Quantitative Investigation of Decrease in Gas Well Productivity Due to the Presence of a Condensate Bank Around the Wellbore

Jalal Mazoom ( jalal.mazloom@imperial.ac.uk ) is a PhD student at the Polytechnic University of Tehran . He is currently spending a year in the Centre for Petroleum Studies at Imperial College finalising his studies on well testing in gas condensate reservoirs under the guidance of Professor Alain Gringarten ( a.gringarten@imperial.ac.uk ). Here he presents a two-phase pseudo-pressure function which can be used to quantify the effect of condensate drop out on well productivity.

Introduction

When pressure around the wellbore in a gas condensate reservoir drops below the dew point, a bank of condensate builds up in the near-wellbore region. The presence of this condensate bank decreases the well productivity, mainly because of relative permeability effects. This decrease in well productivity has been the subject of many investigations, which have attempted to resolve uncertainties in many areas: critical condensate saturation, re-vaporisation of condensate, radii of condensate saturation and mobility in "concentric rings" versus pressure, and so on. In this article, the effect of condensate on well productivity is quantified using a two-phase pseudo-pressure function calculated as a function of the condensate saturation distribution in the reservoir.

Development of the method

Methods have been previously introduced to investigate the effect of condensate saturation on decreasing well productivity [1]. Equation 1 is used as the basic equation for fluid flow:

(1)

Where:

(2)

If the presence of condensate is not considered in the integration of Equation 1, the productivity of the well is overestimated [1]. Integration of this equation must therefore be performed over three distinct regions (Figure 1).

Figure 1 : Schematic of Condensate Saturation Regions Around a Gas Condensate Well Producing Below the Dew Point (Plan View )

• Region 1, near the wellbore, where the condensate saturation is above the critical saturation. In this region, the condensate is able to flow along with the gaseous phase in proportion to their respective relative permeabilities;
• Region 2, further away, where the condensate saturation is below the critical condensate saturation. The liquid condensate is immobile;
• Region 3, away from the well, where the pressure is above the dew point. Only a gaseous phase is present.

A relationship between relative permeabilities and pressure is necessary to integrate Equation 1. As a relationship between relative permeabilities and condensate saturation exists, only a relationship between condensate saturation and pressure must be found:

For Region 1, steady-state flow is assumed.

For Region 2, results from CCE and CVD have been used [2] but simulation results show that this is not appropriate [3].

In this paper, we introduce a new equation to represent the relationship between condensate saturation and pressure in Region 2:

(3)

The result of the integration of Equation 1 with Equation 3 is compared in Figure 2 with the productivity prediction using dry gas pseudo-pressures (which does not consider the presence of condensate): in the latter case, the calculated AOF is 22% higher.

Figure 2 : Well Productivities Predicted by the Method Presented in this Article and by the Dry Gas Pseudo Pressure

Conclusions

• Using CVD and CCE methods is not appropriate for finding the relationship between condensate saturation and pressure;
• Ignoring the presence of condensate around the wellbore leads to a significant overestimation of well productivity and AOF;
• These issues have been quantified by finding the key relationship between condensate saturation and pressure.

Acknowledgements

Special thanks to Dr F.Rashidi (Polytechnic University of Tehran) and R.Kelly (ECL Technology) and my colleagues in the Centre of Petroleum Studies at Imperial College for their inspirations for this project. Also we appreciate the financial support from the London office of Sasol Petroleum International.

Nomenclature

Saturation of gas

Formation volume factor of gas

Derivative of Gas FVF w.r.t. Pressure

Total compressibility

Well bore radius

Skin of well

Mobility of gas

Solution of gas in condensate

Relative permeability of gas

Relative permeability of condensate

Gas viscosity

Condensate viscosity

Gas flow rate

Drainage radius

Mobility of gas and condensate

References

1. Saleh, A.M. and Stewart, G: "Interpretation of Gas Condensate Well Tests With Field Examples", SPE 27719, presented at annual technical conference and exhibition of the Society of Petroleum Engineers held in Washington DC , Oct 1992.
2. Fevang, Q. and Whitson, C. H.: "Modelling Gas Condensate Well Deliverability", SPE reservoir engineering, Nov 1996.
3. Zaitsev, I. Y. and Dmitrievsky, S.A. and Yufin, P. A. and Dolotnik, D. N. and Sarkisov, G. G. and Schepkina, K. E.: "Compositional Modelling and PVT Analysis of Pressure Maintenance Effect in Gas Condensate Field", comparative study, paper SPE 36923 presented at the SPE European petroleum conference held in Milan Italy 22-24 Oct 1996.

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