|Publisher||Society of Petroleum Engineers||Language||English|
|Content Type||Conference Paper|
|Title||Asphaltenes Pipeline Cleanout: A Horizontal Challenge for Coiled Tubing|
C.A. Torres, SPE, Schlumberger; F. Treint and C. Alonso, Total; A. Milne, SPE, Schlumberger; and A. Lecomte, Total
SPE/ICoTA Coiled Tubing Conference and Exhibition, 12-13 April 2005, The Woodlands, Texas
|Copyright||2005. Society of Petroleum Engineers|
Crude produced in the North of Monagas Estate, East Venezuela, has a high asphaltene content, which comes out of solution in both the wellbore tubulars and pipeline. This can eventually lead to complete plugging of the pipeline. This increases the cost of maintaining production because of the need to periodically remove these organic deposits. In a specific case, 9 km of 8-5/8-in. outside diameter (OD) production pipeline was successfully cleaned out using 2-in. OD coiled-tubing (CT) to regain pipeline production. As there is limited literature or documentation on the use of CT for this specific application, the operator and the service company established a joint team to do the feasibility study and engineering. Some of the key points were; the design of a frame to lay down the injector head, define the entry points along the pipeline, the selection of the bottomhole assembly (BHA), and fluids to use. Other issues were the measurement of stresses (push/pull) on the CT so that the CT could be run as far as possible in the pipeline without damaging either the CT or the pipeline. The pipeline was successfully cleaned, the CT being run seven times from five different entry points in the pipeline. This resulted in savings of USD 1 million for the operator and significantly reduced the time to recover normal production in the pipeline.
The characteristic asphaltene content in the crude produced from the northeastern Venezuelan oilfields,1 requires periodic CT cleanouts with solvents and mechanical means to remove the obstructions that plug the wells and reduce production. These asphaltenes precipitate from solution in the wellbore tubular, caused by the pressure and temperature differentials, and progressively reduce the flow area in the tubing. Surface facilities are not exempt from this phenomenon. As the crude flows through the pipeline, the asphaltenes settle at the bottom due to the lower temperatures and pressures in the system. To prevent total plugging, the operators pump solvent mixtures and pigs through the pipelines, however without regular treatments the pipelines become restricted and eventually the production rate drops.
In the case studied, this phenomenon led to an increase in the differential pressure in the line and ended in complete production stoppage on the surface system. This forced the operator to look for alternative means to reestablish and maintain production. Fig. 1 illustrates the progressive increase in the pipeline’s differential pressure caused by the asphaltenes accumulation. Conventional pipeline maintenance practices could not be performed. Pumping aromatic solvents was not an option given the environmental constraints.
Temporary Production Assisted by a Mobile Testing Unit
To maintain the well’s production, a program designed to produce the well using a mobile testing unit (MTU) was implemented. A choke manifold, a flare, two separators, and twelve 500-bbl capacity storage tanks were connected to the well and reconnected to the production line. Because of the severity of the pipeline plugging, it was necessary to transport the produced oil using trucks, increasing the risk associated with human error and environmental incidents. Fig. 2 illustrates the MTU layout.
An attempt was performed to unplug an entire pipeline section, with the assumption that the plugged section would be below the river crossed by the pipeline, as this was the coldest and the lowest point in the pipeline. Two pipeline entry points (HT1 and HT2) were constructed to perform a first test across the river section by pumping water at a maximum pressure of 2,900 psi. Different pipeline sections were tested following the same procedure. When the pressure built up and there was no resultant flow at the other end, a plugged section was identified. Two main plugged sections were identified. The results showed that these plugged sections were located between the pipeline entry points HT3 and HT2 and between HT1 and HT4. Fig. 3 illustrates the pipeline layout on the field and the pipeline entry point locations.
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