logging, petrophysics, water saturation

Frequently Asked Questions About Magnetic Resonance Logging

How does NMR porosity differ from neutron-density porosity?

Neutron-density porosity is calculated from the interaction of high-energy neutrons with hydrogen atoms in the formation and from the bulk density of the rock. Both measurements are affected by the mineral composition of the matrix: clay-rich formations cause neutron tools to over-read (because clays contain structural hydrogen), and heavy minerals like barite or siderite cause density tools to under-read porosity. NMR porosity, by contrast, measures only the hydrogen in pore fluids and is insensitive to matrix mineralogy, making it more accurate in lithologically complex intervals. The primary limitation of NMR is that it does not read hydrogen in very small pores relaxing faster than the shortest detectable T2 (typically 0.3 to 1.0 ms), so NMR slightly underestimates total porosity in tight formations with very fine pore systems.

What is the depth of investigation of NMR logging tools?

Most commercial NMR tools have a shallow depth of investigation of approximately 2.5 to 6 centimetres into the formation from the borehole wall, meaning the measurement reads primarily the flushed zone in invaded permeable intervals. The Schlumberger CMR-Plus and Baker Hughes MRIL both read to about 3.8 cm. Deeper-reading tools such as the Halliburton MR Scanner offer sensitive volumes at 3.8, 5.1, and 7.6 cm, allowing comparison across depths of investigation to reveal invasion profiles and native fluid properties beyond the invaded zone.

Can NMR logging distinguish oil from water without conventional resistivity logs?

Yes, using diffusion-based fluid typing. Oil and water have very different molecular diffusion coefficients; by acquiring echo trains at two different inter-echo spacings (TE), the diffusion coefficient is extracted and used to separate oil from water in a diffusion-T2 map. This is particularly valuable in low-contrast, low-resistivity pay zones, fresh-formation-water environments, or thinly laminated sand-shale sequences where resistivity-based saturation calculations are unreliable.

Why Magnetic Resonance Logging Matters in Oil and Gas

NMR logging has become a routine component of modern petrophysical programs because it provides information no other single measurement can supply: lithology-independent porosity, pore size distribution, and permeability estimation from a single acquisition. In conventional reservoirs, NMR identifies productive free-fluid intervals that resistivity analysis misclassifies as tight. In unconventional shale plays, NMR guides completion design by mapping organic porosity and free gas volumes along horizontal laterals. As drilling extends into geologically complex basins, demand for NMR as a primary petrophysical measurement continues to grow across all major producing regions.

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