A comparative study on the performance of multiphase flow models against offshore field production data

Chaves, Gabriela Souza; Karami, Hamidreza; Filho, Virgílio José Martins Ferreira; Vieira, Bruno Ferreira

doi:10.1016/j.petrol.2021.109762

Cited by 12 publications

(2 citation statements)

References 23 publications

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“…Ansari (Ansari et al, 1994;Chaves et al, 2022) The models describing bubble flow, slug flow and annular flow are established by simulating the riser model of production Wells. The annular flow is slightly weaker.…”

Section: Model Applicable Conditionsmentioning

confidence: 99%

A new optimized method in wellbore to improve gas recovery in shale reservoirs

Yang,

Xiang,

et al. 2023

Front. Energy Res.

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With the scale development of shale gas, the importance of selecting appropriate deliquification process has become increasingly evident in maintaining well productivity and improving shale gas recovery rate. At present, the preferred deliquification process are macro-control plate method and field experience method. The existing methods can only qualitatively select the deliquification process by considering limited influencing factors, resulting in poor process implementation. Based on the results of error analysis, the Gray model was optimized to calculate the pressure distribution in the shale gas wellbore and determine the applicable pressure limit. The W.Z.B. empirical model, which fully considers the influence of wellbore inclination, is used to calculate the gas-liquid carrying situation and determine the applicable liquid carrying limit. By analyzing the technical limits of five commonly used deliquification processes in the Changning shale gas field, namely, plunger lift, optimizing pipe string, gas lift, foam drainage, and intermittent production, a quantitative optimization method for deliquification processes was established. This method was then used to obtain the optimization chart for deliquification processes in shale gas wells. This method was applied in Well Ning 209-X, where the corresponding optimization chart for deliquification processes was drawn based on the production characteristics of the gas well. By quantitatively optimizing the deliquification processes and adjusting to suitable techniques, it effectively guided the production of the gas well and improved the gas field recovery rate.

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Section: Model Applicable Conditionsmentioning

confidence: 99%

A new optimized method in wellbore to improve gas recovery in shale reservoirs

Yang,

Xiang,

et al. 2023

Front. Energy Res.

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“…However, none of these correlations have been definitively proven to be universally applicable or provide satisfactory results for all field conditions and parameters. Since multiphase flow behavior can vary significantly across different oil fields and operational scenarios, it poses challenges in finding a single correlation that accurately captures the complexities of the entire field [21][22][23][24][25]. The primary purpose of multiphase flow correlations is to predict the liquid holdup and the frictional pressure gradient [26].…”

Section: -Introductionmentioning

confidence: 99%

Multiphase Flow Behavior Prediction and Optimal Correlation Selection for Vertical Lift Performance in Faihaa Oil Field, Iraq

Hamed,

Sadeq,

Mahmud

2023

IJCPE

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In the petroleum industry, multiphase flow dynamics within the tubing string have gained significant attention due to associated challenges. Accurately predicting pressure drops and wellbore pressures is crucial for the effective modeling of vertical lift performance (VLP). This study focuses on predicting the multiphase flow behavior in four wells located in the Faihaa oil field in southern Iraq, utilizing PIPESIM software. The process of selecting the most appropriate multiphase correlation was performed by utilizing production test data to construct a comprehensive survey data catalog. Subsequently, the results were compared with the correlations available within the PIPESIM software. The outcomes reveal that the Hagedorn and Brown (HB) correlation provides the most accurate correlation for calculating pressure in FH-1 and FH-3 while the Beggs and Brill original (BBO) correlation proves to be the optimal fit for wells FH-2 and Gomez mechanistic model for FH-4. These correlations show the lowest root mean square (RMS) values of 11.5, 7.56, 8.889, and 6.622 for the four wells, respectively, accompanied by the lowest error ratios of 0.00692%, 0.00033%, 0.00787%, and 0.0011%, respectively. Conversely, Beggs and Brill original (BBO) correlation yields less accurate results in predicting pressure drop for FH-1 compared with other correlations. Similarly, correlations, such as Orkiszewski for FH-2, Duns and Ros for FH-3, and ANSARI for FH-4, also display less accuracy level. Notably, the study also identifies that single-phase flow dominates within the tubing string until a depth of 6000 feet in most wells, beyond which slug flow emerges, introducing significant production challenges. As a result, the study recommends carefully selecting optimal operational conditions encompassing variables such as wellhead pressure, tubing dimensions, and other pertinent parameters. This approach is crucial to prevent the onset of slug flow regime and thus mitigate associated production challenges.

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