A simple and accurate model to predict pressure drop in vertical gas wells

ABSTRACT

Predicting pressure drop in gas wells is one of the most important issues for designing deliquification technologies and optimizing gas production. Current pressure-drop prediction methods can be divided into analytical and empirical models. Although various models have been proposed to predict pressure drop in wellbores, no model has offered stable performance over wide liquid and gas flowrate ranges. Especially for gas wells with low liquid – gas ratios, very few models have been developed specifically. In this study, a simple and accurate three-point model is developed for predicting liquid holdup in wellbores. The model is based on the liquid holdups and gas velocities at the annular – churn, churn – slug and slug – bubble boundaries and is comprehensive for calculating the liquid holdup in vertical wellbores at different liquid/gas flowrates and pressures. The proposed method was verified with 39 collected laboratory and 182 field measured data points from the literature, which have wide parameter ranges. For comparison, some widely used models in the petroleum industry were also evaluated. In validation with the laboratory data with pipe diameters of 50.8 and 101.6 mm, although the new model has an average percentage error (E3) of 220.1% in the churn flow, ranking fourth of all the evaluated models, the other five indicators in the churn flow and six indicators in the annular flow are lowest of all these evaluated models, resulting in relative performance factors (RPFs) of 0.2 and 0, respectively. In the field measured data, gas and liquid productions range between 0.34 × 10⁴—77.6 × 10⁴ m³/d and 1—347.8 m³/d, tubinghead pressure ranges from 0.7 to 84.7 MPa, which can cover most gas wells. The validation demonstrates that the new model still has good performance with five indicators being lowest. The RPF of the new pressure-drop model in the field measured data ranges is 0.29, still lowest of all these evaluated models, showing better performance than these widely used models in petroleum industry for vertical gas wells. This indicates that the new model can accurately predict pressure drop under different conditions in vertical gas wells.

KEYWORDS:

• Vertical gas wells
• liquid holdup
• pressure drop
• three-point model
• analytical model

Highlights

A three-point model is proposed for predicting liquid holdup in gas wells based on flow pattern transitions.

The proposed semi-analytical model is superior to other empirical models with no limit on experimental range.

Experimental and field data demonstrate that the new pressure-drop model is better than these widely used models in the petroleum industry for vertical gas wells.

Disclosure statement

No potential conflict of interest was reported by the author(s).

Additional information

Funding

This work is supported by Science and Technology Cooperation Project of the CNPC-SWPU Innovation Alliance (Grant No. 2020CX020203).

Notes on contributors

Jian Yang

Jian Yang received his Ph.D. degree from Southwest Petroleum University. Currently he works at PetroChina Southwest Oil & Gas Field Company. His research interest is Oil and Gas Field Development Technology and Management.

Jiaxiao Chen

Jiaxiao Chen is a Senior Engineer at PetroChina Southwest Oil & Gas Field Company, his research interest is Multiphase flow theory and application

Qiang Wang

Qiang Wang is a Senior Engineer at PetroChina Southwest Oil & Gas Field Company, his research interest is Oil and gas production engineering theory and technology

Changqing Ye

Changqing Ye is a Senior Engineer at PetroChina Southwest Oil & Gas Field Company, his research interest is Oil and gas production engineering theory and technology.

Fan Yu

Fan Yu is a Senior Engineer at PetroChina Southwest Oil & Gas Field Company, his research interest is Oil and gas production engineering theory and technology.