KAT offers a suite of analyses to characterise crude oil and gas condensate samples and help assess the potential impact on production operations.
Separates the test fluid into four solubility classes: Saturate (Paraffin), Aromatic, Resin, and Asphaltenes using the Iatroscan technique [a semi-automated, modified form of thin layer chromatography].
Separation of the SAR fractions from the Asphaltenes is achieved by using a series of solvents of differing polarity (non-polar for the saturates, increasing polarity for the aromatics and resin fractions). Once separated, analysis of all the different fractions is performed using flame ionisation detector (FID).
Asphaltene Content [Modified IP143]
Determines the mass percent of asphaltenes as defined by insolubility in n-heptane solvent. It is applicable to all solid and semi-solid petroleum asphalts containing little or no mineral matter, to gas condensates and heavy fuel oils.
Wax Content [UOP46 / BP237]
Determines the mass percent of material precipitated when a solution of asphaltene free crude is dissolved in dichloromethane and cooled to -32°C [-25.6°F].
C36+ Hydrocarbon Composition
The hydrocarbon distribution within black oils and gas condensates can be determined using a gas chromatograph [GC] equipped with a non-polar capillary column, and a flame ionisation detector. Components up to C9 may be individually resolved and quantified but species beyond nC9 are usually reported as pseudo-components.
Extended n-Paraffin Composition
Resolves the complete n-paraffin distribution of a crude oil or gas condensate and/or their deposited fractions both quantitatively and qualitatively. It is accepted as the industry standard for compositional characterisation of waxes and provides a key input to simulation and correlation tools for thermodynamic, rheological, and depositional predictions. The use of T-SEP® , a proprietary enhanced sample preparation technique allows, on average, an additional 20 carbon numbers to be observed and accurately measured.
Arsenic and Lead by ICP and ICP-MS analysis. Mercury by AA [UOP938/IP594/ASTM D7622]. Sulphur, Nickel and Vanadium by XRF.
Total Acid Number [IP77/D664]
The measurement of acidity as determined by the amount of potassium hydroxide in required to neutralise one gram of test fluid. The TAN value indicates the potential for corrosion problems.
Density [IP365] & API Gravity
Measurement of how heavy or light a petroleum liquid is.
API gravity is an inverse measure of a petroleum liquid’s density relative to that of water [specific gravity]. API gravity values of most petroleum liquids fall between 10 and 70 degrees. If API gravity is greater than 10, the fluid floats on water; if less than 10, it is heavier and sinks.
Kinematic Viscosity [IP71]
The dynamic viscosity of a fluid per unit density.
Sulphate, Bromide and Nitrate by Ion Chromatography. Organic acids by Ion Exchange. Multi-element/cation analysis by ICP-OES. Chloride by potentiometric titration. pH and Resistivity.
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…
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…
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…
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…
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…
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…
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…
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…
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,…
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 /…