Hydrogen Index

Key Takeaways

• The hydrogen index of natural gas varies strongly with pressure and temperature in a manner that is critical for NMR interpretation in gas reservoirs: at very high pressures (above 7,000 to 10,000 psi) and elevated temperatures, gas becomes supercritical and its density approaches that of a light liquid, with HI rising from 0.02 to 0.05 at shallow low-pressure conditions to 0.4 to 0.7 at deepwater ultra-high-pressure conditions where a cubic centimeter of gas-phase hydrocarbons contains nearly as many hydrogen atoms as a cubic centimeter of liquid oil; the pressure and temperature dependence of gas HI follows from the real-gas equation of state (using Z-factor to relate actual gas molar volume to ideal gas molar volume) combined with the hydrogen atom density of the specific gas composition; in deepwater wells drilled through pressurized gas sands (where reservoir pressure may be 12,000 to 15,000 psi and temperature 150 to 200 degrees Celsius), the gas HI may be 0.3 to 0.5, causing the NMR to underestimate gas porosity by only 50 to 70 percent rather than the 90 to 95 percent underestimate that would occur for the same gas at surface conditions, making the NMR porosity more useful as a gas indicator tool in deepwater reservoirs than in shallow wells.
• The gas effect on NMR porosity is used as a qualitative gas detection indicator: when NMR-derived porosity (which reflects only the hydrogen-bearing pore fluids, weighted by their HI) is compared to density-derived porosity (which reflects all pore fluids plus the matrix and organic carbon, weighted by their electron density) and neutron-derived porosity (which reflects all hydrogen-bearing materials including clay water, structural water, and pore fluids), the presence of free gas creates a characteristic crossplot response where NMR porosity is lower than density porosity (because gas has lower HI than the water assumed in the density porosity calibration), and density porosity is lower than neutron porosity (the classic gas crossover of the density-neutron crossplot, because gas has lower electron density than water causing density to over-read porosity, and gas has lower hydrogen density than water causing neutron to under-read porosity, creating the crossover); the three-porosity comparison (NMR versus density versus neutron) is more diagnostic of gas than the two-porosity gas crossover alone, and has been applied in deepwater exploration to confirm gas saturation in reservoirs where resistivity-based gas identification is ambiguous due to high-salinity formation water masking the resistivity contrast of the gas.
• Bitumen and heavy oil hydrogen index effects are the opposite of gas effects: heavy crude oils with API gravity below 20 degrees have hydrogen index values of 0.90 to 0.98 at reservoir conditions, close to but slightly below water HI, which means the NMR slightly underestimates total porosity in heavy oil reservoirs but the error is small compared to the gas HI effect; however, bitumen (the solid to very viscous organic material in oil sands and heavy oil deposits) has a hydrogen index near 1.0 but an extremely short T2 relaxation time (below the instrument dead time of 0.2 to 0.5 milliseconds), meaning that the bitumen hydrogen is present and polarized but relaxes so quickly that it cannot be detected by the NMR tool; the result is that NMR porosity in bitumen-bearing sands underestimates total porosity by the fraction of the pore space occupied by bitumen, underestimates producible fluid porosity because the bitumen pore space is not producible without thermal stimulation, and accurately represents the mobile fluid porosity (water plus free oil) that is producible by primary or cold production methods; recognizing the bitumen dead-time effect versus the gas HI effect versus the reduced-HI light hydrocarbon effect is one of the key interpretation challenges in NMR log analysis of oil sands, heavy oil, and gas reservoirs.
• NMR tool calibration to hydrogen index uses pure water as the primary reference standard, defining the NMR response per unit volume of 100 percent water-saturated porosity as the baseline against which all other measurements are referenced: before logging, the NMR tool is calibrated in a water-filled test jig or in a downhole calibration mode that measures the NMR response of the borehole fluid (assumed to be fresh or saltwater of known HI) to verify that the tool gain is set correctly; the calibration converts the raw NMR magnetization amplitude to porosity units by dividing by the calibration amplitude per unit porosity, under the assumption that all pore fluids have HI = 1 (water); if the actual pore fluids have HI less than 1, the NMR will read apparent porosity below the true porosity by the factor (1 - volume fraction of non-water fluid times (1 - HI of that fluid)), requiring a hydrogen index correction to the NMR porosity before it is used in reservoir evaluation; the hydrogen index correction for gas or oil requires independent knowledge of the HI (from fluid samples, PVT analysis, or formation temperature and pressure) and the saturation (from resistivity or NMR-derived saturation), making HI-corrected NMR porosity most accurate when all of these inputs are well constrained from calibration to core and fluid data.
• Source rock hydrogen index in pyrolysis geochemistry (Rock-Eval analysis) uses a completely different definition of hydrogen index than NMR logging: in Rock-Eval pyrolysis, the hydrogen index (HI) is defined as the milligrams of hydrocarbons generated per gram of total organic carbon (TOC) during programmed heating to 550 degrees Celsius (S2 yield divided by TOC, multiplied by 100 to give mg HC / g TOC), quantifying the hydrogen richness of the organic matter and therefore its potential to generate oil and gas during natural burial and maturation; a source rock with HI above 600 mg HC / g TOC contains predominantly oil-prone type I or type II kerogen, while HI below 200 mg HC / g TOC indicates gas-prone type III kerogen derived from terrestrial plant material; the Rock-Eval HI decreases with increasing thermal maturity as the organic hydrogen is progressively converted to hydrocarbons and expelled, making HI versus Tmax crossplots (the van Krevelen diagram in geochemical form) the standard method for classifying kerogen type and maturity in source rock evaluation; this geochemical HI has no mathematical relationship to the NMR HI but is unfortunately also called "hydrogen index" in the petroleum literature, requiring context to determine which definition is intended.