Modeling fully transient two-phase flow in the near-wellbore region during liquid loading in gas wells

Zhang, He; Falcone, Gioia; Teodoriu, Cătălin

doi:10.1016/j.jngse.2010.04.005

“…Thus, the concept of U-shaped pressure profile is proposed as shown in Fig. 4 c. (Zhang et al, 2010;Limpasurat, 2013;Liu, 2016) Fig. 4 -Pressure distribution of liquid unloaded and loaded wells along the near-wellbore reservoir, where r w is the wellbore radius and r e is the reservoir radius.…”

Section: Pressure Distributions and Flow Directions In The Near Wellbmentioning

confidence: 99%

“…To first prove the existence of the U-shaped pressure profile originally proposed by Zhang et al (2010) while avoiding the laboratory complexities of handling two-phase flow, single gas nitrogen (purity >= 99.996%) was used as the test fluid in this study. Obernkirchen sandstone, which is a very consolidated, relatively fine grained, low permeability sedimentary rock in the Lower Cretaceous, was selected for this study.…”

Section: Laboratory Tests At Core-scalesmentioning

confidence: 99%

Liquid loading in gas wells: From core-scale transient measurements to coupled field-scale simulations

Liu

¹

,

Falcone

²

,

Teodoriu

³

2017

Journal of Petroleum Science and Engineering

Self Cite

View full text Add to dashboard Cite

Liquid loading is a major operational constraint in mature gas fields around the world. It manifests itself as an increasing back pressure on the reservoir due to a rising liquid column in the well, which initially decreases deliverability, then ultimately causes the gas well to cease production. Theoretically, every gas well will experience this debilitating phenomenon in the latter stages of its producing life.In this paper, both laboratory experiments and numerical simulations are presented to shed more light on the physical process of liquid loading, with a focus on reservoir responses. On the one hand, core-flooding experimental setups of different scales were designed and constructed to investigate back pressure effects on transient flow through the near-wellbore region of the reservoir. On the other hand, the modelling of a gas well undergoing controlled flow and shut-in cycles was performed to validate core-scale observations at reservoir scale, using commercial integrated numerical software that connects a transient wellbore model to a transient reservoir model. The simulated transient characteristics of short-term downhole dynamics (e.g. liquid re-injection and co-current/counter-current flows) supported the Ushaped concept observed in the experiments.The detected temporal distribution of pore fluid pressure within the reservoir medium itself (referred to as the U-shaped pressure profile) was observed both experimentally at the corescale and numerically at the reservoir-scale. This pressure distribution can be used to explain re-injection of the denser phases into the near-wellbore region of the reservoir.

show abstract

“…One small-scale and one large-scale core-flooding experimental setups were designed and constructed to mimic the physical process of liquid loading and the corresponding reservoir response. To first prove the existence of the U-shaped pressure profile originally proposed by Zhang et al (2010) while avoiding the laboratory complexities of handling two-phase flow, single gas nitrogen (purity >= 99.996%) was used as the test fluid in this study. Obernkirchen sandstone, which is a very consolidated, relatively fine grained, low permeability sedimentary rock in the Lower Cretaceous, was selected for this study.…”

Section: Laboratory Tests At Core-scalesmentioning

confidence: 99%

Liquid loading in gas wells: Experimental investigation of back pressure effects on the near-wellbore reservoir

Liu

¹

,

Falcone

²

,

Teodoriu

³

2016

Journal of Natural Gas Science and Engineering

Self Cite

View full text Add to dashboard Cite

Liquid loading is a major operational constraint in mature gas fields around the world. It manifests itself as an increasing back pressure on the reservoir due to a rising liquid column in the well, which initially decreases deliverability, then ultimately causes the gas well to cease production. Theoretically, every gas well will experience this debilitating phenomenon in the latter stages of its producing life.In this paper, both laboratory experiments and numerical simulations are presented to shed more light on the physical process of liquid loading, with a focus on reservoir responses. On the one hand, core-flooding experimental setups of different scales were designed and constructed to investigate back pressure effects on transient flow through the near-wellbore region of the reservoir. On the other hand, the modelling of a gas well undergoing controlled flow and shut-in cycles was performed to validate core-scale observations at reservoir scale, using commercial integrated numerical software that connects a transient wellbore model to a transient reservoir model. The simulated transient characteristics of short-term downhole dynamics (e.g. liquid re-injection and co-current/counter-current flows) supported the Ushaped concept observed in the experiments.The detected temporal distribution of pore fluid pressure within the reservoir medium itself (referred to as the U-shaped pressure profile) was observed both experimentally at the corescale and numerically at the reservoir-scale. This pressure distribution can be used to explain re-injection of the denser phases into the near-wellbore region of the reservoir.

show abstract

“…Liu et al improved the distribution coefficient and the drift velocity of drift flow models for horizontal and upward inclined gas–liquid two-phase flow . A large number of literature studies have been reported on the mechanism of gas–liquid two-phase flow in a gas pipeline. ,− …”

Section: Introductionmentioning

confidence: 99%

Optimum Strategy for Perforating Distribution of Homogeneous Gas–Liquid Two-Phase Flow in Vertical Gas Wells

Hu

¹

2021

View full text Add to dashboard Cite

Aiming to optimize the total production of homogeneous gas−liquid two-phase flow in perforated vertical gas wells, a new coupled reservoir−wellbore mathematical model is proposed which consists of the crushed zone damage skin factor, pressure gradient, flow rate, and liquid holdup. An optimum strategy consisting of two optimization problems is developed to study the effect of perforation distribution on the production of vertical wells under a steady-state inflow. Then, these optimization models are applied to infinite and finite conductivity gas wells and the optimal distribution of perforation could be determined. The results show that inflow rate profiles could be improved by optimizing the perforation location for vertical gas wells.

show abstract

Modeling fully transient two-phase flow in the near-wellbore region during liquid loading in gas wells

Cited by 11 publications

References 8 publications

Liquid loading in gas wells: From core-scale transient measurements to coupled field-scale simulations

Liquid loading in gas wells: From core-scale transient measurements to coupled field-scale simulations

Liquid loading in gas wells: Experimental investigation of back pressure effects on the near-wellbore reservoir

Optimum Strategy for Perforating Distribution of Homogeneous Gas–Liquid Two-Phase Flow in Vertical Gas Wells

Contact Info

Product

Resources

About