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Cem Sarica - One of the best experts on this subject based on the ideXlab platform.
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droplet entrainment measurements under high pressure two phase low Liquid Loading flow in slightly inclined pipes
Journal of Petroleum Science and Engineering, 2020Co-Authors: Hendy T Rodrigues, Auzan A Soedarmo, Eduardo Pereyra, Cem SaricaAbstract:Abstract This paper presents new experimental data for droplet entrainment measurements under low-Liquid Loading two-phase flow. Liquid and gas flow rates are representative of the flow in wet gas/condensate pipelines under stratified and annular flow patterns. The novelty in the experimental conditions are the high-pressure (2.76 MPa), large diameter pipe (0.155 m) and inclination from the horizontal (2°). The used fluids are Isopar-L oil and Nitrogen gas. Data are presented as a function of system pressure, Liquid and gas superficial velocities, and dimensionless numbers. Comparisons of the new data with previous models are also provided.
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Liquid droplet entrainment in two phase oil gas low Liquid Loading flow in horizontal pipes at high pressure
International Journal of Multiphase Flow, 2018Co-Authors: Duc Huu Vuong, Eduardo Pereyra, Cem Sarica, A AlsarkhiAbstract:Abstract An experimental study is conducted in a 152.4-mm inner diameter (ID) high-pressure facility to investigate the Liquid droplet entrainment in two-phase oil-gas flow in horizontal pipe under low-Liquid Loading condition. Total of 247 tests are carried out at five different operating pressures, namely, 1.48, 1.82, 2.17, 2.51, and 2.86 MPa. The test fluids are nitrogen and mineral oil (Isopar-L). Superficial oil velocity (vSL) ranges from 0.01 to 0.05 m/s, while superficial gas velocity (vSg) ranges from 1.6 to 16.7 m/s depending on the operating pressures. An isokinetic sampling system is used to measure the entrained droplet flux at three different vertical positions in the gas phase. A high-speed video camera is used to visually observe and estimate the onsets of entrainment. This paper provides a unique entrainment data set for two-phase flow in a large diameter pipe at high operating pressure. The experimental data are analyzed to evaluate the effects of high operating pressure and superficial velocities. It is found that the entrainment fraction increases with the operating pressure. In addition, predictions of ten correlations for two-phase entrainment fraction are compared with the experimental data to evaluate the performances. The results show that these correlations over-predict the entrainment fraction data from this study.
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droplet entrainment analysis of three phase low Liquid Loading flow
International Journal of Multiphase Flow, 2017Co-Authors: Hamidreza Karami, Eduardo Pereyra, Carlos F Torres, Cem SaricaAbstract:Abstract Most of the commonly used multiphase flow models neglect the amount of droplets entrained in stratified wavy flow. However, the experimental data presented in this study show high entrainment values, exceeding 50% in some cases. This shows that neglecting entrainment phenomenon can introduce a major source of discrepancy into multiphase flow modeling predictions. This study improves the entrainment fraction predictions in three-phase stratified flow. The droplet entrainment in three-phase stratified flow in horizontal pipelines is experimentally investigated using a 0.152-m ID facility. The experiments are conducted under low Liquid Loading conditions, which is very commonly observed in wet gas pipelines. The oil-aqueous-gas flow experiments are initially performed without mono-ethylene glycol (MEG), and then repeated with 50 wt% of MEG in the aqueous phase to analyze the effects of MEG presence on entrainment. MEG is a commonly used inhibitor in oil industry, applied to avoid hydrate formation in offshore systems. Its impacts on multiphase flow droplet entrainment are investigated. The experimental range of this study covers superficial gas velocity (vSg) values from 17 to 23 m/s, superficial Liquid velocity (vSL) values of 0.01 and 0.02 m/s, and inlet Liquid stream aqueous phase fraction (APFin) values between 0 to 100%. Similar test matrix is completed for both water and water and MEG solution as the aqueous phase. An isokinetic probe system is used to measure the entrained droplet flux at different vertical positions in the gas phase. Liquid entrainment fraction is then estimated by means of volumetric averaging. The trends of the data with respect to input parameters are investigated. The two and three-phase entrainment fraction data are used for a correlation evaluation study. Performances of ten correlations for two-phase entrainment fraction are compared to the experimental data, and best performing correlations are identified. The correlation of Pan and Hanratty (2002) is modified in an effort to improve the entrainment fraction estimations. The predictions of the modified correlation are compared with the acquired data and datasets from the literature. In addition, a simple empirical correlation is proposed to predict Liquid phase entrainment fraction for three-phase flow systems.
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foam flow in vertical gas wells under Liquid Loading critical velocity and pressure drop prediction
International Journal of Multiphase Flow, 2016Co-Authors: Abdulkamil Ajani, Cem Sarica, Mohan Kelkar, Eduardo PereyraAbstract:Abstract Foam lift is one of the most cost effective methodologies for unLoading gas wells. The surfactants are either injected intermittently or continuously to lift the Liquid to the surface. By reducing the gravitational gradient and increasing the frictional gradient, the critical velocity at which Liquid Loading occurs is shifted to lower gas velocities. Currently, we do not have a methodology to predict the critical velocity (at the transition boundary of annular and intermittent flow) and the pressure drop under foam flow conditions. To address this, we measured several foam flow characteristics in both small scale and large scale facilities. Small scale facility involved measurement of foam carryover capacity as a function of time and surfactant concentration. Large scale facility involved measurement of Liquid holdup, pressure drop, fraction of gas trapped in foam and foam holdup in 40-ft 2-in. and 4-in. tubing. We developed closure relationships for Liquid hold up, foam holdup, fraction of gas trapped in the foam and interfacial friction factor by combining the small scale data with the data collected in the large scale experiments. These closure relationships are applicable to four different surfactants tested. A new transition criterion was developed and successfully used to predict onset of Liquid Loading under foam flow. Using a force balance over the gas core in annular flow, we developed a new procedure to calculate the pressure drop under foam flow conditions. We compared our model results with actual measurements in the large scale facility. Our model was reasonably able to predict the pressure drop within ±30%. The reason for such a large variance is that the small scale facility was not able to capture all the characteristics of the foam which were observed in the large scale facility. It is very difficult to reproduce the foam characteristics exactly in two different experiments. This is discussed further in this paper. The procedure developed is the only one currently available to calculate the pressure drop under the foam flow conditions using the small scale data. It is superior to conventional annular flow pressure drop prediction models which are currently available in the literature.
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effect of surfactants on Liquid Loading in vertical wells
International Journal of Multiphase Flow, 2016Co-Authors: Abdulkamil Ajani, Cem Sarica, Mohan Kelkar, Eduardo PereyraAbstract:Abstract Most gas wells produce some amount of Liquid. The Liquid is either condensate or water. At high rates, the gas is able to entrain Liquid to the surface; however, as gas well depletes, the Liquid drops back in a gas well (called Liquid Loading) creating a back pressure on the reservoir formation. Addition of surfactants to the well to remove Liquid is one of the common methods used in gas wells. Liquid Loading in vertical gas wells with and without surfactant application was investigated in this study. Anionic, two types of amphoteric (amphoteric I and amphoteric II), sulphonate and cationic surfactants were tested in 2-inch and 4-inch 40-feet vertical pipes. Pressure gradient and Liquid holdup are measured. Visual observation with a high speed camera was used to gain insight into the direction of foam flow in intermittent flow and foam film flow under annular flow conditions. Liquid Loading is initiated when the Liquid film attached to the wall in annular flow starts flowing downwards. Introduction of foam causes the gas velocity at which film reversal occurs to decrease; this shift increases with increasing surfactant concentration and it is more pronounced in 2-inch pipe than in 4-inch pipe. That is, the benefit of surfactants is much more pronounced in 2-inch pipe than in 4-inch pipe. The reason for postponement of Liquid Loading is reduction in the Liquid holdup at low gas velocities which reduces the Liquid holdup in foam flow compared to air-water flow. However, at higher gas velocities, the pressure drop in 2-inch compared to 4-inch pipe increases rapidly as the surfactant concentration increases. The selection of optimum concentration of the surfactant is a balance between the reductions in the gas velocity at which Liquid Loading occurs compared to increase in the frictional loss as the concentration increases. We provide guidelines about the selection of the surfactant concentration. Visual observations using high speed camera show differences in the behavior under foam flow conditions. Unlike air-water flow, the Liquid film attached to the wall is replaced by thick foam capturing the gas bubbles. The type of roll waves which carry the Liquid in 2-inch pipe is different than what was observed in 4-inch pipe. Compared to 4-inch pipe, the roll waves in 2-inch pipe are much thicker. This partly explains the differences in 2-inch versus 4-inch pipe behavior.
Eduardo Pereyra - One of the best experts on this subject based on the ideXlab platform.
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droplet entrainment measurements under high pressure two phase low Liquid Loading flow in slightly inclined pipes
Journal of Petroleum Science and Engineering, 2020Co-Authors: Hendy T Rodrigues, Auzan A Soedarmo, Eduardo Pereyra, Cem SaricaAbstract:Abstract This paper presents new experimental data for droplet entrainment measurements under low-Liquid Loading two-phase flow. Liquid and gas flow rates are representative of the flow in wet gas/condensate pipelines under stratified and annular flow patterns. The novelty in the experimental conditions are the high-pressure (2.76 MPa), large diameter pipe (0.155 m) and inclination from the horizontal (2°). The used fluids are Isopar-L oil and Nitrogen gas. Data are presented as a function of system pressure, Liquid and gas superficial velocities, and dimensionless numbers. Comparisons of the new data with previous models are also provided.
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Liquid droplet entrainment in two phase oil gas low Liquid Loading flow in horizontal pipes at high pressure
International Journal of Multiphase Flow, 2018Co-Authors: Duc Huu Vuong, Eduardo Pereyra, Cem Sarica, A AlsarkhiAbstract:Abstract An experimental study is conducted in a 152.4-mm inner diameter (ID) high-pressure facility to investigate the Liquid droplet entrainment in two-phase oil-gas flow in horizontal pipe under low-Liquid Loading condition. Total of 247 tests are carried out at five different operating pressures, namely, 1.48, 1.82, 2.17, 2.51, and 2.86 MPa. The test fluids are nitrogen and mineral oil (Isopar-L). Superficial oil velocity (vSL) ranges from 0.01 to 0.05 m/s, while superficial gas velocity (vSg) ranges from 1.6 to 16.7 m/s depending on the operating pressures. An isokinetic sampling system is used to measure the entrained droplet flux at three different vertical positions in the gas phase. A high-speed video camera is used to visually observe and estimate the onsets of entrainment. This paper provides a unique entrainment data set for two-phase flow in a large diameter pipe at high operating pressure. The experimental data are analyzed to evaluate the effects of high operating pressure and superficial velocities. It is found that the entrainment fraction increases with the operating pressure. In addition, predictions of ten correlations for two-phase entrainment fraction are compared with the experimental data to evaluate the performances. The results show that these correlations over-predict the entrainment fraction data from this study.
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droplet entrainment analysis of three phase low Liquid Loading flow
International Journal of Multiphase Flow, 2017Co-Authors: Hamidreza Karami, Eduardo Pereyra, Carlos F Torres, Cem SaricaAbstract:Abstract Most of the commonly used multiphase flow models neglect the amount of droplets entrained in stratified wavy flow. However, the experimental data presented in this study show high entrainment values, exceeding 50% in some cases. This shows that neglecting entrainment phenomenon can introduce a major source of discrepancy into multiphase flow modeling predictions. This study improves the entrainment fraction predictions in three-phase stratified flow. The droplet entrainment in three-phase stratified flow in horizontal pipelines is experimentally investigated using a 0.152-m ID facility. The experiments are conducted under low Liquid Loading conditions, which is very commonly observed in wet gas pipelines. The oil-aqueous-gas flow experiments are initially performed without mono-ethylene glycol (MEG), and then repeated with 50 wt% of MEG in the aqueous phase to analyze the effects of MEG presence on entrainment. MEG is a commonly used inhibitor in oil industry, applied to avoid hydrate formation in offshore systems. Its impacts on multiphase flow droplet entrainment are investigated. The experimental range of this study covers superficial gas velocity (vSg) values from 17 to 23 m/s, superficial Liquid velocity (vSL) values of 0.01 and 0.02 m/s, and inlet Liquid stream aqueous phase fraction (APFin) values between 0 to 100%. Similar test matrix is completed for both water and water and MEG solution as the aqueous phase. An isokinetic probe system is used to measure the entrained droplet flux at different vertical positions in the gas phase. Liquid entrainment fraction is then estimated by means of volumetric averaging. The trends of the data with respect to input parameters are investigated. The two and three-phase entrainment fraction data are used for a correlation evaluation study. Performances of ten correlations for two-phase entrainment fraction are compared to the experimental data, and best performing correlations are identified. The correlation of Pan and Hanratty (2002) is modified in an effort to improve the entrainment fraction estimations. The predictions of the modified correlation are compared with the acquired data and datasets from the literature. In addition, a simple empirical correlation is proposed to predict Liquid phase entrainment fraction for three-phase flow systems.
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foam flow in vertical gas wells under Liquid Loading critical velocity and pressure drop prediction
International Journal of Multiphase Flow, 2016Co-Authors: Abdulkamil Ajani, Cem Sarica, Mohan Kelkar, Eduardo PereyraAbstract:Abstract Foam lift is one of the most cost effective methodologies for unLoading gas wells. The surfactants are either injected intermittently or continuously to lift the Liquid to the surface. By reducing the gravitational gradient and increasing the frictional gradient, the critical velocity at which Liquid Loading occurs is shifted to lower gas velocities. Currently, we do not have a methodology to predict the critical velocity (at the transition boundary of annular and intermittent flow) and the pressure drop under foam flow conditions. To address this, we measured several foam flow characteristics in both small scale and large scale facilities. Small scale facility involved measurement of foam carryover capacity as a function of time and surfactant concentration. Large scale facility involved measurement of Liquid holdup, pressure drop, fraction of gas trapped in foam and foam holdup in 40-ft 2-in. and 4-in. tubing. We developed closure relationships for Liquid hold up, foam holdup, fraction of gas trapped in the foam and interfacial friction factor by combining the small scale data with the data collected in the large scale experiments. These closure relationships are applicable to four different surfactants tested. A new transition criterion was developed and successfully used to predict onset of Liquid Loading under foam flow. Using a force balance over the gas core in annular flow, we developed a new procedure to calculate the pressure drop under foam flow conditions. We compared our model results with actual measurements in the large scale facility. Our model was reasonably able to predict the pressure drop within ±30%. The reason for such a large variance is that the small scale facility was not able to capture all the characteristics of the foam which were observed in the large scale facility. It is very difficult to reproduce the foam characteristics exactly in two different experiments. This is discussed further in this paper. The procedure developed is the only one currently available to calculate the pressure drop under the foam flow conditions using the small scale data. It is superior to conventional annular flow pressure drop prediction models which are currently available in the literature.
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effect of surfactants on Liquid Loading in vertical wells
International Journal of Multiphase Flow, 2016Co-Authors: Abdulkamil Ajani, Cem Sarica, Mohan Kelkar, Eduardo PereyraAbstract:Abstract Most gas wells produce some amount of Liquid. The Liquid is either condensate or water. At high rates, the gas is able to entrain Liquid to the surface; however, as gas well depletes, the Liquid drops back in a gas well (called Liquid Loading) creating a back pressure on the reservoir formation. Addition of surfactants to the well to remove Liquid is one of the common methods used in gas wells. Liquid Loading in vertical gas wells with and without surfactant application was investigated in this study. Anionic, two types of amphoteric (amphoteric I and amphoteric II), sulphonate and cationic surfactants were tested in 2-inch and 4-inch 40-feet vertical pipes. Pressure gradient and Liquid holdup are measured. Visual observation with a high speed camera was used to gain insight into the direction of foam flow in intermittent flow and foam film flow under annular flow conditions. Liquid Loading is initiated when the Liquid film attached to the wall in annular flow starts flowing downwards. Introduction of foam causes the gas velocity at which film reversal occurs to decrease; this shift increases with increasing surfactant concentration and it is more pronounced in 2-inch pipe than in 4-inch pipe. That is, the benefit of surfactants is much more pronounced in 2-inch pipe than in 4-inch pipe. The reason for postponement of Liquid Loading is reduction in the Liquid holdup at low gas velocities which reduces the Liquid holdup in foam flow compared to air-water flow. However, at higher gas velocities, the pressure drop in 2-inch compared to 4-inch pipe increases rapidly as the surfactant concentration increases. The selection of optimum concentration of the surfactant is a balance between the reductions in the gas velocity at which Liquid Loading occurs compared to increase in the frictional loss as the concentration increases. We provide guidelines about the selection of the surfactant concentration. Visual observations using high speed camera show differences in the behavior under foam flow conditions. Unlike air-water flow, the Liquid film attached to the wall is replaced by thick foam capturing the gas bubbles. The type of roll waves which carry the Liquid in 2-inch pipe is different than what was observed in 4-inch pipe. Compared to 4-inch pipe, the roll waves in 2-inch pipe are much thicker. This partly explains the differences in 2-inch versus 4-inch pipe behavior.
Paulo J Waltrich - One of the best experts on this subject based on the ideXlab platform.
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a simplified model to predict transient Liquid Loading in gas wells
Journal of Natural Gas Science and Engineering, 2016Co-Authors: Erika V Pagan, Paulo J WaltrichAbstract:Abstract This paper presents a simplified model to predict the inception of Liquid Loading in gas wells and its subsequent transient phenomenon. This model enables the estimation of erratic or cease of production due to Liquid Loading using a simple but robust technique. This approach is validated with field data. The model described in this paper proposes the use of the so-called “nodal analysis technique” to predict Liquid Loading in gas wells. The approach proposed modifies the tubing performance relationship instead of using the common critical velocity or minimum pressure point concept. This modification enables the simple use of nodal analysis to accurately predict Liquid Loading initiation, including the amount of time required to cease production after the inception of Liquid Loading. The model shows good agreement field data on the prediction of Liquid Loading. From the modeling results and comparison with field data, it is possible to conclude that this model can provide a reasonable prediction of the Liquid Loading phenomena. For instance, one of the main objectives of using models to predict Liquid Loading is to anticipate when a gas well would start suffering from Liquid Loading problems, and potentially stop flowing. The use of conventional models showed a significant mismatch in the critical flow for Liquid Loading initiation when compared to field data while the use of the model proposed would reduce this mismatch significantly. In addition to that, the use of this simplified model also enables understanding of the main field symptoms related to Liquid Loading in gas wells.
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experimental investigation on the prediction of Liquid Loading initiation in gas wells using a long vertical tube
Journal of Natural Gas Science and Engineering, 2015Co-Authors: Paulo J Waltrich, Gioia Falcone, Catalina Posada, Jessica Martinez, Jader R BarbosaAbstract:Liquid Loading in gas wells is generally defined as the inability of the produced gas to lift the co-produced Liquid up the tubing, resulting in Liquid accumulation in the wellbore. This Liquid accumulation is related to decrease in gas production and it can even cease production. The characterization of this phenomenon is often based on field monitoring, with limited measurements of pressure and Liquid holdup profiles, and usually without visual observations of the phenomenon. This paper reveals there is still a significant discrepancy between the available models and the experimental data available in the literature. Besides reviewing the present state of research into this area, the current understanding about the mechanisms of Liquid Loading initiation is discussed in this paper and directions on how to use this understanding to model and provide solutions to Liquid Loading problems is also presented. An experimental investigation on the initiation of Liquid Loading in a gas well has been carried out using a vertical 42 m long, 0.0489 m (2 in) ID tube system. Vertical gas–Liquid flows were analyzed with the aim of understanding how the Liquid accumulates in a long vertical tube while decreasing the gas flow rate. This experimental study includes visual observations of the Liquid transport and two-phase flow regimes, and measurements of pressure, temperature and Liquid holdup along the vertical tube. The experimental observation of the Liquid build-up was correlated to prediction criteria models available in the literature for Liquid Loading initiation.
Catalin Teodoriu - One of the best experts on this subject based on the ideXlab platform.
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Relative Permeability Hysteresis Effects in the Near-Wellbore Region During Liquid Loading in Gas Wells
SPE Latin American and Caribbean Petroleum Engineering Conference, 2010Co-Authors: He Zhang, Catalin TeodoriuAbstract:In oil and gas field operations, the dynamic interactions between reservoir and wellbore cannot be ignored, especially during transient flow in the near-wellbore region. A particular instance of transient flow in the near-wellbore region is the intermittent response of a reservoir that is typical of Liquid Loading in gas wells. Our previous numerical simulation study (Zhang et. al. 2009 and 2010) successfully captured the Liquid backflow rates resulting from bottomhole pressure (BHP) oscillations typical of Liquid Loading, and emphasized their detrimental effect on gas production. This paper presents a numerical modeling effort to investigate the relative permeability hysteresis effects in the near-wellbore region during transient flow conditions for a synthetic, low permeability gas reservoir. Firstly, the previously validated "U-shaped?? pressure profile along the reservoir radius was generated with an increased BHP from a starting steady-state flowing configuration. This pressure profile can lead to reinjection of the Liquid phase into the reservoir. The BHP was then let to decrease, with a corresponding temporary recovery in gas productivity. With subsequent BHP oscillations, the flow direction was allowed to switch back and forth, which could represent a typical Liquid Loading scenario. The Killough method was used to calculate the relative permeability hysteresis during the various imbibitions and drainage processes. The results reveal that the hysteresis effect is negligible at a high-frequency alternation of imbibition and drainage in the near-wellbore region, and may therefore not be significant in Liquid Loading problems.
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decision matrix for Liquid Loading in gas wells for cost benefit analyses of lifting options
Journal of Natural Gas Science and Engineering, 2009Co-Authors: Hanyoung Park, Gioia Falcone, Catalin TeodoriuAbstract:Liquid Loading in gas wells is a multiphase flow phenomenon where the Liquid content of the well creates back pressure that restricts, and in some cases even stops, the flow of gas from the reservoir. It is estimated that 90% of the producing gas wells in the U.S. are operating in Liquid Loading regime. Field-proven solutions already exist to reduce the loss of gas production when Liquid Loading begins to occur. However, whether or not the chosen remedy is technically feasible and cost effective will depend on the field's location, export route capacity and the operator's experience. Although there are literature reviews available that describe the possible solutions to Liquid Loading problems in gas wells, no tool currently exists which is capable of helping an operator select the best remedial option for a specific field case. The selection of the best remedial technique and the timeframe within which the remedial action is undertaken are critical to a project's profitability. This paper describes a newly developed decision matrix to screen the possible remedial options available to the operator. The matrix not only provides a critical evaluation of technical solutions to the problem of Liquid Loading in gas wells vis-a-vis the existing technical and economic constraints, but also serves as a quick screening tool for the selection of production optimization strategies. In its current state of development, the tool consists of an assessment algorithm used in conjunction with a decision tree. Being a data mining technique, the decision tree allows rapid subdivision of large initial data sets into successively smaller sets by a series of decision rules, which are based on information available in the public domain. The effectiveness of the matrix is now ready to be tested against real field data sets.
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Numerical Modeling of Fully-Transient Flow in the Near-Wellbore Region During Liquid Loading in Gas Wells
Latin American and Caribbean Petroleum Engineering Conference, 2009Co-Authors: He Zhang, Gioia Falcone, Peter P. Valko, Catalin TeodoriuAbstract:In oil and gas field operations, the dynamic interactions between reservoir and wellbore cannot be ignored, especially during transient flow in the near-wellbore region. A particular instance of transient flow in the near-wellbore region is the intermittent response of a reservoir that is typical of Liquid Loading in gas wells. Despite the high level of attention that the industry has devoted to the alleviation of Liquid Loading, the fundamental understanding of the associated phenomena is still surprisingly weak. This applies not only to the flows in the wells, but also to the ways in which these flows interact with those in the reservoir. The classical way of dealing with these interactions, inflow performance relationships (IPRs), relate the inflow from the reservoir to the pressure at the bottom of the well, which is related to the multiphase flow behavior in the tubing. These relationships are usually based on steady-state or pseudo steady-state assumptions. However, such IPRs may be inadequate when a transition from an acceptable Liquid Loading regime to an unacceptable occurs over a relatively small range of production rates and, hence, over a relatively short time. The most satisfactory solution would be to couple a transient model for the reservoir to a transient model for the well. This paper presents the results of a numerical modeling effort focused on the identification of the transient pressure profile in the near-wellbore region during fully transient flow conditions. The preliminary results, obtained for a single-phase (gas) situation and for a three-phase (oil-water-gas) situation, show a "U-shaped" pressure profile along the reservoir radius. The existence of a similar pressure profile could be the explanation for the reinjection of the heavier phase into the reservoir during Liquid unLoading in gas wells.
Michael A Adewumi - One of the best experts on this subject based on the ideXlab platform.
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low Liquid Loading multiphase flow in natural gas pipelines
Journal of Energy Resources Technology-transactions of The Asme, 2003Co-Authors: Luis F Ayala, Michael A AdewumiAbstract:Pressure and temperature variations of natural gas flows in a pipeline may cause partial gas condensation. Fluid phase behavior and prevailing conditions often make Liquid appearance inevitable, which subjects the pipe flow to a higher pressure loss. This study focuses on the hydrodynamic behavior of the common scenarios that may occur in natural gas pipelines. For this purpose, a two-fluid model is used. The expected flow patterns as well as their transitions are modeled with emphasis on the low-Liquid Loading character of such systems. In addition, the work re-examines previous implementations of two-flow model for gas-condensate flow.