CPMG, Oil & Gas Glossary

What Is CPMG?

CPMG (Carr-Purcell-Meiboom-Gill) designates the radio-frequency pulse sequence used in nuclear magnetic resonance (NMR) logging and core analysis to measure hydrogen relaxation times in pore fluids, generating T2 distributions that petrophysicists interpret for porosity, bound-water volume, permeability estimation, and fluid typing across every major producing basin.

Key Takeaways

A 90-degree pulse tips protons into the transverse plane; repeated 180-degree pulses refocus dephased protons into measurable spin echoes.
Echo amplitude decays exponentially; the T2 decay time reflects pore-surface relaxivity, bulk fluid relaxation, and diffusion in the static field gradient.
Short T2 components (below 3 ms in carbonates, 33 ms in sandstones) represent bound water; long T2 components represent moveable fluids.
The CPMG sequence counteracts magnetic field inhomogeneity, making it practical in the irregular field environments of downhole NMR tools.
Echo spacing (TE) must be short enough — typically 0.2 to 1.2 ms in wireline tools — to capture all T2 components before diffusion effects dominate.

How the CPMG Sequence Works

The CPMG measurement begins with a wait time (TW) that allows hydrogen protons in pore fluids to align with the static magnetic field. A 90-degree radio-frequency pulse then tips the net magnetisation into the plane perpendicular to the static field, where protons begin precessing together. Field inhomogeneities quickly cause the protons to precess at slightly different rates, dephasing the signal within microseconds. Without correction, this dephasing would make the measurement useless in the non-uniform fields of a wireline or LWD tool.

The CPMG innovation, building on Carr and Purcell's original 1954 work and the Meiboom-Gill phase correction of 1958, applies a train of 180-degree pulses at regular intervals equal to twice the echo spacing. Each 180-degree pulse reverses the sense of precession, causing the protons to refocus at a predictable time and produce a spin echo — a measurable burst of signal. The process repeats hundreds or thousands of times. Echo amplitude decays from one echo to the next because molecular relaxation — surface relaxation at pore walls, bulk relaxation in the fluid body, and diffusion through internal field gradients — irreversibly destroys coherence. The rate of decay encodes information about pore geometry and fluid properties.

CPMG Application Across International Jurisdictions

In Canada, NMR logging using CPMG sequences is applied widely across WCSB wells for Montney and Duvernay siltstone evaluation where conventional density-neutron crossplots cannot distinguish bound from free water in complex clay-mineral assemblages. AER Directive 045 requires wireline log submission; NMR logs are submitted as specialty logs and used in pool establishment applications under AER Directive 065 to support porosity and irreducible water saturation parameters in dynamic reservoir models. CMR and MR Scanner tools run by SLB and equivalent tools from Halliburton and Baker Hughes are standard on deep Montney evaluation programmes.

In the United States, CPMG-based NMR logging is routine in Gulf of Mexico deepwater turbidite evaluations where complex laminated sands require T2 distributions to separate productive from tight laminae that resistivity logs cannot resolve at standard vertical resolution. BSEE wireline log requirements for OCS appraisals specify log types; NMR is listed as an optional but recommended tool for complex lithology. In Norway, Sodir's NCS well data requirements accept NMR logs; Equinor's Troll and Johan Sverdrup field evaluations have used CPMG-based porosity measurements to calibrate core-log relationships in heterogeneous Jurassic sandstones where variable clay distribution affects conventional log response. NORSOK D-010 well integrity requirements indirectly drive NMR use by requiring accurate fluid-contact identification for barrier placement. In Australia, NOPSEMA-regulated Carnarvon Basin wells use NMR logging to characterise Triassic Mungaroo Formation gas reservoirs where high irreducible water saturation in fine-grained sandstones would otherwise generate pessimistic water saturation calculations. In the Middle East, Saudi Aramco's Arab Formation carbonate reservoir evaluations at Ghawar use NMR logs to identify microporosity-dominated tight zones from productive vuggy and interparticle porosity, a distinction that resistivity-based methods cannot make reliably in zero-salinity connate water environments.

Fast Facts

Modern LWD NMR tools can acquire CPMG data while drilling at rates of advance up to 30 m/hr (100 ft/hr), providing real-time T2 distributions that inform geosteering decisions in horizontal Montney and Duvernay wells. The signal-to-noise ratio for LWD NMR is lower than wireline because the tool moves during acquisition, but echo stacking over multiple CPMG trains compensates — giving actionable porosity and bound-water data within the same bit run that delivers the reservoir section.

T2 Distribution Interpretation

The raw CPMG echo train is inverted into a T2 distribution — a spectrum showing the amplitude of relaxation at each T2 time. Peaks at different T2 times correspond to different pore populations. In water-wet sandstones, T2 scales with pore size through the surface relaxivity parameter (rho): small pores relax fast, large pores relax slowly. The cutoff T2 separating bound from free water is empirically calibrated against core capillary pressure data — typically 33 ms in sandstones and 92 ms in carbonates, though these values vary by formation.

Permeability estimation from the T2 distribution uses either the Coates-Timur model (relating free-fluid index and bound-fluid ratio) or the SDR model (relating mean T2 and porosity). Both require calibration against core permeability measurements to be reliable in a specific formation, and both are sensitive to the T2 cutoff choice. In gas reservoirs, hydrogen index correction is required because gas has a lower proton density than water, causing NMR to underestimate gas-filled porosity if the raw echo train is used without fluid-property adjustment.

Tip: When running NMR logs in wells with oil-based mud (OBM), the OBM filtrate invades the formation and its T2 signal overlaps with formation hydrocarbons in the intermediate T2 range (10 to 100 ms). Differentiate OBM filtrate from formation oil using the dual-TW or dual-TE acquisition method, which exploits the difference in diffusivity between OBM filtrate and heavier formation crudes. Without this correction, apparent oil saturation from NMR will include filtrate and overestimate moveable oil volume.

CPMG is also known as:

Carr-Purcell-Meiboom-Gill sequence — the full name honouring the four physicists who developed the pulse sequence; used in academic NMR literature and tool physics papers
Spin-echo train — the operational description of what the CPMG sequence produces; used in log analysis and acquisition parameter discussions
T2 measurement — the common shorthand in petrophysics referring to the transverse relaxation time acquired via CPMG; used in log headers and formation evaluation reports

Frequently Asked Questions

What does CPMG measure in oil and gas?

CPMG measures transverse nuclear magnetic relaxation of hydrogen protons in pore fluids. The decay rate of the spin-echo train encodes pore size distribution, fluid type, and fluid volume. Petrophysicists use the resulting T2 distribution to calculate total porosity, bound-water volume, free-fluid index, and permeability — parameters that are inaccessible or unreliable from conventional density, neutron, and resistivity logs in complex lithologies.

Why are 180-degree pulses used in CPMG?

The 180-degree refocusing pulses counteract magnetic field inhomogeneity that would otherwise cause rapid, irreversible dephasing within microseconds of the initial 90-degree excitation. By reversing the precession direction, each 180-degree pulse forces the protons to refocus and produce a measurable echo. Without refocusing, NMR measurement in the inhomogeneous fields of a downhole tool would be impossible. The Meiboom-Gill phase modification of the original Carr-Purcell sequence corrects for cumulative phase errors that would otherwise degrade echoes with each successive 180-degree pulse.

What is the echo spacing in CPMG and why does it matter?

Echo spacing (TE) is the time between successive 180-degree pulses and the time at which each echo is measured. Short TE (0.2 to 0.6 ms) is critical for capturing fast-relaxing bound-water components in small pores, which would decay below noise before the first echo at longer TE values. Short TE also reduces diffusion-induced T2 shortening in gradient fields. The tradeoff is signal-to-noise ratio — shorter TE increases electrical noise per echo, requiring more echo stacking to achieve acceptable data quality.

Why CPMG Matters in Oil and Gas

The CPMG pulse sequence transformed NMR from a laboratory technique into a practical downhole measurement that now runs on millions of wells worldwide. Its ability to directly measure pore-fluid hydrogen — independent of lithology mineralogy and clay conductivity effects that compromise resistivity and density-neutron logs — makes it the only logging measurement that provides direct porosity, bound-water, and permeability information in a single pass. In tight-rock plays like the Montney, Duvernay, and Permian Basin Wolfcamp where conventional log-based porosity models routinely underestimate or misclassify pore fluids, CPMG-based NMR is the diagnostic measurement that separates commercial from sub-commercial reservoir intervals before perforation decisions are made.

CPMG: Definition, NMR Pulse Sequence, and Petrophysical Applications