– Effects of Near Wellbore and Reservoir Fluid Compositional Changes on Condensate Banking –
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ABSTRACT
Gas condensate reservoirs are initially discovered as single-phase gas reservoirs. As the reservoir is produced below the fluid dew-point pressure, an increase in condensate saturation in the near wellbore region occur which reduces the relative permeability to gas and in turn causes productivity impairment.
It is pertinent to predict condensate banking behavior accurately during a field’s operational phase to avoid problems with a well’s ability to attain production targets.
This paper seeks to explore the effects of near wellbore and reservoir fluid compositional changes on condensate banking using Velocity Dependent Relative Permeability (VDRP).
To achieve this, a PVT data for gas condensate reservoir from a field was used to build an input data file using Eclipse 300. A single-layer, radial, 3D reservoir model was used to investigate the effects of VDRP on productivity index, relative permeability to gas and condensate recovery.
When Velocity Dependent Relative Permeability (VDRP) option was adopted for volume flow rate of 10Mscfpd, there was no change in the gas relative permeability and productivity index.
This was due to low flow rate. However, when the flow rate was increased to 1000Mscfpd and 2000Mscfpd, the gas relative permeability reduced only by 36.1% and 23.6% respectively while the Productivity Index reduced by 34.2% and 21.7% respectively. The positive effect of VDRP assisted these low values.
TABLE OF CONTENTS
CERTIFICATION……………………………………………………………………………………………………………ii
ABSTRACT…………………………………………………………………………………………………………………..iv
ACKNOWLEDGMENT………………………………………………………………………………………………….vi
DEDICATION………………………………………………………………………………………………………………vii
TABLE OF CONTENTS……………………………………………………………………………………………….viii
CHAPTER ONE………………………………………………………………………………………………………………1
INTRODUCTION……………………………………………………………………………………………………………1
1.1 PROBLEM STATEMENT……………………………………………………………………………………….2
1.2 AIM AND OBJECTIVE…………………………………………………………………………………………..2
1.3 JUSTIFICATION…………………………………………………………………………………………………….3
1.4 SCOPE…………………………………………………………………………………………………………………..3
CHAPTER TWO……………………………………………………………………………………………………………..4
LITERATURE REVIEW………………………………………………………………………………………………….4
2.1 PHYSICAL BEHAVIORS OF GAS CONDENSATE…………………………………………………4
2.1.1 Hydrocarbon Reservoir Fluids…………………………………………………………………………….4
2.2 PHASE BEHAVIOR OF GAS CONDENSATE………………………………………………………..10
2.3 FLOW BEHAVIOR OF GAS CONDENSATE…………………………………………………………12
2.3.1 Drawdown Behavior…………………………………………………………………………………………12
2.3.2 Buildup Behavior…………………………………………………………………………………………….15
2.4 EFFECT OF FLOW VELOCITY AND INTERFACIAL TENSION ON RELATIVE
PERMEABILITY……………………………………………………………………………………………………….17
2.4.1 Non-Darcy Flow………………………………………………………………………………………………18
2.5 PREVIOUS RELATED WORKS……………………………………………………………………………20
CHAPTER THREE………………………………………………………………………………………………………..21
METHODOLOGY…………………………………………………………………………………………………………21
CHAPTER FOUR………………………………………………………………………………………………………….24
4.0 RESULTS AND DISCUSSION………………………………………………………………………………….24
CHAPTER FIVE……………………………………………………………………………………………………………34
CONCLUSION………………………………………………………………………………………………………………34
Recommendation………………………………………………………………………………………………………..34
REFERENCES………………………………………………………………………………………………………………35
INTRODUCTION
Gas condensate reservoirs are typically discovered as single-phase gas reservoirs. During the production life of wells drilled in gas condensate reservoirs, the pressure declines near- isothermally from the reservoir boundary to the well.
If the well flowing bottom-hole pressure drops below the dew-point pressure, the condensate drops out of the gas and forms a bank of liquid around the well (Gringarten et al., 2000; Hashemi et al., 2006) which is mainly composed of intermediate and heavier hydrocarbon components.
When the condensate drops out in the reservoir, at first, the condensate liquid will not flow until the accumulated condensate saturation exceeds the critical condensate saturation. This leads to a loss of valuable hydrocarbons because the condensate contains most of the heavy hydrocarbon components.
Besides that, near the wellbore where the condensate bank appears, there will be a multiphase flow, so the gas relative permeability is reduced. The reduction of gas relative permeability due to the condensate bank is called condensate blocking (or condensate banking).
REFERENCES
Nagarajan, N. R., Honarpour, M. M., Sampath, K., & McMichael, D. (2004). Comparison of Gas-Condensate Relative Permeability Using Live Fluid vs. Model Fluids. SCA2004- 09.
Fevang, Ø., & Whitson, C. H. (1996). Modeling gas-condensate well deliverability. SPE Reservoir Engineering, 11(04), 221-230.
Cho, S. J., Civan, F., & Starling, K. E. (1985, January). A correlation to predict maximum condensation for retrograde condensation fluids and its Use in pressure- depletion calculations. In SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers.
Gringarten, A. C., Al-Lamki, A., Daungkaew, S., Mott, R., & Whittle, T. M. (2000, January). Well test analysis in gas-condensate reservoirs. In SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers.
Jamiolahmady, , Danesh, A., Henderson, G., & Tehrani, D. (2003, January).Variations of gas-condensate relative permeability with production rate at near wellbore conditions: a general correlation. In Offshore Europe. Society of Petroleum Engineers.
Sognesand, S. (1991, January). Long-term testing of vertically fractured gas condensate wells. In SPE Production Operations Symposium. Society of Petroleum
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