Delineating the Pour Point and Gelation Temperature of Waxy Crude Oils
- Ramachandran Venkatesan (U. of Michigan) | Probjot Singh (U. of Michigan) | H. Scott Fogler (U. of Michigan)
- Document ID
- Society of Petroleum Engineers
- SPE Journal
- Publication Date
- December 2002
- Document Type
- Journal Paper
- 349 - 352
- 2002. Society of Petroleum Engineers
- 5.1.1 Exploration, Development, Structural Geology, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 4.2 Pipelines, Flowlines and Risers, 3.4.1 Inhibition and Remediation of Hydrates, Scale, Paraffin / Wax and Asphaltene, 4.2.5 Offshore Pipelines
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Paraffin deposition in subsea pipelines is a multimillion-dollar problem in the oil industry. The temperature at which a waxy crude oil gels is an important property that determines the initiation of the deposition process. The "pour point," as defined by the standard ASTM test method, is not sufficient to describe the deposition of waxy crudes under flow conditions. The "gelation temperature," explained in this article, is found to be an appropriate measure of the onset of gelation under static as well as flow conditions. Rheological experiments show that the gelation temperature of a wax-oil system is depressed by the shear stress acting on the system during cooling.
Paraffin deposition in subsea pipelines is becoming a greater concern as offshore oil wells have moved farther away from the shore because of the depletion of oil reserves near the shore. As crude oil flows through the cold ocean floor environment, the oil temperature drops, leading to precipitation of high-molecular-weight paraffins (waxes) because of solubility limits. Some of the precipitated waxes then deposit on the walls of the pipeline, restricting the flow. Because the oil now has to travel longer distances to reach the shore, the crude oil is subjected to a greater extent of cooling, leading to a greater amount of precipitation and deposition. Paraffin deposition restricts the oil flow, increases the strain on the pumping equipment (when present), and may eventually lead to shutting off production. The magnitude of the problem can be gauged from the example of the Lasmo oil field in the United Kingdom, which had to be abandoned because of recurring paraffin plugging problems at a cost of over $100 million U.S. According to the U.S. DOE, remediating pipeline blockages in water depths of about 400 m can cost $1 million/mile U.S.1 As reported by Elf Aquitaine, at least 17 pipelines were plugged in the Gulf of Mexico alone in 1994, and this number has increased since. Thus, paraffin deposition is a critical problem that calls for a fundamental understanding of the mechanisms involved. Prediction of the location, amount, and characteristics of the paraffin deposits is imperative for selecting and designing an appropriate remediation or deposit removal technique.
The deposit formed on the pipe wall is not purely solid wax, but is in the form of a gel consisting of a network of solid wax crystals, which traps a large amount of oil (as much as 95% or more) inside. This gel deposit grows in thickness and also ages with time because of the diffusion of the wax molecules from the oil flowing in the bulk toward the cold wall.2 Thus, the radius available for the flow of oil decreases with time, reducing flow efficiency. Buildup of thick wax deposits may force production shutdowns. Paraffin deposition has been experimentally studied using a laboratory flow loop to develop a comprehensive theoretical model that successfully predicts single-phase paraffin deposition and aging.3 The rate of buildup and aging of the deposit depends, among other factors, on the composition of the incipient deposit (i.e., the solid wax content of the deposited gel). The solid wax content of the incipient gel deposit, in turn, is determined by the wall temperature and the thermal and shear histories imposed on the oil. The solid wax content of the gel formed on the walls of the pipeline can be predicted by studying the gelation of the given oil using a rheometer. 4 It is to be noted that the deposition process involves the gelation of wax-oil mixtures under conditions of shear stress exerted by the oil flow.
Another problem associated with paraffin precipitation is that of restart. When an emergency production shutdown occurs, the result is gelation of the oil that remains stagnant in the cold pipeline because of temperature reduction that causes wax precipitation. In this case, the entire pipe may be plugged, and restarting the flow would require the breaking of the paraffin plug. When dealing with the restart problem, it is necessary to estimate the pressure required to break down the plug of wax-oil gel. It should be noted that, in this situation, the waxy oil gels under quiescent (no flow) conditions, unlike the case of gel deposition under flow.
This article addresses one of the most important concepts in the study of the paraffin deposition phenomenon, namely the gelation temperature. The article points out the significance of using the gelation temperature when dealing with the dynamic wax deposition process, and compares it to the pour point temperature, the use of which is limited to the description of static gelation of waxy oils.
To elucidate the concepts of this article, pour point and rheological experiments were carried out on a model wax-oil system. The model wax used was food-grade paraffin wax with a carbon number distribution of C22 to C39. Fig. 1 shows the carbon-number distribution of the paraffin wax. The model oil solvent used to dissolve the paraffin wax was a mineral oil normally used as a viscosity standard (N10 standard from Cannon Instruments Co.®). At 25°C, the oil viscosity was 14.8 cp and the density was 0.857 g/ml. A 5% wax-in-oil mixture was used for the experimental studies. A controlled stress cone-and-plate rheometer (TA Instruments ® AR1000) was used for the rheological experiments.
The Cloud Point, Pour Point, and Gelation Temperature
High molecular weight paraffins (waxes) precipitate out of the crude oil when the temperature of the oil drops below the theoretical value of the cloud point temperature (determined thermodynamically), which is the solubility limit. It is to be noted that the experimentally determined value of the cloud point, or the wax appearance temperature (WAT), is usually lower than the theoretical value because a finite amount of precipitate is required for detection. Under conditions of equilibrium cooling, wherein the cooling rate applied on the waxy oil is lower than the rate of precipitation, the experimentally determined cloud point could compare closely to the theoretical value.
As the crude oil flows through the cooled pipeline, its temperature drops even below the cloud point; therefore, more precipitation occurs. Some of the precipitated waxes deposit on the pipe walls in the form of a wax-oil gel (i.e., the deposit consists of a network of solid wax crystals that traps some liquid oil inside). The gelation of the waxy crude is because of the flocculation of orthorhombic wax crystallites that appear in the solution during cooling.5 Observations under a cross-polarized microscope have revealed that the crystallites have structures of platelets that overlap and interlock.6 The overlapping paraffin platelets trap the oil inside them.
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