Wax Deposition

The build-up of solid waxy layers onto cooled surfaces such as pipe walls is generally considered to be a temperature-dominated phenomenon. Several theories have been proposed to describe the effect and several commercial semi-empirical models have been developed to predict oil field deposition rates. However, it is generally agreed that to predict waxing and/or the performance of inhibitors it is important to measure deposition in a controlled series of tests.

Cold Finger / Plate Tests

KAT employs a series of stirred cold finger tests for rapid screening of inhibitors. The equipment comprises of cooled stainless-steel tubes or plates, each immersed in separate stirred samples of test fluid at ambient pressure.

The tests would be allowed to run for a pre-determined optimum duration after which time the cold fingers / plates are removed and digital images of any deposits formed recorded. A written description of the deposits, their tenacity, weight, and the levels of entrained fluid are also noted.

Having identified a suitable inhibitor its performance may be evaluated under more realistic temperature and flow conditions using the flow-loop methodology, described below.

Deposition Flow Loop

KAT employs a laboratory scale laminar flow loop to determine wax deposition rates of uninhibited and inhibited test fluids. Here the deposition rates are determined at a series of discrete temperature conditions approximating to positions of specific interest or expected high deposition within the operating system.

The flow-loop system has several advantages for assessing deposition which include control of flow and temperature conditions; real time monitoring of wax build-up rates; recovery of deposit for analysis, and realistic simulation of single-phase flow regimes where the velocity profile over the deposit can be readily matched to those across the laminar boundary layer [where the deposition is taking place] within most full-scale lines under turbulent flow conditions.

How it works

2L of hot oil is circulated through the pump and heat exchanger to deliver the fluid into the test section at the desired temperature. The wall temperature of the test section is independently set or adjusted to provide a deposition surface. Deposition rates are determined by equating the change in pressure drop across the deposition test section to a reduction in internal pipe radius using Poiseulles’ equation for Newtonian fluids in laminar flow. The oil is then returned to the hot reservoir via another heat exchanger to recondition the sample.

Deposits can be collected at the end of a test for inspection, confirmation of mass and/or further analysis. Alternatively, if sample volumes are limited then the fluid temperature can be elevated to melt the wax and reconstitute the fluid for reuse.

Wax deposition flow loop testing, in conjunction with characterisation of the waxes in the fluid by HTGC, provides the data required for deriving the Diffusion Coefficient Multiplier. The DCM is required for detailed wax deposition modelling and understanding of the wax deposition characteristics.

Fluid Analysis

KAT offers a suite of analyses to characterise crude oil and gas condensate samples and help assess the potential impact on production operations.SARA [latroscan]Separates the test fluid into four solubility classes: Saturate (Paraffin), Aromatic, Resin, and Asphaltenes using the Iatroscan…

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Asphaltenes are a natural constituent of many crude oils and may be precipitated in production systems when the crude’s natural solvency for them is reduced. Several factors including, pressure, temperature, and composition can change the stability of these high molecular…

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Foaming When produced and transported from the reservoir to processing facilities, fluids experience a drop in pressure. This will release dissolved gases that can cause the fluids to foam. Evolved gas is removed in a separator, but foaming can lead…

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Gas Hydrates

Gas hydrates are crystalline solids with cage-like structures [clathrates] in which a hydrocarbon molecule is enclosed in a lattice of water molecules. Although they have the appearance of ice or snow, gas hydrates crucially form at pressures and temperatures above…

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Oilfield Scale

Oilfield scale is the term used to describe deposits of insoluble inorganic minerals such as calcium carbonate, barium sulphate, and metal sulphides. In general, scale deposits occur when waters with different ion contents are mixed although pressure and pH can…

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Dynamic Viscosity Dynamic Viscosity vs. Temperature curves for assessing the flow behaviour of a waxy [Non-Newtonian] fluid are produced at a range of shear rates corresponding to typical production flowrates during normal steady-state pipeline flowing conditions. As such, each curve…

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Wax Appearance

Waxes are generally defined as paraffinic material with carbon numbers greater than nC17. Waxes are present in oil as a distribution of molecular weights and thus exhibit a range of solubilities, precipitating over a range of conditions. Precipitation is temperature…

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Wax Deposition

The build-up of solid waxy layers onto cooled surfaces such as pipe walls is generally considered to be a temperature-dominated phenomenon. Several theories have been proposed to describe the effect and several commercial semi-empirical models have been developed to predict…

Learn more
Arn Acids

Napthenate Solids Naphthenate solids are naturally occurring oilfield fluid scales formed from reactions between a specific group of high molecular weight cyclic naphthenic ARN acids, also known as Tetra Protic Acids or Tetra-Acids, with dissolved divalent cations [such as Ca,…

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Compared to the relatively high concentrations of nC10 – 20 in crude oils and gas condensates [analysed as unadulterated “Whole” sample] the concentrations of >nC30 can be relatively low and either close to or below the limit of detection /…

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