condensate ratio, Oil & Gas Glossary

What Is a Condensate-Gas Ratio?

Condensate-gas ratio (also called CGR, gas-condensate ratio, or condensate yield) is the volume of liquid condensate produced per unit volume of gas, expressed in barrels per million standard cubic feet (bbl/MMscf), which characterizes the richness of a gas condensate reservoir and directly determines the economic value of the gas stream beyond its heating value. CGR is measured from separator tests at surface conditions, reflects the composition of the reservoir fluid, and is a primary input to reserves classification, facility design, fiscal modeling, and development economics in any gas condensate project.

Key Takeaways

CGR classification ranges: lean gas is less than 10 bbl/MMscf; moderate condensate is 10–100 bbl/MMscf; rich condensate is 100–300 bbl/MMscf; near-critical volatile oil systems exceed 300 bbl/MMscf.
CGR declines over field life in depletion-drive reservoirs as reservoir pressure falls below the dew point and heavier components drop out into the pore space, permanently reducing the richness of the produced wellstream.
Gas cycling — reinjecting stripped lean gas to maintain reservoir pressure above the dew point — prevents CGR decline and can recover 60–80% of original condensate in place versus 25–40% under depletion.
In high-CGR fields (above 100 bbl/MMscf), condensate revenue can equal or exceed gas revenue, and the field may be classified as a condensate reservoir with associated gas rather than a gas reservoir with associated liquids — a distinction that affects royalty rates and reserves classification.
CGR is measured at separator conditions, not at reservoir conditions; the recombined wellstream CGR adjusted for reservoir temperature and pressure gives the in-situ fluid richness used in reservoir simulation.

Measuring and Interpreting Condensate-Gas Ratio

CGR is determined from a well test or extended production test during which gas and liquid volumes are measured simultaneously at separator conditions. The gas volume is corrected to standard conditions (typically 60°F and 14.73 psia in the U.S., or 15°C and 101.325 kPa in metric systems) and the condensate volume is measured in stock-tank barrels. The ratio of condensate barrels to gas MMscf gives the separator CGR. To obtain the recombined CGR representative of reservoir fluid, laboratory analyses — constant composition expansion (CCE) and constant volume depletion (CVD) tests on recombined wellstream samples at reservoir temperature — are used to characterize the full phase behavior as a function of pressure. The initial CGR from a flow test may differ from the stabilized long-term CGR because near-wellbore condensate banking, wellbore liquid loading, or separator efficiency issues can distort early measurements.

The inverse of CGR — the gas-oil ratio (GOR) expressed in Mscf/bbl or scf/bbl — is sometimes used in reservoir engineering and production accounting, particularly when a field straddles the boundary between a volatile oil system and a gas condensate system. A GOR of 5,000 scf/bbl corresponds to a CGR of 200 bbl/MMscf; a GOR of 100,000 scf/bbl corresponds to 10 bbl/MMscf. Fields with GOR above 100,000 scf/bbl are generally classified as lean gas condensate; fields below 3,300 scf/bbl (CGR above 300 bbl/MMscf) are classified as volatile oil or near-critical systems. The boundary is important because different reservoir engineering methods, fiscal regimes, and surface facility designs apply to each classification.

CGR varies spatially across a field because gas condensate reservoirs often exhibit vertical and lateral compositional gradients: deeper, hotter zones tend to be richer than shallower cooler zones due to gravity segregation of heavier hydrocarbon molecules over geologic time. In stacked pay formations, individual zones may have CGRs differing by a factor of two or three, so commingled production CGR represents a volume-weighted average of all contributing zones. Reservoir simulation models must capture these compositional gradients to accurately forecast total liquid production and the rate of CGR decline over field life.

Fast Facts: Condensate-Gas Ratio

Lean gas: Less than 10 bbl/MMscf; condensate revenue is a minor supplement to gas sales
Moderate condensate: 10–100 bbl/MMscf; condensate typically contributes 10%–25% of field revenue
Rich condensate: 100–300 bbl/MMscf; condensate revenue rivals or exceeds gas revenue
Near-critical / volatile oil: Greater than 300 bbl/MMscf; often classified as oil with associated gas for fiscal purposes
North Field (Qatar) CGR: Approximately 40–60 bbl/MMscf; generates over 800,000 bbl/day of condensate at peak production
CGR decline under depletion: Typically 20%–50% decline over field life as retrograde dropout reduces the C5+ content of the produced wellstream
Units: bbl/MMscf (U.S.), bbl/MMscfd, or STB/MMscf; European and international usage may express as m³/MMm³ or cm³/m³
Royalty implication: High-CGR fields classified as condensate reservoirs may attract lower royalty rates than crude oil fields in some jurisdictions, as condensate is considered a gas byproduct

Reservoir Engineering Tip:

Track CGR on a monthly basis throughout the producing life of any gas condensate well and plot it against cumulative gas production. A declining CGR curve that tracks the CVD depletion prediction confirms the reservoir is behaving as modeled. A CGR that declines faster than predicted may indicate near-wellbore condensate banking; a CGR that holds steady despite pressure decline below the dew point suggests water influx is maintaining partial pressure support. Early CGR trends are your most sensitive indicator of reservoir drive mechanism and near-wellbore damage in a condensate field.

Condensate-gas ratio is also referred to as:

CGR — the universal abbreviation used in reservoir engineering reports, well tests, and fiscal filings.
Gas-condensate ratio (GCR) — the inverse expression (MMscf/bbl or Mscf/bbl), less common but used in some production accounting and regulatory filings.
Condensate yield — used in surface facilities and gas processing contexts to describe how many barrels of condensate are recovered per MMscf of gas processed through the separator or gas plant.
Liquid-gas ratio (LGR) — a broader term that includes all liquid hydrocarbons (condensate plus heavier NGL fractions) recovered per unit volume of gas, used in gas plant design and NGL extraction studies.

Frequently Asked Questions About Condensate-Gas Ratios

Why does CGR decline as a gas condensate field depletes?

As reservoir pressure falls below the dew-point pressure during production, heavier hydrocarbon molecules (C5+) begin to condense from the gas phase and accumulate as a stationary liquid in the pore space. This liquid cannot flow at low saturations (below the critical condensate saturation, typically 10–25% pore volume) and is therefore lost to production. The gas remaining in the reservoir becomes progressively leaner — depleted in C5+ — so the produced wellstream has a lower CGR over time. This retrograde process is essentially irreversible without pressure maintenance. The CVD laboratory test mimics this process and predicts the magnitude of CGR decline as a function of pressure drop.

How does CGR affect reserves classification?

In the U.S. SEC and SPE-PRMS reserves frameworks, a field with a CGR above approximately 300 bbl/MMscf (GOR below about 3,300 scf/bbl) is typically classified as a volatile oil or condensate reservoir rather than a gas reservoir. This affects how reserves are reported: condensate volumes are booked as oil (liquids) reserves and gas volumes are classified as associated gas, rather than the reverse. The distinction matters because oil reserves attract different royalty rates in many jurisdictions and oil-equivalent production volumes affect company metrics differently than gas-equivalent volumes. Some operators in high-CGR fields prefer the condensate classification because condensate royalty rates are sometimes lower than crude oil royalty rates.

Can CGR be improved once it starts declining?

CGR decline caused by retrograde dropout in the reservoir is generally irreversible — once condensate has dropped out of the gas phase into the pore space below its critical saturation, it cannot be produced by conventional gas production. However, several techniques can slow decline or partially recover dropped-out condensate. Gas cycling maintains pressure above the dew point to prevent further dropout and vaporizes some condensate already in the reservoir. Injection of lean gas, nitrogen, or solvent can strip some condensate from the pore space through a vaporization process, though recovery efficiency depends strongly on reservoir heterogeneity. Hydraulic fracturing can bypass near-wellbore condensate banks and connect the well to undamaged reservoir, improving CGR near the wellbore even if reservoir CGR continues to decline.

Why Condensate-Gas Ratio Matters in Oil and Gas

CGR is one of the most commercially significant parameters in gas field development because it determines what fraction of the gas stream has oil-equivalent value above and beyond its heating value. In fields like Qatar's North Field, Shah Deniz in Azerbaijan, and the Carnarvon Basin in Australia, condensate revenue from high-CGR wellstreams has funded billions of dollars of LNG infrastructure and underpinned national energy strategies. A production engineer who understands CGR decline and can design a pressure-maintenance strategy to slow it will generate substantially more value over a field's life than one who simply allows depletion to proceed unchecked. For commercial professionals, accurate CGR forecasting is essential to revenue modeling, offtake agreement pricing, and any fiscal analysis that separates gas and liquids revenue streams for royalty and tax calculations.

Condensate-Gas Ratio: Measuring Reservoir Richness in Gas Fields