Phase prediction technology was applied to the evaluation and design of natural gas pipeline. The technology was applied to a system in Texas to determine the economic feasibility of replacing an existing line and to the design of liquid removal facilities. A one year study of the system was run that developed data trends for key system variables. Through this effort, we demonstrated that condensate prediction technology is directly applicable to natural gas pipeline design and evaluation.


Within the last five years, Panhandle Eastern Pipeline has begun experiencing liquid problems in many of it's natural gas gathering systems. This was first apparent in what we term West Panhandle Region (Texas Panhandle Region north of Amarillo). The pipeline liquids have resulted in increased operating costs, damage to equipment and, the potential for catastrophic damage to compressor stations and extreme danger to their operations personnel if liquids would enter compressors. We first approached the problem by determining why the liquids were now occurring. We then sought to understand the phenomenon. Through this we became acquainted with the work of Bergman and Katz with the University of Michigan from their monograph entitled "Retrograde Condensation in Natural Gas Pipelines" and from discussion with and through the papers of Al Dukat of Columbia Gas System on Condensate Control. Their work is the basis of our one year study of condensate behavior in our Zofness to Sneed transmission line and our applications of the resulting technology to the evaluation, design and optimization of gathering facilities within the Panhandle system.


The retrograde phenomenon for a multi-component gas mixture, is where at one temperature two dewpoint pressures can exist. Thus, for natural gas, (Refer to figure 1) you can go from a single phase high pressure gas into the two-phase region by isothermally decreasing the gas pressure, passing the retrograde dew point. The pressure can he decreased until vaporization occurs, signifying entering the normal condensation region. As temperature decreases at constant pressure within the two phase region, the liquid make increases.


Pipeline liquids enter the pipeline in natural gas systems by the vapor state, due to wellhead separation of the gas and liquids. Casinghead gas is usually low pressure produced gas that is in intimate contact with crude oil and natural gas liquids before wellhead separation. Due to the low pressure and contact with liquid, significant quantities of C+5 enter into the gas stream. In a condensate well, production is usually high pressure initially, thus the heavy ends are in the liquid state in the reservoir. As the wellhead pressure decreases, more heavy ends vaporize into the gas stream increasing the potential amount of pipeline liquids.


In a normal natural gas gathering system, gas undergoes a series of compression steps (based on wellhead pressure) before entering the mainline. (See figure 2) In this system, condensation formation is a function of pressure increases and temperature decreases in the system.

This content is only available via PDF.
You can access this article if you purchase or spend a download.