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Gas Condensate Banking Effects

Gas Condensate Banking Effects

Gas condensate reservoirs have been classified between volatile oil and wet gas reservoirs. It means that the reservoir temperature is between the critical temperature and the cricondentherm (maximum temperature at which gas-liquid phases can coexist). Gas condensate reservoirs exhibit a complex behavior due to the existence of a two-fluid system (it is a single-phase fluid at original reservoir conditions) composed of reservoir gas and liquid condensate. When the pressure of the reservoir falls below dew point due to production, the original single-phase (gas phase) literally disappears because of the formation of condensates (liquid phase). The behaviours of such systems are complex and still not fully understood, especially in the near-wellbore region, where the largest pressure drops occur. It is important to mention that two kinds of gas condensate reservoirs exist: rich gas condensate reservoirs (e.g. Alen field – Equatorial Guinea) and lean gas condensate reservoirs (e.g. Arun field – Indonesia, Camisea field – Peru).

Gas Condensate Blockage

Condensate banking formation is a major problem when producing gas condensate fields. From the first day a gas condensate field is being produced, heavy components (valuable components) in the reservoir condense near the wellbore and continue growing over time. These condensate liquids are formed because the reservoir pressure falls below dew point (point where the first drop of liquid appears), and reduce the productivity over time. Productivity losses of around 50% (or even more) have been registered. Taking for example the case of the Arun field in Indonesia, where after 10 years of production a significant loss in well productivity occurred.

In technical literature, many authors proposed the existence of flow regions (from 2 to 4). Beyond the discussion of the existence of 2, 3 or even 4 flow regions in the reservoir, in this article we will focus only in the near wellbore region, where the principal phenomena occur due to condensate banking. Generally speaking there are two main factors that affect well deliverability when producing gas condensate reservoirs: Coupling and Forchheimer effects.

In the near wellbore region, where the gas flow rate is higher, an important effect called Forchheimer effect appears which produces higher pressure drawdown which results in major gas condensation that fills up the pore throats, and  consequently the gas relative permeability is reduced, decreasing the well deliverability. However, when condensation reaches a critical saturation, a “positive effect” occurs, which is called the coupling effect, that essentially explains the increment of the condensate relative permeability with increasing velocity and decreasing interfacial tension.

The evidence is overwhelming, it does not matter whether it is a rich or lean gas condensate reservoir, with production over time, the quantity of liquids in the near wellbore region will increase, affecting the well deliverability which is translated as a reduction in the production. Working to avoid a high pressure drawdown in retrograde gas condensate reservoirs has become an important topic today.