Predicting Severe Slugging in Toe-Down Horizontal Wells
- Chris Carpenter (JPT Technology Editor)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- November 2019
- Document Type
- Journal Paper
- 79 - 80
- 2018. Society of Petroleum Engineers
- 2 in the last 30 days
- 39 since 2007
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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 191611, “Existence and Prediction of Severe Slugging in Toe-Down Horizontal Wells,” by Jayanth Nair, SPE, Eduardo Pereyra, SPE, and Cem Sarica, SPE, The University of Tulsa, prepared for the 2018 SPE Annual Technical Conference and Exhibition, Dallas, 24–26 September. The paper has not been peer reviewed.
Severe slugging is an important flow-assurance issue, typically observed in offshore pipeline-riser systems. The consequences of severe slugging include flooding of downstream production facilities and an overall decrease in productivity. Severe slugging had been thought to be limited to systems with a downward-inclined pipeline and vertical, catenary, or lazy-S-shaped riser. This paper presents the results of an experimental and modeling study that demonstrates the existence of severe slugging in systems with upward-inclined lateral flow paths, such as a toe-down well.
Severe slugging in offshore pipeline-riser systems with downward-inclined pipelines has been intensely studied because of its serious consequences. Most such studies are related to pipeline-riser systems, but the possibility of severe slugging in toe-up horizontal wells also was demonstrated experimentally in the literature. Toe-up wells are geometrically analogous to pipeline-riser systems because the lateral section in a toe-up well is a mostly downward-inclined flow path. However, there has been no documented evidence of severe slugging in systems with upward-inclined flow paths.
A large-scale experimental facility was used in this study. This facility was designed primarily to study flow behavior in horizontal wells. The lateral section in the facility was 236 ft long and comprised 6-in. inner-diameter (ID) pipe, which acted as the casing. The curvature section was made of bent acrylic pipe and had a radius of curvature of approximately 18 ft. The vertical section was 34 ft high with 2-in. ID polycarbonate pipe simulating the tubing. The schematic shows a packerless configuration. In such a configuration, an additional volume was necessary to simulate the effect of an annular volume. This was achieved by adding a 37-ft-high, 6-in.-ID expansion volume. For cases where a packer was required, a solid plug was placed in the system to simulate the packer and the annular volume was disconnected. The end of the tubing location was varied by pulling the tubing or running the tubing deeper.
The test fluids were air and water. Air and water entered the facility at the toe of the well. The mass flow rates were measured using flowmeters and were held constant during the tests. As the flow pattern developed along the lateral section, flowing pressures, temperatures, and pressure gradient were measured. Conductivity probes allowed the measurement of slug characteristics. The test facility also included several quick-closing valves. These valves were pneumatically operated and could capture the flow and measure holdup. When the flow reached the top of the vertical section, it returned to the water tank where the air was vented. A separate metering skid was used to inject gas in the tubing to study the effect of gas lift.
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