Wax precipitation in crude oils can produce problems in production and transportation operations. A novel FT-IR spectroscopy method is described for the determination of the wax precipitation temperature (WPT), and the estimation of the amount of precipitated solid wax material (both crystalline and amorphous) present in petroleum crude oils. A reference model oil system is analyzed using the described method. Comparisons are provided between FT-IR generated data and data generated using conventional analyses for Alaska North Slope, Utah, and Gulf of Mexico crude oils. The FT-IR method is shown to provide comparative results with conventional analysis methods, and offers several advantages over existing test methods.

Knowledge of certain properties of a crude oil such as saturates, aromatics, resins, and asphaltenes (SARA) contents, Conradson carbon residue (CCR), ultimate analysis (CHNS), density, and molecular weight (MW) is useful for the characterization of the oil. Multivariate statistics combined with near-infrared (NIR) spectroscopy can be a powerful tool to rapidly and accurately predict these properties. Twenty-two crude oil fractions, from Alaska North Slope (ANS), the western United States (Utah, Colorado, and Wyoming), and Venezuela were used in this study. Eleven of these samples were C25+ residual fractions while the rest were C12+ residual fractions. The objective was to develop chemometric prediction models to predict the properties of unknown fractions using a single NIR spectrum. The SARA components (HPLC), molecular weights, densities, hydrogen-to-carbon (H/C) ratios, weight percent (wt %) nitrogen, weight percent sulfur (from CHNS analysis), and weight percent Conradson carbon residue (CCR) were measured. The NIR spectra for these fractions were obtained at 20 °C. Principal component analysis (PCA) and partial least-squares (PLS) techniques were used to analyze and correlate the spectra to the measured properties. Linear correlations with R 2 values greater than 0.99 were obtained for all properties studied. The uncertainty in experimental measurements for all the properties studied was comparable with the uncertainty in predictions by the models of the respective property. Furthermore, the models were tested using samples that did not belong to the calibration set. The properties predicted for these samples were within the range described by the experimental error for the respective property.

Wax precipitation and deposition in crude oils can produce problems in production and transportation operations. To gain an understanding of deposits formed in a pipeline transporting an intermediate type crude oil in an arctic/subarctic environment, comparisons of several types of crude oil solid deposits from the Trans Alaska Pipeline System (TAPS) and precipitated waxes present in the TAPS mix crude oil were developed. An extended high-temperature gas chromatography (HTGC) method was used for the determination of the solids composition, and is described in this paper. The HTGC method uses a longer capillary column to obtain improved resolution of higher carbon number groups. The method also provides quantification of n-alkane and non-n-alkane content within each single carbon number group. A comparison of the ratio of n-alkane: non-n-alkane for each single carbon number (SCN) between the parent crude oil and the crude oil solids is used to identify the amount of liquid crude oil occluded in the crude oil solid. A reference wax is analyzed using the described method to demonstrate the precision and accuracy of the method.

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It is estimated that about a third of the total gas produced from the prolific Bakken Formation, amounting to about 250 million standard cubic feet (MMSCF)/day, is either vented or flared. The gas flared in the Eagle Ford formation in Texas is also of the order of 100 MMSCF/day. The main target in these plays is liquid (oil and condensate), and the associated gas is flared or vented. Any liquid production from shale will ultimately involve surface production facilities for stabilization, treatment, and transport of produced fluids. The design and operation of the surface production facilities affect the amount and quality of the liquid produced and significantly affect the amount of gas vented. In this paper, we show that using a two-stage design improves liquid quality while reducing venting rates by up to 70%. The two-stage operation will require additional infrastructure and cost upfront but will yield considerable technical and environmental benefits and move tight oil production to a more sustainable operation. The impact of operational change in surface facility and wellhead on the sub-surface flow is also investigated in this study by simulating a conventional condensate process flowsheet with Eagle Ford fluid. Major pressure drops occur in the vertical section of the well and in the wellhead choke valve, where a change in the flow regime is observed. Up to 10% liquid fallout inside the reservoir causes a loss of production and creates a condensate bank near the wellbore, hindering the gas flow.