Automatic Pigging of Two-Phase Gas Gathering Systems
- D.J. Vinson
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- September 1968
- Document Type
- Journal Paper
- 951 - 955
- 1968. Society of Petroleum Engineers
- 4.1.5 Processing Equipment, 4.2 Pipelines, Flowlines and Risers, 4.1.6 Compressors, Engines and Turbines, 5.2.1 Phase Behavior and PVT Measurements, 6.1.5 Human Resources, Competence and Training, 4.1.2 Separation and Treating, 2.2.2 Perforating, 4.1.3 Dehydration
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Vinson, D.J., Colorado Interstate Gas Co., Colorado Springs, Colo.
This paper describes one answer for the often encountered problem of excessive pressures drops due to liquids in gas gathering systems located in rough terrain. Some gas gathering systems experience pressure drops so large that gas flow is severely restricted or completely stopped. The causes of the excess pressure drop are low gas velocity, liquids, and many sags for the liquids to collect in. These liquids may be either conducted into the pipeline from the wells or condensed in the pipeline as pipeline from the wells or condensed in the pipeline as the gas cools to ground temperature. Each sag contributes an additive pressure drop equivalent to the head of liquid held in its downstream uphill section. The liquid head in each sag varies inversely with the gas velocity. In many cases, automatic on-stream spherical pigging offers a practical solution to the pressure drop problem.
A study was begun in 1958 to determine the ultimate extent of and the best way for handling a liquids problem developing in a new gathering system. The system consisted of a 39-mile trunk line, gathering gas from approximately 300 wells with 16-, 18-, 20-, and 24-in. OD pipes (Fig. 1). The maximum working pressure was 960 psi and the required delivery pressure was 700 psi. psi and the required delivery pressure was 700 psi. The pressure drop in the system began to increase steadily, and by Jan., 1959, pressures at the remote end of the line approached the maximum allowable for the pipeline. Rupture discs were blowing with a resultant loss of gas. The high pressures were relieved temporarily by increasing the velocity in the pipeline that moved the liquids to a terminal point where they were removed and sold. Fig. 2 is a record of pressure in the system at various periods during the winter. It also records the effectiveness of removing liquids by the use of high gas velocity. A plot of the expected liquid production in the system was made (Fig. 3). These volumes and liquid head totals for the system reveal that excessive pressure drops could be expected to exist during at least 9 months of the year. The volume of liquids also indicates that they would be expected to exist during at least 9 months of the conveniently collected and marketed at pipeline pressures. Colorado Interstate Gas Co.'s standard method for handling this problem was to remove the liquids through drips installed in the sags. The number of drips required in this case and the economic advantage of collecting and marketing the liquids at pipeline pressures stimulated an investigation of other possibilities.
The investigation indicated that automatic on-stream pigging of the liquids into storage at a proposed gasoline pigging of the liquids into storage at a proposed gasoline plant site would be the most practical solution. plant site would be the most practical solution. A rubber sphere was developed to separate batch liquids in a products pipeline. If spherical pigs could be adapted for use in a two-phase, multiple line-size gas gathering system, they should be more readily automated than conventional pigs. Test facilities installed to verify the utility of the sphere for this application revealed that a sphere inflated to a tight fit in the two-phase pipeline removes liquids as efficiently as does a squeegee, or conventional pig, while a slightly undersized sphere i.e., 97 percent of pipeline ID removes over 98 percent of the liquids. This result was adequate for this application and promised an extremely long sphere life. promised an extremely long sphere life. The spheres tend to stop at side connections having diameters over one-half that of the pigged pipeline. To prevent this, there should be installed in the side prevent this, there should be installed in the side connection opening a coupon that should be perforated over its upstream half and solid plated over its downstream half (see Fig. 7A); or an oversized tee should be installed in the pigged line at the side connection and sloped downward in the downstream direction, so that the sphere is free to roll or fall past the side connection (see Fig. 7B). A sphere matching the inside diameter of the pipeline pushes a train of smaller-diameter spheres ahead of it. pushes a train of smaller-diameter spheres ahead of it. In the investigation, the smallest diameter sphere was approximately one-half the diameter of the pushing sphere. Liquids can flow downhill into a lateral connection that is feeding gas into the pigged pipeline. A large lateral connection, not pigged, operating at low gas velocity, may allow enough liquids to flow into it from the pigged pipeline to reduce noticeably the immediate liquid recoveries; pipeline to reduce noticeably the immediate liquid recoveries; also, since a large portion of these liquids is pushed back into the pigged pipeline shortly after the pig has passed, the pressure drop just after pigging may not be reduced as much as was expected.
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