Tubing Size Optimization in Gas Depletion Drive Reservoirs
Authors: Gunawan Ronald , Dyer George R. 
Published: December 2007

Abstract
Proper tubing size selection is essential to maximize economic reserve recovery in depletion drive gas reservoirs. For wells completed in multiple reservoirs with a wide range of reservoir properties, tubing size selection can become quite complex. This paper presents an approach used to determine optimum tubing size using a model developed by applying Nodal Analysis and Gas Load-Up Technology. A database consisting of 340 gas wells was analyzed and used to confirm the validity of the approach and develop a model. The model shows the relationship between Reservoir Abandonment Pressure (Pab), Permeability Thickness (kh), Tubing Size, and Flowing Wellhead Pressure. The model shows that for high kh (Permeability Thickness) completions, tubing size has only a minor effect on the reservoir abandonment pressure. Actual field data confirms the model's predicted results.
Refer to the result of the study, the tubing in 7 (seven) gas wells were changed from 2 3/8" to 3 1/2". This project resulted in 50 MMCFD gas deliverability increase. The actual results agreed closely with the predictions and demonstrated the accuracy of the methods used.

Introduction
VICO Indonesia, the operator of Sanga-Sanga Block in East Kalimantan - Indonesia (Fig. 1) has four major gas fields that produce an average of 1.6 BSCFD. These fields consist of more than 300 unique reservoirs that have permeability ranges from less than 1 md to greater than 1,500 md. Most reservoirs are depletion drive. Most of the 440 wells in the Sanga-Sanga block are dual completions. They range in depth from 5,000 to 14,000 ft. The Sanga-Sanga block has three gathering system pressures, high (950 psig), medium (375 psig), and low (150 psig).
Typically, a new completion will start in the high pressure system and move through the medium pressure system into the low pressure system before depletion.
Tubing size selection is an important factor in completion design that affects well performance and ultimate reserve recovery. Producing a well at the maximum rate without affecting the reserve recovery is desirable. Increasing the tubing size will usually increase the rate, however, the question becomes how does tubing size affect reserve recovery. A general tubing selection guideline is required for optimum tubing size selection. That guideline is also required for inventory control and planning.

Theoretical Background
One of the critical factors in selecting tubing size is determining when a well will load up and die. Determination of the factors effecting this load up has been a matter of intense study over the years. The minimum flowrate required to unload a well primarily depends on tubing size, liquid yields and flowing tubing pressure. Two primary methods for determining when a well begins to load up are Turner et al's method using a physical model and Nodal Analysis based on reservoir inflow performance and two phase flow correlations.
Turner Method. The Turner et al.'s method for predicting gas well load up is based on two physical models, liquid film movement along the pipe walls and entrainment of liquid droplets in a gas stream. Turner compared the two models with observed field data and found that the Liquid-Droplet Model was superior. The Liquid-Droplet Model is based on a free-falling particle in a gas will reach a terminal velocity. This terminal velocity depends on the particle size, shape, interfacial tension, liquid density, fluid-medium density and viscosity. In a gas well if the upward velocity of the gas is less than the terminal velocity, liquid will begin to accumulate and eventually the well will load up and die. The Turner method predicts when liquids can no longer be suspended in the gas as droplets. At this point the well is at impending load-up. Applying this terminal velocity equation to wellbores and correcting to standard conditions, the minimum gas flowrate, qc, for continuous removal of liquids from a wellbore:
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