Changes

Two important tests can be performed in the laboratory to simulate and quantify condensate production. Constant Composition Expansion (CCE) and Constant Volume Depletion (CVD) tests. The data obtained from these two tests can aid in determining the PVT properties of the fluid, which consequently supports optimum reservoir engineering decisions, and well performance for the field.<ref name=Whitsonetal_1999> Whitson, C. H., Fevang, Ø., & Yang, T. (1999). Gas Condensate PVT-What's Really Important and Why? IBC Conference. London: IBC UK Conferences Ltd.</ref>   

Two important tests can be performed in the laboratory to simulate and quantify condensate production. Constant Composition Expansion (CCE) and Constant Volume Depletion (CVD) tests. The data obtained from these two tests can aid in determining the PVT properties of the fluid, which consequently supports optimum reservoir engineering decisions, and well performance for the field.<ref name=Whitsonetal_1999> Whitson, C. H., Fevang, Ø., & Yang, T. (1999). Gas Condensate PVT-What's Really Important and Why? IBC Conference. London: IBC UK Conferences Ltd.</ref>   

===Constant composition expansion (CCE)===

===Constant composition expansion (CCE)===

The CCE test entails lowering the pressure in a chamber that contains a sample of reservoir fluid, by increasing the volume of the chamber. The initial pressure of the reservoir fluid is the reservoir pressure and temperature. Pressure is decreased until the first drop of liquid is observed. The pressure where the first drop of liquid is observed, is the dew point pressure. No composition changes occur in this experiment. CCE aids in measuring the Z-factors, oil relative volume below dew point or what is known as the liquid dropout curve, and the dew point pressure.<ref name=Whitsonetal_1999 />  An illustration of the CCE test is shown in [[:file:AlAhmadiTawfiqFigure2.jpg|Figure 2]].  

The CCE test entails lowering the pressure in a chamber that contains a sample of reservoir fluid, by increasing the volume of the chamber. The initial pressure of the reservoir fluid is the reservoir pressure and temperature. Pressure is decreased until the first drop of liquid is observed. The pressure where the first drop of liquid is observed, is the dew point pressure. No composition changes occur in this experiment. CCE aids in measuring the Z-factors, oil relative volume below dew point or what is known as the liquid dropout curve, and the dew point pressure.<ref name=Whitsonetal_1999 />  An illustration of the CCE test is shown in [[:file:AlAhmadiTawfiqFigure2.jpg|Figure 2]].  

 

[[file:AlAhmadiTawfiqFigure2.jpg|center|framed|{{figure number|2}}Constant composition expansion (CCE) test experimental setup.<ref name=Panjaetal_2020>Panja, P., Velasco, R., & Deo, M. (2020). Understanding and Modeling of Gas-Condensate Flow in Porous Media. Advances in Geo-Energy Research, 173-186.</ref>]]

[[file:AlAhmadiTawfiqFigure3.jpg|thumb|300px|{{figure number|3}}Constant volume depletion (CVD) test experimental setup.<ref name=Panjaetal_2020 />]]

===Constant volume depletion (CVD)===

===Constant volume depletion (CVD)===

The CVD test simulates pressure depletion in a gas condensate reservoir. The CVD test entails decreasing the pressure, in increments, below the dew point by increasing the volume of the chamber. At each pressure increment, the gas that is produced as a consequence of pressure depletion, is released from the top of the chamber. The chamber volume remains constant at the end of each step. In essence this is simulating the exact conditions in an actual reservoir. The volume of the effluent gas is measured, as well as its composition and Z-factor. The remaining fluid in the chamber is also measured. The CVD test, as opposed to the CCE test, involves a change in composition. The measurements from the CVD test are necessary to estimate condensate recovery.<ref name=Whitsonetal_1999 />.  An illustration of a typical CVD experiment is shown in [[:file:AlAhmadiTawfiqFigure3.jpg|Figure 3]].  

The CVD test simulates pressure depletion in a gas condensate reservoir. The CVD test entails decreasing the pressure, in increments, below the dew point by increasing the volume of the chamber. At each pressure increment, the gas that is produced as a consequence of pressure depletion, is released from the top of the chamber. The chamber volume remains constant at the end of each step. In essence this is simulating the exact conditions in an actual reservoir. The volume of the effluent gas is measured, as well as its composition and Z-factor. The remaining fluid in the chamber is also measured. The CVD test, as opposed to the CCE test, involves a change in composition. The measurements from the CVD test are necessary to estimate condensate recovery.<ref name=Whitsonetal_1999 />.  An illustration of a typical CVD experiment is shown in [[:file:AlAhmadiTawfiqFigure3.jpg|Figure 3]].  

==Condensate banking==

==Condensate banking==

The effect of condensate banking on productivity is dependent on multiple factors, including the petrophysical properties of the rock as well as the properties of the fluid and the effect of different forces acting upon the rock and fluid. Once condensate starts to form, it will preferentially start to migrate into small pores due to capillary forces. This initial formation of condensate does not affect productivity significantly as the condensate occupies the smaller pores and thus frees the larger pathways for gas to flow freely into the wellbore. With time and as condensate production increases with pressure depletion, the condensate occupies larger pores, significantly reducing the ability of gas to flow, and hence reducing the productivity of the well.<ref name=Hinchmanandbaree_1985>Hinchman, S. B., & Baree, R. D. (1985). Productivity Loss in Gas Condensate Reservoirs. 60th Annual Technical Conference and Exhibition of the Society of Petroleum Engineers . Las Vegas: SPE 14203.</ref> As mentioned, the concentration of liquid and hence the productivity is dependent on the petrophysical properties of the rock. In lower permeability and lower porosity reservoirs, condensate banking effect is more significant due to the shortage of well-connected and large pores, where condensate will most likely dominate the pore space and thus reduce productivity.  

The effect of condensate banking on productivity is dependent on multiple factors, including the petrophysical properties of the rock as well as the properties of the fluid and the effect of different forces acting upon the rock and fluid. Once condensate starts to form, it will preferentially start to migrate into small pores due to capillary forces. This initial formation of condensate does not affect productivity significantly as the condensate occupies the smaller pores and thus frees the larger pathways for gas to flow freely into the wellbore. With time and as condensate production increases with pressure depletion, the condensate occupies larger pores, significantly reducing the ability of gas to flow, and hence reducing the productivity of the well.<ref name=Hinchmanandbaree_1985>Hinchman, S. B., & Baree, R. D. (1985). Productivity Loss in Gas Condensate Reservoirs. 60th Annual Technical Conference and Exhibition of the Society of Petroleum Engineers . Las Vegas: SPE 14203.</ref> As mentioned, the concentration of liquid and hence the productivity is dependent on the petrophysical properties of the rock. In lower permeability and lower porosity reservoirs, condensate banking effect is more significant due to the shortage of well-connected and large pores, where condensate will most likely dominate the pore space and thus reduce productivity.  

==Condensate banking profile near the wellbore vicinity==

==Condensate banking profile near the wellbore vicinity==

With the effect of condensate banking, a two-phase region is created, where gas and liquid exist. This causes different condensate mobility zones to exist in the near-wellbore region. [[:file:AlAhmadiTawfiqFigure4.jpg|Figure 4]] demonstrates this phenomena, where three zones exist.   

With the effect of condensate banking, a two-phase region is created, where gas and liquid exist. This causes different condensate mobility zones to exist in the near-wellbore region. [[:file:AlAhmadiTawfiqFigure4.jpg|Figure 4]] demonstrates this phenomena, where three zones exist.   

* Near Wellbore Zone: (Zone 1) Finally, closer to the wellbore, both phases (condensate and gas) exist and gas will continue to produce, while condensate is considered to have low mobility. Condensate will only start to produce when the liquid saturation reaches the critical condensate saturation.<ref name=Shi_2009 /> <ref name=Daungkaewandgringarten_2004 />  

* Near Wellbore Zone: (Zone 1) Finally, closer to the wellbore, both phases (condensate and gas) exist and gas will continue to produce, while condensate is considered to have low mobility. Condensate will only start to produce when the liquid saturation reaches the critical condensate saturation.<ref name=Shi_2009 /> <ref name=Daungkaewandgringarten_2004 />  

[[file:AlAhmadiTawfiqFigure5.jpg|thumb|300px|{{figure number|5}}Condensate saturation versus radial distance from wellbore, with velocity stripping zone.<ref name=Daungkaewandgringarten_2004 />]]

file:AlAhmadiTawfiqFigure4.jpg|{{figure number|4}}Condensate saturation versus radial distance from wellbore, with different condensate mobility zones.<ref name=Daungkaewandgringarten_2004>Daungkaew, S., & Gringarten, A. (2004). The Effect of Capillary Number on a Condensate Blockage in Gas Condensate Reservoirs . Walailak Journal Science and Technology, 91-116.</ref>

file:AlAhmadiTawfiqFigure5.jpg|{{figure number|5}}Condensate saturation versus radial distance from wellbore, with velocity stripping zone.<ref name=Daungkaewandgringarten_2004 />

Increased gas mobility is observed in the near wellbore region mainly due the compositional changes occurring. As the heavier components increase, this increases the viscosity of the liquid, whereas the gas becomes less viscous. This increases the relative mobility of the gas with respect to the liquid condensate. This increase in gas mobility is observed at higher velocities, and thus is termed the velocity stripping effect, which can increase the productivity of a well. This can further be demonstrated in [[:file:AlAhmadiTawfiqFigure5.jpg|Figure 5]].<ref name=Daungkaewandgringarten_2004 />

Increased gas mobility is observed in the near wellbore region mainly due the compositional changes occurring. As the heavier components increase, this increases the viscosity of the liquid, whereas the gas becomes less viscous. This increases the relative mobility of the gas with respect to the liquid condensate. This increase in gas mobility is observed at higher velocities, and thus is termed the velocity stripping effect, which can increase the productivity of a well. This can further be demonstrated in [[:file:AlAhmadiTawfiqFigure5.jpg|Figure 5]].<ref name=Daungkaewandgringarten_2004 />

Another effect is also present at high velocities, which acts against the velocity stripping effect. This effect is termed the Inertial (non-Darcy) flow effects, which, at high velocities, reduces effective gas permeability and leads to lower well productivity. On the other hand, velocity stripping increases the relative permeability. However, it has been observed in most gas-condensate wells that relative permeability effects are dominant, hence an increase in productivity is usually observed in these wells.<ref name=Mottetal_2000 />   

Another effect is also present at high velocities, which acts against the velocity stripping effect. This effect is termed the Inertial (non-Darcy) flow effects, which, at high velocities, reduces effective gas permeability and leads to lower well productivity. On the other hand, velocity stripping increases the relative permeability. However, it has been observed in most gas-condensate wells that relative permeability effects are dominant, hence an increase in productivity is usually observed in these wells.<ref name=Mottetal_2000 />   

==Well test analysis of condensate banking in gas wells==

==Well test analysis of condensate banking in gas wells==