Phase Change Tracking Approach to Predict Timing of Condensate Formation and its Distance from the Wellbore in Gas Condensate Reservoirs

Benedicta Bilotu Onoabhagbe, Sina Rezaei Gomari, Paul Russell, Johnson Ugwu, Blessing Tosin Ubogu

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Abstract

Production from gas condensate reservoir poses the major challenge of condensate banking or blockage. This occurs near the wellbore, around which a decline in pressure is initially observed. A good sign of condensate banking is a rise in the gas-oil ratio (GOR) during production and/or a decline in the condensate yield of the well, which leads to considerable reductions in well deliverability and well rate for gas condensate reservoirs. Therefore, determining the well deliverability of a gas condensate reservoir and methods to optimize productivity is paramount in the industry. This research study aims to investigate fluid phase change behaviour in a gas condensate reservoir during depletion, to understand the problems encountered in well deliverability during production and to evaluate optimization techniques that could enhance deliverability. This requires a review of different techniques and methods used in the analysis of gas condensate reservoirs and of condensate saturation build-up in the system as a function of time to determine the occurrence of condensate in the vicinity of wellbore and a sensitivity analysis of the different parameters and how they affect well deliverability. A commercial compositional simulator (E300) was used to study gas condensate fluid flow using synthetic data to simulate a gas condensate reservoir by studying the compositional changes (i.e., C 1, C 2, C 3, C 4-C 6?) in hydrocarbon content over time and/or distance from the wellbore by determining the timing of condensate banking as well as its distance from a well, and the results were used in turn as guidance to optimize condensate production. Typical scenarios such as those involving water injection and gas recycling were adopted in studying condensate banking. The result shows a considerable change in the composition of the fluid components with respect to fluid phase changes as the pressure declines during depletion. The earlier the pressure decline occurs, the quicker the change in phase and the closer to the wellbore the transition takes place, which leads to significant condensate loss. Simulation results show that water injection with the minimum pressure decline produces a higher condensate recovery factor of 93%, while gas recycling suffered from early phase change and a condensate recovery factor of only 66% was achieved. Altering the gas production rate in the gas recycling case reduced the phase change near to the wellbore and produced a better recovery factor of up to 82%. The findings of this study help to provide a better understanding of the hydrocarbon phase change near wellbores in gas condensate reservoirs from the gas phase to condensate. The suggested approach to tracking the timing and location of condensate formation can also assist the production engineers in managing condensate production and selecting appropriate optimization techniques to improve condensate recovery.

Original languageEnglish
Article numberFluids 2019,4,71
Number of pages14
JournalFluids
Volume71
Issue number4
DOIs
Publication statusPublished - 12 Apr 2019

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Gas condensates
Recycling
Recovery
Gases
Water injection
Fluids
Hydrocarbons
Gas oils
Sensitivity analysis
Flow of fluids
Simulators
Productivity
Engineers
Chemical analysis

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title = "Phase Change Tracking Approach to Predict Timing of Condensate Formation and its Distance from the Wellbore in Gas Condensate Reservoirs",
abstract = "Production from gas condensate reservoir poses the major challenge of condensate banking or blockage. This occurs near the wellbore, around which a decline in pressure is initially observed. A good sign of condensate banking is a rise in the gas-oil ratio (GOR) during production and/or a decline in the condensate yield of the well, which leads to considerable reductions in well deliverability and well rate for gas condensate reservoirs. Therefore, determining the well deliverability of a gas condensate reservoir and methods to optimize productivity is paramount in the industry. This research study aims to investigate fluid phase change behaviour in a gas condensate reservoir during depletion, to understand the problems encountered in well deliverability during production and to evaluate optimization techniques that could enhance deliverability. This requires a review of different techniques and methods used in the analysis of gas condensate reservoirs and of condensate saturation build-up in the system as a function of time to determine the occurrence of condensate in the vicinity of wellbore and a sensitivity analysis of the different parameters and how they affect well deliverability. A commercial compositional simulator (E300) was used to study gas condensate fluid flow using synthetic data to simulate a gas condensate reservoir by studying the compositional changes (i.e., C 1, C 2, C 3, C 4-C 6?) in hydrocarbon content over time and/or distance from the wellbore by determining the timing of condensate banking as well as its distance from a well, and the results were used in turn as guidance to optimize condensate production. Typical scenarios such as those involving water injection and gas recycling were adopted in studying condensate banking. The result shows a considerable change in the composition of the fluid components with respect to fluid phase changes as the pressure declines during depletion. The earlier the pressure decline occurs, the quicker the change in phase and the closer to the wellbore the transition takes place, which leads to significant condensate loss. Simulation results show that water injection with the minimum pressure decline produces a higher condensate recovery factor of 93{\%}, while gas recycling suffered from early phase change and a condensate recovery factor of only 66{\%} was achieved. Altering the gas production rate in the gas recycling case reduced the phase change near to the wellbore and produced a better recovery factor of up to 82{\%}. The findings of this study help to provide a better understanding of the hydrocarbon phase change near wellbores in gas condensate reservoirs from the gas phase to condensate. The suggested approach to tracking the timing and location of condensate formation can also assist the production engineers in managing condensate production and selecting appropriate optimization techniques to improve condensate recovery.",
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Phase Change Tracking Approach to Predict Timing of Condensate Formation and its Distance from the Wellbore in Gas Condensate Reservoirs. / Bilotu Onoabhagbe, Benedicta; Rezaei Gomari, Sina; Russell, Paul; Ugwu, Johnson; Ubogu, Blessing Tosin.

In: Fluids, Vol. 71, No. 4, Fluids 2019,4,71, 12.04.2019.

Research output: Contribution to journalArticle

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T1 - Phase Change Tracking Approach to Predict Timing of Condensate Formation and its Distance from the Wellbore in Gas Condensate Reservoirs

AU - Bilotu Onoabhagbe, Benedicta

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AU - Ugwu, Johnson

AU - Ubogu, Blessing Tosin

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N2 - Production from gas condensate reservoir poses the major challenge of condensate banking or blockage. This occurs near the wellbore, around which a decline in pressure is initially observed. A good sign of condensate banking is a rise in the gas-oil ratio (GOR) during production and/or a decline in the condensate yield of the well, which leads to considerable reductions in well deliverability and well rate for gas condensate reservoirs. Therefore, determining the well deliverability of a gas condensate reservoir and methods to optimize productivity is paramount in the industry. This research study aims to investigate fluid phase change behaviour in a gas condensate reservoir during depletion, to understand the problems encountered in well deliverability during production and to evaluate optimization techniques that could enhance deliverability. This requires a review of different techniques and methods used in the analysis of gas condensate reservoirs and of condensate saturation build-up in the system as a function of time to determine the occurrence of condensate in the vicinity of wellbore and a sensitivity analysis of the different parameters and how they affect well deliverability. A commercial compositional simulator (E300) was used to study gas condensate fluid flow using synthetic data to simulate a gas condensate reservoir by studying the compositional changes (i.e., C 1, C 2, C 3, C 4-C 6?) in hydrocarbon content over time and/or distance from the wellbore by determining the timing of condensate banking as well as its distance from a well, and the results were used in turn as guidance to optimize condensate production. Typical scenarios such as those involving water injection and gas recycling were adopted in studying condensate banking. The result shows a considerable change in the composition of the fluid components with respect to fluid phase changes as the pressure declines during depletion. The earlier the pressure decline occurs, the quicker the change in phase and the closer to the wellbore the transition takes place, which leads to significant condensate loss. Simulation results show that water injection with the minimum pressure decline produces a higher condensate recovery factor of 93%, while gas recycling suffered from early phase change and a condensate recovery factor of only 66% was achieved. Altering the gas production rate in the gas recycling case reduced the phase change near to the wellbore and produced a better recovery factor of up to 82%. The findings of this study help to provide a better understanding of the hydrocarbon phase change near wellbores in gas condensate reservoirs from the gas phase to condensate. The suggested approach to tracking the timing and location of condensate formation can also assist the production engineers in managing condensate production and selecting appropriate optimization techniques to improve condensate recovery.

AB - Production from gas condensate reservoir poses the major challenge of condensate banking or blockage. This occurs near the wellbore, around which a decline in pressure is initially observed. A good sign of condensate banking is a rise in the gas-oil ratio (GOR) during production and/or a decline in the condensate yield of the well, which leads to considerable reductions in well deliverability and well rate for gas condensate reservoirs. Therefore, determining the well deliverability of a gas condensate reservoir and methods to optimize productivity is paramount in the industry. This research study aims to investigate fluid phase change behaviour in a gas condensate reservoir during depletion, to understand the problems encountered in well deliverability during production and to evaluate optimization techniques that could enhance deliverability. This requires a review of different techniques and methods used in the analysis of gas condensate reservoirs and of condensate saturation build-up in the system as a function of time to determine the occurrence of condensate in the vicinity of wellbore and a sensitivity analysis of the different parameters and how they affect well deliverability. A commercial compositional simulator (E300) was used to study gas condensate fluid flow using synthetic data to simulate a gas condensate reservoir by studying the compositional changes (i.e., C 1, C 2, C 3, C 4-C 6?) in hydrocarbon content over time and/or distance from the wellbore by determining the timing of condensate banking as well as its distance from a well, and the results were used in turn as guidance to optimize condensate production. Typical scenarios such as those involving water injection and gas recycling were adopted in studying condensate banking. The result shows a considerable change in the composition of the fluid components with respect to fluid phase changes as the pressure declines during depletion. The earlier the pressure decline occurs, the quicker the change in phase and the closer to the wellbore the transition takes place, which leads to significant condensate loss. Simulation results show that water injection with the minimum pressure decline produces a higher condensate recovery factor of 93%, while gas recycling suffered from early phase change and a condensate recovery factor of only 66% was achieved. Altering the gas production rate in the gas recycling case reduced the phase change near to the wellbore and produced a better recovery factor of up to 82%. The findings of this study help to provide a better understanding of the hydrocarbon phase change near wellbores in gas condensate reservoirs from the gas phase to condensate. The suggested approach to tracking the timing and location of condensate formation can also assist the production engineers in managing condensate production and selecting appropriate optimization techniques to improve condensate recovery.

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