Condensate Settings

settings reference for the dynamic drainage volume (ddv) model on gas condensate wells every field on the condensate ddv settings input is documented here defaults are tuned to work across a wide range of wells — most wells never need any of these changed, but understanding them helps you diagnose an average reservoir pressure result that looks wrong what this model does the ddv model uses each well's daily rates and pressures to answer two questions how much reservoir volume is this well actually draining , and how has average reservoir pressure declined over time? it does this by matching the well's flowing behavior — fitting the relationship between production and pressure decline, then solving for the drainage volume and pressure history that best explain the observed data the outputs (connected volume, average reservoir pressure over time, remaining pressure support) feed the pi based forecast and downstream optimization the condensate variant combines behaviors of the gas and oil variants multiphase downhole rates matter (as for gas wells), while the core trend is fitted on the pressure normalized rate with condensate specific tuning reservoir pressure initial reservoir pressure tolerance ( initialreservoirpressuretolerance , default 0 05) — how far the model may move initial reservoir pressure away from your configured value while matching history, as a decimal fraction (0 05 = 5%) within the tolerance, the solver will trade a small pressure shift for a better overall match reservoir pressure relative to the dew point drives everything in a condensate system, so this anchor matters more here than for dry gas example your initial pressure comes from a recent buildup and you trust it — tighten to 0 01 or 0 02 if initial pressure is a rough regional estimate, the default or wider lets the data speak reservoir pressure fit settings ( reservoirpressurefitsettings ) — starting guess and allowed range (min / base / max for magnitude, early decline, and curvature, plus a hyperbolic to exponential switch) for the fitted average reservoir pressure trend all fields default to 0, which means unset the model picks its own starting point from the data only set these when the automatic pressure trend converges somewhere unphysical relative to offsets or surveillance fluid handling ignore gas in downhole rate ( perrineignoregas , default off) — the match works on total downhole hydrocarbon withdrawal, which normally includes the gas phase turning this on removes gas from that calculation entirely rarely correct for a condensate well; it exists for diagnostic runs where you suspect the gas contribution is distorting the material balance ignore gas when undersaturated ( perrineignoregasundersaturated , default off) — the conditional version gas is excluded from the downhole rate only on days when reservoir pressure is above the saturation point, where free gas should not exist in the reservoir the more physically defensible switch when gas breaking out in the wellbore, rather than the reservoir, is inflating the apparent withdrawal early in the well's life use constant compressibility ( useconstantcompressibility , default on) — with the default, total system compressibility is evaluated once at initial pressure and held constant through the match turned off, compressibility is re evaluated daily from the fluid properties as pressure declines constant compressibility is more stable and accurate enough for modest depletion; for a condensate well that has depleted through the dew point, where fluid behavior changes sharply, daily re evaluation is worth the extra run time saturation bounds water saturation min / max ( watersaturationmin / watersaturationmax , defaults 0 1 / 0 9) — the range the solver may consider for water saturation when resolving the drainage volume deliberately wide by default, excluding only the non physical extremes; narrow it when petrophysics constrains saturation, which removes wrong but well fitting solutions and makes volumes more repeatable well to well data quality material balance time filter threshold ( materialbalancetimefilterthreshold , default 5) — screens out days where the well's cumulative production to rate ratio (material balance time) is wildly inconsistent with how long the well has actually been producing days exceeding the threshold — typically poisoned by long shut ins, allocation errors, or bad uptime records — are excluded from the match example an intermittently operated well with a scattered, drifting match — lower to 3 to discard more suspect days if too little valid history survives the filter, raise it fit tuning pressure normalized rate fit settings ( pnrfitsettings ) — the bounds and starting guesses for the core fit of the pressure normalized rate vs material balance time trend each parameter has a min / base (starting guess) / max field what it bounds yimin / yibase / yimax magnitude of the fitted trend at time zero logdimin / logdibase / logdimax how quickly the trend changes early in the history bmin / bbase / bmax curvature of the trend over time switchpercent decline level at which the fitted trend transitions from hyperbolic to exponential behavior (0 = no forced transition) the base values are where the solver starts; the min/max are hard walls it cannot cross if a fitted parameter lands exactly on a bound, that bound is binding — widen that one wall slightly and re run rather than moving several at once caution the defaults in this group have been finely tuned for condensate behavior and differ from the oil defaults treat them as last resort levers for an individual problem well, not as field wide knobs