NMR Measurement: Definition, Nuclear Magnetic Resonance Logging, and Porosity Analysis

What Is NMR Measurement in Petroleum Well Logging?

Nuclear magnetic resonance (NMR) measurement in petroleum logging uses the magnetic properties of hydrogen atoms in pore fluids to characterise formation porosity, pore size distribution, fluid type, and permeability — without emitting or detecting radioactive particles. An NMR tool applies a static magnetic field that polarises hydrogen nuclei in the formation fluids (water and hydrocarbons), then fires a radio-frequency pulse sequence (CPMG — Carr-Purcell-Meiboom-Gill) to tip the polarised nuclei, and measures the T1 (longitudinal) and T2 (transverse) relaxation times as the nuclei return to equilibrium. T2 relaxation time distribution is the primary output: short T2 (tight pores, clay-bound water) to long T2 (large pores, free fluid) directly maps pore size distribution and distinguishes moveable from irreducible fluid — information no other porosity tool provides.

CPMG Pulse Sequence and T2 Distribution

The CPMG (Carr-Purcell-Meiboom-Gill) pulse sequence is the standard NMR measurement protocol. After polarisation, a 90° radio-frequency pulse tips the magnetised hydrogen nuclei into the transverse plane. A series of 180° refocusing pulses then measure the decaying echo train — the amplitude of successive echoes decreases as hydrogen nuclei lose coherence. The rate of echo amplitude decay at each frequency is the T2 relaxation time. Hydrogen in small pores with large surface-to-volume ratios (clays, tight micropores) relaxes very rapidly (T2 = 1–10 ms) because surface interactions randomise spin phase quickly. Hydrogen in large pores (macropores, vugs) relaxes slowly (T2 = 100–1,000 ms) with minimal surface interaction. The T2 spectrum from a rock sample therefore directly maps its pore size distribution.

The T2 cutoff divides the T2 spectrum into bound fluid volume (BFV, T2 < cutoff) and free fluid index (FFI, T2 > cutoff). BFV is the irreducible fluid — primarily clay-bound water and capillary-held water in tight micropores — that cannot be produced. FFI is the potentially producible fluid. Total NMR porosity (BFV + FFI) agrees closely with true porosity in clean sandstones and carbonates, making NMR the preferred porosity measurement where lithology variation would confound neutron-density cross-plots. The T2 cutoff is formation-dependent — it must be calibrated against capillary pressure or centrifuge data from core plugs for each formation type.

NMR Measurement Synonyms and Related Terminology

NMR measurement is also referred to as:

• NMR log — the wireline or LWD log product from an NMR tool run in a wellbore
• CPMG measurement — after the pulse sequence; used in academic and core lab contexts
• Magnetic resonance imaging (MRI) log — used by Halliburton (MRIL tool name)
• Pore size distribution log — descriptive term used when explaining NMR outputs to non-technical audiences

Related terms: Porosity, Permeability, Formation Factor, Wireline Log

Frequently Asked Questions About NMR Measurement

How does NMR estimate permeability, and how reliable is it?

NMR permeability uses either the Timur-Coates model (k = [φ/C]⁴ × [FFI/BFV]²) or the Schlumberger-Doll-Research (SDR) model (k = C × φ⁴ × T2lm², where T2lm is the log-mean T2). Both relate permeability to pore size information captured by the T2 distribution. NMR permeability is generally more accurate than empirical porosity-permeability transforms because it captures pore size rather than just total porosity — a formation with 15% porosity in large pores (high permeability) looks identical to one with 15% in tiny pores (low permeability) on a porosity log, but NMR distinguishes them through the T2 distribution. Calibration against core permeability improves accuracy significantly: uncalibrated NMR permeability is often within one order of magnitude; calibrated models achieve accuracy within a factor of 2–3 for most formations.

Can NMR log identify gas in the reservoir?

Yes. Gas has very short T1 polarisation time relative to water and a T2 that is shorter than free water in the same pore — but longer than bound water. Gas also shows a distinctive diffusion signature: at different magnetic field gradients (using a multi-gradient tool), gas diffusivity is much higher than oil or water at the same T2. The SLB MR Scanner and Halliburton MRIL-Prime tools run multi-gradient acquisitions specifically to separate gas, light oil, and brine in the T1-T2 or D-T2 domain. This fluid typing capability is particularly valuable in gas-water contact zones, over-pressured gas reservoirs with compressed gas (which can have T2 similar to water), and tight gas sands where resistivity-based gas identification is uncertain due to tight formation water salinity assumptions.

Why is NMR the preferred porosity tool for carbonates?

Carbonates present a severe challenge for conventional porosity tools: neutron-density crossplots require accurate mineralogy corrections for calcite versus dolomite versus anhydrite; photoelectric factor (PEF) and gamma ray are needed to identify mineralogy; cave and vug effects distort pad contact on density tools. NMR bypasses all of this: it measures only hydrogen in fluids, not the rock matrix at all. Carbonate mineralogy — whether the rock is calcite, dolomite, or anhydrite — is invisible to NMR. Total NMR porosity in carbonates agrees well with core porosity across all carbonate pore types, making it the most reliable single-sensor porosity measurement in heterogeneous carbonate formations. The pore size distribution additionally distinguishes microporous mudstones (short T2, poor producibility) from moldic or vuggy grainstones (long T2, good producibility) — critical information for flow unit characterisation in Middle East and Permian Basin carbonate reservoirs.

Why NMR Measurement Matters in Oil and Gas

NMR logging has become a standard component of the logging suite in exploration and appraisal wells drilled into challenging reservoirs — tight sands, heterogeneous carbonates, heavy oil zones, and complex lithology sequences where conventional porosity tools give ambiguous results. The unique ability to measure pore size distribution, separate bound from free fluid, estimate permeability independently of empirical correlations, and identify fluid type from a single non-radioactive tool makes NMR the most information-rich downhole measurement available per tool run. As tight gas and unconventional resource plays demand finer characterisation of nanometre-scale pore systems, NMR — combined with high-field laboratory measurements on core plugs — provides the only direct pore-scale fluid measurement available in the wellbore environment.