Moved Hydrocarbons

Key Takeaways

• The fundamental calculation of moved hydrocarbons uses the relationship BVM = (1 - Sxo) - (1 - Sw) = Sw - Sxo, where Sw is the water saturation in the undisturbed virgin reservoir zone (from deep resistivity) and Sxo is the water saturation in the flushed zone (from shallow resistivity or NMR); when Sw is less than Sxo (meaning more water in the flushed zone than in the virgin zone), the difference Sw - Sxo is positive and represents the fraction of pore volume that has had hydrocarbons displaced by invading filtrate; the Archie equation applied to the flushed zone uses Rxo (flushed zone resistivity) and Rmf (mud filtrate resistivity) in the same form as the virgin zone calculation uses Rt and Rw, and the ratio Rxo/Rt provides a useful invasion diagnostic independent of the absolute resistivity values, with high Rxo/Rt ratios (greater than 5) indicating oil-bearing formations (oil-wet rock resists aqueous filtrate) and low Rxo/Rt ratios (less than 2) suggesting gas, water, or very conductive formation water.
• Nuclear magnetic resonance (NMR) logging provides an alternative and complementary approach to moved hydrocarbon estimation that does not rely on resistivity contrasts between the filtrate and the native formation fluid, instead using the difference between the total NMR porosity (measured at a long wait time that recovers all hydrogen signal) and the bound-fluid porosity (measured at a short wait time of 12 milliseconds that captures only the clay-bound water, capillary-bound water, and small-pore water signals, omitting the bulk relaxing hydrocarbon and free water signals): the movable fluid porosity from NMR represents the volume of pore space occupied by fluids that can be displaced under reservoir conditions, providing a direct physical measurement of whether the hydrocarbon is in pore space accessible enough for flow, independent of the filtrate-native fluid conductivity contrast that resistivity-based BVM requires; in gas reservoirs, NMR-based moved hydrocarbon estimation is particularly valuable because gas has very low hydrogen index (low NMR signal per unit volume compared to oil or water) which can cause resistivity-NMR discrepancies that help identify gas-bearing intervals.
• The radial depth of investigation of the logging tool determines which saturation state is measured, with microresistivity devices (microspherically focused log, microlaterolog, proximity log) reading the flushed zone within approximately 3 to 10 centimeters of the borehole wall, medium-depth resistivity devices (shallow induction, medium laterolog) reading through the transition zone at 30 to 90 centimeters depth, and deep resistivity devices (deep induction, deep laterolog, Rxo-normalized dual induction) reading beyond the invasion front in the uncontaminated virgin formation at depths of 1 to 3 meters or more; the time of invasion (from drilling the interval to logging it) affects both the depth and the degree of flushing, with fresh zones logged within hours of drilling showing less complete flushing and smaller Rxo/Rt contrast than zones that have been invaded for days as the well is deepened; ideally, the same zone is logged early (for flushed zone resistivity before invasion deepens) and late (for virgin zone resistivity after invasion has stabilized), a practice that is sometimes implemented with LWD resistivity followed by wireline resistivity passes.
• Moved hydrocarbon interpretation for producibility uses empirical thresholds that vary by basin and fluid type: in a typical Gulf Coast sandstone oil reservoir, a BVM greater than 0.04 to 0.06 (4 to 6 percent of bulk rock volume) is considered evidence of producible hydrocarbons and supports a perforation or completion decision, while BVM less than 0.02 suggests either a non-reservoir quality interval or an interpretation problem; gas reservoirs show lower BVM values than oil reservoirs at comparable producibility because gas moves more readily (lower viscosity) through tighter pore throats than oil and the resistivity contrast between gas and filtrate water is larger than for oil and filtrate water; the producibility interpretation is most reliable when BVM is computed over a calibrated suite with consistent environmental corrections, formation water salinity known from downhole water samples or adjacent formation waters, and mud filtrate resistivity Rmf measured at surface and corrected to formation temperature; erroneous producibility conclusions arise from uncorrected borehole rugosity effects on the microresistivity curve, incorrect Rw assumptions, or mixed oil-base / water-base mud systems where the invaded zone saturation physics differs from the standard Archie model.
• The Rwa (apparent Rw) and Rmfa (apparent Rmf) overlay method is a quick-look moved hydrocarbon indicator used on the log plot before full quantitative computation, plotting the apparent formation water resistivity computed from the deep resistivity log alongside the apparent filtrate resistivity computed from the shallow resistivity log on the same depth track: where the two curves track each other (Rwa approximately equal to Rmfa), the formation is water-bearing or the same fluid fills both the flushed and virgin zones; where the deep Rwa tracks below the shallow Rmfa, the virgin zone has higher resistivity than the flushed zone, indicating that hydrocarbons in the virgin zone are resisting deep resistivity and the flushed zone has been swept to higher conductivity by aqueous filtrate, confirming moved hydrocarbon; the separation between the Rwa and Rmfa curves is qualitatively proportional to the hydrocarbon saturation difference between flushed and virgin zones, making the crossplot a powerful visual tool for quickly identifying producible pay zones on a resistivity log suite before detailed saturation computation is performed.