Condensate Banking

Condensate Banking

• Condensate precipitates from gas as changes in the pressure and temperature of the gas stream drive the phase behavior past the Dew Point.

• The extra liquid phase in the pores near the wellbore reduces relative permeability to gas.

• Condensing of liquids during production is very common in the choke or tubing; this creates problems in liquid loading and lift.

• When condensation occurs in the formation, the effect is first seen in the pores nearest the wellbore.

• The damage produced by condensate in the pores is a type of skin damage. Skins from condensates are on the order of 1 to over 20.

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Estimation of the DP Onset

• PVT tests done on a representative bottom hole sample of the gas can predict the phase envelope and the onset of Dew Point

• Changes in temperature and pressure influence the condensate precipitation.

• Rich gas is more likely to have a higher Dew Point than lean gas.


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Phase Related Permeability Reduction CONDENSATE BANKING GAS BREAKOUT

MECHANISM As near wellbore pressure is reduced during production, Dew Point pressure of gas is reached. Dropout of liquid hydrocarbons in near wellbore zone reduces relative permeability to gas. Once formed, condensate banking will itself cause additional pressure drop, and be self aggravating. OCCURRENCE Usually only a problem in gas reservoirs with significant condensate yield (rich gas), and relatively high dew point pressure. Fluid sampling problems (contamination) make DP harder to predict. IMPACT Possibly serious, but poorly understood. Skins to over 20. PREVENTION/REMOVAL

Maintain reservoir pressure through pressure support. May be

possible to periodically flush the near-wellbore zone with dry gas or solvent. High flow capacity fractures open more flow area that negates damage.

MECHANISM

Near wellbore increase in gas saturation may have two causes (see

above)

OCCURRENCE

Easy to predict/diagnose, but sometimes difficult to quantify.

IMPACT

Potentially severe.

PREVENTION/REMOVAL

Maintain reservoir pressure through pressure support. Minimise

production drawdown to prevent early problems caused by

localized (near wellbore) drawdown.

Zone of condensate dropout

Dewpoint pressure

Reservoir pressure

Distance

Pre

ssu

re

Gas

Gas Gas

Gas Oil bubble point pressure

Reservoir pressure

Distance

Pre

ssu

re

Increased near-wellbore gas-saturation

1

2 Downward Coning of pre-existing gas-cap


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Impact of Formation Damage on Relative Permeability

a condensatebank only formsafter depletion

dew point

depletion

decreasingreservoir pressure

initial reservoirpressure

D i s t a n c e

formationdamage causesdew point to bereached earlier -condensate bankforms earlier.

dew point

depletion

formation damage(e.g. scale)

D i s t a n c e

Any factor that causes higher drawdown to be applied at the formation/wellbore interface may create a pressure low enough to cross into the two-phase region. 8/25/2015 5

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Condensate Breakout - Self Aggravation

Light hydrocarbons

condense first in the

tubulars and then

near the wellbore the relative

permeability to gas

increases

the skin increases

and gas productivity

falls

Bottomhole

pressure is reduced

– either in the

whole reservoir or

near the wellbore


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Treatments

• Re-perforating:

– Short-term improvement provided the current shot density is less than about 8 shots per foot at less than 60 degree phasing.

– Need longer perforating depths to be noticed.

– Although new perforations may improve inflow where damage is present, the amount of skin damage reduction is often small and the improvement is short lived.

– Perforation length is a factor – longer perfs simulate a larger reservoir, but will not prevent the problem.


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Treatments

• Dry Methane Gas Injection

– Dry gas injection (condensate revaporization) has been explored by Amoco (SPE 1813- March 1969, JPT) and others (CIM:1967, AIME 1948, SPE 68170, etc.) for over 50 years.

– The process will work, but usually requires cycling of wells and investment in compressors and high pressure gas injection.


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Treatments

• Gas Cycling:

– Gas cycling can be effective, but requires a different operating procedure and commitment (O’Dell, et.al., JPT, 1967). The quantity of gas needed depends on the heaviest retrograde component. The speed of revaporization can also be affected by the composition of the dry gas.


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Treatments

• Nitrogen Injection:

– Amoco tried nitrogen injection into wells in the Anschutz Ranch field in the 1980’s to drive condensate back. The effect was small and very short lived. Large scale, field-wide pressurization with Nitrogen was successful. Several efforts have been pushed forward on this front and Nitrogen and dry gas injection has been compared (SPE22360).


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Treatments

• Solvent Injection:

– Amoco experimented with methanol and other short-chained alcohol injection in the Anschutz Ranch field and some other fields with retrograde behavior in the 1990’s to try to resolubilize the condensate. Although skins were often cut by 30 to 50%, the damage was never removed. The effects of the treatments did not last more than a few weeks. (See also SPE 62935)


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Treatments

• Increasing Reservoir Contact: – Increasing reservoir contact is probably the best way to

offset condensate precipitation effects on permeability.

– Both horizontal wells (SPE 54351) and hydraulic fracturing (are viable solutions to the problem.

– Hydraulic fracturing was successfully done in many cases world wide by Amoco, to offset the skin damage caused by retrograde condensate.

– Neither horizontals nor fractures will prevent condensate drop out. The purpose is simply to offer more flow area and reduce the effect of the skin damage in radial flow.


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Treatment

• Methanol plus dry gas:

– Anschutz Ranch field (12,000 ft, 260F, 2000 bbl condensate per 1mmscf gas) in the mid/late 1980's. Treated pay with about 10 drums (500+ gallons) of a product that was roughly 80% methanol, 17% xylene plus some surfactants and long chain alcohols. Damage was near the wellbore. The treatment returned a good increase in gas production, but the clean-out effect was limited to about 10 days before the condensate again precipitated.


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Condensate Banking

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