Using the Drill Stem Test Results in Production Tubing Size Design for Development Wells

This paper presents a practical methodology for optimizing production tubing size in development wells, leveraging Drill Stem Test (DST) results. While tubing size constitutes a minor component of the overall field development plan, its proper design is crucial for ensuring efficient well flow, particularly in later field life stages characterized by reservoir pressure depletion and increased liquid production, which can lead to liquid loading issues and impact hydrocarbon recovery and project economics. The core of this methodology is nodal analysis, employing a well model built and calibrated using DST data with the Petroleum Experts (Prosper) application. The study details the process of well model calibration through Inflow Performance Relationship (IPR) and Vertical Lift Performance (VLP) matching, followed by a sensitivity analysis on various tubing sizes. This analysis incorporates considerations for liquid loading, using both the Turner velocity model and the PE5 stability criteria, to identify the optimal tubing size that delivers maximum flow rate while minimizing the risk of liquid loading. For the gas condensate well studied, an optimum tubing size of 4 ½ inches was suggested, balancing maximum flow rate with minimized liquid loading potential. This approach ensures both initial optimal flow rates and long-term production deliverability. The study addresses a gap in previous research, which often focused on field-scale modeling or used DST data primarily for reservoir evaluation, without fully leveraging its potential in tubing size design for development wells. This paper's novelty lies in its direct integration of DST data into the tubing design workflow, bridging the gap between reservoir testing and completion engineering to enhance decision-making in well development planning.