Comparative Compositional Study of Crude Oil Solids from the Trans

Comparative Compositional Study of Crude Oil Solids from the Trans Alaska Pipeline System Using High-Temperature Gas Chromatography. R. M. Roehner* ...
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Energy & Fuels 2002, 16, 211-217

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Comparative Compositional Study of Crude Oil Solids from the Trans Alaska Pipeline System Using High-Temperature Gas Chromatography R. M. Roehner,* J. V. Fletcher, and F. V. Hanson University of Utah, Department of Chemical & Fuels Engineering, Merrill Engineering Building, Room 3290, Salt Lake City, Utah 84112

N. F. Dahdah University of Utah, Energy & Geoscience Institute, 423 Wakara Way, Suite 150, Salt Lake City, Utah 84108 Received August 16, 2001. Revised Manuscript Received November 1, 2001

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.

Introduction The Trans Alaska Pipeline System (TAPS) currently transports approximately 1 million barrels per day of a co-mingled blend of crude oils produced on the Alaskan North Slope.1 This blend is commonly referred to as Alaska North Slope (ANS) crude oil, and is referred to here as TAPS mix crude oil. The TAPS mix crude oil can be classified as an intermediate-type crude oil, based on a Watson Characterization Factor2 of 11.5 obtained from a traditional True Boiling Point (TBP) analysis3 of the TAPS mix crude oil given in Table 1. This crude oil was found to have a wax precipitation temperature (WPT) of 25 ( 1.0 °C using both cross-polarized microscopy and a novel FT-IR spectroscopy technique.4,5 Since this measured WPT is well above the 16 °C current * Author to whom correspondence should be addressed at Alyeska Pipeline Service Company, 8670 South Snow Mountain Drive, Sandy, UT, 84093. E-mail: [email protected]. Tel: (801)5859488. (1) Williams, B. The New Era Dawning For Alaskan North Slope. Oil Gas J. August 6, 2001, p 59. (2) Gary, J.; Handwerk, G. Petroleum Refining Technology and Economics, 3rd ed.; Marcel Dekker: New York, 1994; p 26. (3) ASTM D 2892. Annu. Book STM Stand. 2001, 05.02, 222-249. (4) Roehner, R. Measurement and Prediction of Wax Precipitation for Alaska North Slope Crude Oil Transported in the Trans Alaska Pipeline System. Ph.D. Dissertation, University of Utah, Salt Lake City, Utah, August 2000. (5) Roehner, R.; Hanson, F. Determination of Wax Precipitation Temperature and Amount of Precipitated Slid Wax versus Temperature for Crude Oils Using FT-IR Spectroscopy. Energy Fuels 2001, 15 (3), 756-763.

typical delivery temperature to the pipeline terminus at the Valdez Marine Terminal (VMT),6 the deposition of solid wax would be anticipated to occur in areas of the pipeline where large thermal gradients exist at the pipe-wall, on the basis of previous literature studies.7-9 These large thermal gradients can be shown to exist in direct buried sections of the pipeline which are not insulated and located in riverbeds, where moving groundwater just above freezing can contact the pipe. The operator of TAPS, Alyeska Pipeline Service Company, currently uses scraper pigs to remove solid wax deposits from the 800 mile pipeline on a weekly basis.10 The pipeline solids obtained from these pigging operations, the solids obtained from tank bottoms (assumed to be settled solids), and floating solid wax obtained from a VMT Ballast Water Treatment (BWT) tank were compared using high-temperature gas chromatography (HTGC) with thermally precipitated solids obtained from the parent TAPS mix crude oil. (6) Operational data supplied by Alyeska Pipeline Service Company, Systems Engineering. (7) Burger, E.; Perkins, T.; Striegler, J. Studies of Wax Deposition in the Trans Alaska Pipeline. J. Petr. Technol. 1981, 1075-1086. (8) Singh, P.; Venkatesan, R.; Fogler, H.; Nagarajan, N. Formation and Aging of Incipient Thin Film Wax-Oil Gels. AICHE J. 2001, 46 (5), 1059-1074. (9) Singh, P.; Venkatesan, R.; Fogler, H.; Nagarajan, N. Morphological Evolution of Thick Wax Deposits during Aging. AICHE J. 2001, 47 (1), 6-18. (10) Operational data supplied by Alyeska Pipeline Service Company.

10.1021/ef010218m CCC: $22.00 © 2002 American Chemical Society Published on Web 12/12/2001

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Table 1. TBP Characterization of ANS Crude Oil component

mol %

MW (g/mol)

H2S CO2 C1 C2 C3 i-C4 n-C4 neo-C5 i-C5 n-C5 C6 C7 C8 C9 C10 C11 C12 C13 C14 C15 C16 C17 C18 C19 C20 C21 C22 C23 C24 C25 C25+

0.00 0.01 0.00 0.07 0.66 1.25 4.33 0.03 2.11 3.17 2.17 8.93 9.29 6.91 5.70 6.12 2.21 3.65 4.49 3.66 2.86 2.74 2.44 2.17 1.40 2.35 1.61 1.41 1.32 1.38 15.56

34 44 16 30 44 58 58 72 72 72 89 97 100 113 126 138 153 162 174 179 192 208 216 234 241 252 263 285 304 307 555

Total

100.00

F 15.5 °C (g/cc)

0.6773 0.7340 0.7576 0.7759 0.7897 0.8064 0.8287 0.8335 0.8490 0.8609 0.8672 0.8710 0.8780 0.8846 0.8981 0.9015 0.9062 0.9085 0.9108 0.9138 0.9851

Background High-temperature gas chromatography (HTGC) using capillary columns11 now provides quick qualitative identification of n-alkanes present in waxes up to C90. Standardized quantification of carbon number distributions in petroleum waxes is limited to C44 per ASTM D 5442-93.12 Thermally precipitated solids can be obtained from crude oils via centrifuging chilled crude oil samples,7 filtering chilled crude oil samples,13,14 or by contacting the crude oil with a cold surface.15 Solids obtained from contact with cold surfaces introduce heat transfer effects and related diffusional mass transfer effects which might result in solids different from those formed from bulk cooling of the crude oil. Crude oil solids have been investigated for composition with gas chromatography by several groups of researchers. Burger, Perkins, and Striegler7 investigated wax, which could potentially be deposited from Prudhoe Bay crude oil in TAPS during startup by precipitating wax using a cold ether/acetone filtration technique. The solid collected from this precipitation (11) Gupta, A. K.; Severin, D. Characterization of Petroleum Waxes by High-Temperature Gas ChromatographysCorrelation with Physical Properties. Petrol. Sci. Technol. 1997, 15, 943-957. (12) ASTM D 5442. Annu. Book ASTM Stand. 2001, 05.03, 418423. (13) Hansen, J. H.; Fredenslund, A.; Pedersen, K. S.; Ronningsen, H. P. A Thermodynamic Model for Predicting Wax Formation in Crude Oils. AICHE J. 1988, 34, 1937-1942. (14) Weingarten, J. S.; Euchner, J. Methods for Predicting Wax Precipitation and Deposition. SPE 15654, 1986. (15) Deo, M.; Wavrek, D. A. Wax Precipitation: Compositional Study and Cloud Point Measurements. Presented at 2nd International Symposium on Colloid Chemistry in Oil Production, SPE, Rio de Janeiro, 1997; paper 29.

represented the total wax of the crude oil, and was found from conventional GC analysis to contain less than 50wt % of paraffin materials. The remaining material would not elute from the GC column and most likely included resin and asphaltene materials precipitated by the addition of excess acetone. Irani et al.16 used methylethyl ketone (MEK) as a solvent to precipitate total wax from a dozen crude oils. The waxes obtained were then analyzed via HPLC to separate them into saturate, aromatic, polar, and hexane-insoluble fractions and by GPC to obtain carbon number/molecular size distributions. They also used a centrifuge to separate waxes formed by thermal precipitation at different temperatures and performed the same HPLC procedure on each wax fraction. Ronningsen et al.17 filtered wax from a North Sea condensate at several different temperatures below the WPT and performed HTGC-Mass Spectrometry (HTGC/ MS) according to ASTM D 278618 on each wax. They indicated that occlusion of liquid-phase material was likely during filtration and that they were unable to fully characterize each wax since the HTGC/MS method was limited to C40 in carbon number quantification. Because of the limitation of the HTGC/MS method, they only provided qualitative identification of hydrocarbons present. Fazal et al.19,20 analyzed tank sludge formed from the paraffinic Bombay High crude oil and found the sludge to be more paraffinic than its parent crude oil. The researchers used an initial vacuum distillation to produce six different fractions (after initial water removal) as follows: IBP to 300 °C, 300-350 °C, 350-400 °C, 400-450 °C, 450-500 °C, and 500 °C+ residue. Each fraction, except the residue, was analyzed using urea adduction with GC determination of saturate carbon number distribution. Gupta and Severin21 used HTGC/FID and supercritical fluid chromatography to obtain carbon number distributions for two Indian crude oil waxes. The GC results obtained were qualitative in nature as no internal standard was mentioned as being used and average carbon numbers for each wax were determined on the basis of relative peak areas. Deo and Wavrek15 used HTGC/MS methods previously described by Wavrek and Dahdah22 to qualitatively demonstrate that the composition of crude oil solids obtained from deposition on cold surfaces as (16) Irani, C.; Schuster, D.; Yin, R. Understanding The Pour Point Depression Mechanism - I. HPLC And GPC Analysis of Crude Oils. II. Microfiltration Analysis of Crude Oils. Preprints of Papers Presented at Miami Beach, FL, April 28 - May 3, 1985. Prepr. Pap.sAm. Chem. Soc., Div. Fuel Chem. 1985 30 (1), 158-177. (17) Ronningsen, H. P.; Bjorndal, B.; Hansen, A. B.; Pedersen, W. B. Wax Precipitation from North Sea Oils. 1. Crystallization and Dissolution Temperatures, and Newtonian and Non-Newtonian Flow Properties. Energy Fuels 1991, 5, 895-908. (18) ASTM D 2786. Annu. Book ASTM Stand. 1989, 05.02. (19) Fazal, S.; Zarapkar, S.; Joshi, G. Studies on Sludge from Storage Tank of Waxy Crude Oil, Part-I: Structure and Composition of Distillate Fractions. Fuel Sci. Technol. Int. 1995, 13, 881-893. (20) Fazal, S.; Zarapkar, S.; Joshi, G. Studies on Sludge from Storage Tank of Waxy Crude Oil, Part-II: Solvent Fractionation. Fuel Sci. Technol. Int. 1995, 13, 1239-1249. (21) Gupta, A. K.; Severin, D. Characterization of Petroleum Waxes by High-Temperature Gas ChromatographysCorrelation with Physical Properties. Petrol. Sci. Technol. 1997, 15, 943-957. (22) Wavrek, D. A.; Dahdah, N. F. Characterizations of High Molecular Weight CompoundssImplications for Advanced-Recovery Technologies. SPE 28965, 1995, 207-212.

Crude Oil Solids from the Trans Alaska Pipeline System Table 2. HTGC Operating Parameters column (length × ID × film thickness) stationary phase (film) initial oven temperature final oven temperature oven ramp rate carrier gas flow carrier gas velocity inlet temperature detector temperature detector flows (mL/min) a

Restek MXT-1, steel-coated fused silica capillary (30 m × 0.28 mm × 0.1 µm) 100% dimethyl polysiloxane (non-polar) 70 °C, no isothermal hold 410 °C, 11 minute hold 10 °C per minute helium, 1mL per minute constant 23 cm per second oven track mode (maintain 3 °C above oven temp.) 450 °C zero-aira (450), H2, He (45)

Energy & Fuels, Vol. 16, No. 1, 2002 213 Table 3. Results of Replicate Analyses for the HTGC-LCS wt % replicate no.

n-C20

n-C40

n-C40

n-C50

n-C60

0.0101 0.0101 0.0101 0.0101 0.0100 0.0101 0.0101 0.0101 0.0101 0.0102 0.0101

0.0102 0.0102 0.0102 0.0102 0.0102 0.0102 0.0103 0.0102 0.0101 0.0101 0.0101

0.0098 0.0098 0.0098 0.0098 0.0099 0.0098 0.0098 0.0098 0.0097 0.0097 0.0097

0.0050 0.0050 0.0050 0.0050 0.0050 0.0049 0.0049 0.0050 0.0050 0.0051 0.0051

0.0009 0.0009 0.0008 0.0008 0.0008 0.0009 0.0009 0.0009 0.0010 0.0010 0.0010

av 0.0101 0.0102 SD 5.4E-05 6E-05 RSD 0.53 0.59 known value 0.0100 0.0100 biasa(%) -0.91 -1.82

0.0098 7E-05 0.72 0.0100 2.09

0.0050 0.0009 6.3E-05 7.7E-05 1.26 8.61 0.0050 0.0010 0.00 10.00

1 2 3 4 5 6 7 8 9 10 11

Pure air.

described by a SCN distribution is dependent upon bulk oil temperature and cold surface temperature. The Deo and Wavrek study15 also showed a difference in SCN distribution obtained by HTGC analysis of a solid deposit obtained from a pipeline versus a solid deposit created in a coldfinger experiment from the same crude oil. Experimental Section The HTGC procedure used was co-developed by the Energy and Geoscience Institute and the Department of Chemical and Fuels Engineering at the University of Utah. The procedure provides the total weight percent of a given single carbon number (SCN), and the weight percents of the n-alkane and the nonn-alkane components for each SCN. It utilizes a longer column length in comparison with existing standardized HTGC procedures to obtain better resolution at higher carbon numbers. The procedure produces quantitative determination ((10% RSD) of SCN weight percents to C60, well beyond the limit of C44 given for the comparable ASTM procedure.12 Sampling. All pipeline pigging solids were obtained within the same year as the crude oil and the crude oil storage tank bottoms were collected approximately one year after the pipeline solids samples. The samples tested included solids obtained from the following sources: • Centrifugation of chilled (21, -1, -18, -34 °C) TAPS Mix Crude Oil obtained from the discharge of Pump Station 1 (comingled ANS production). • Pipeline solid deposits obtained from pigging operations (solids were removed from the body of a scraper pig). • Pipeline crude oil breakout (pressure relief) tank bottoms at Pump Station 9 (Tank 190). • VMT crude oil storage tank bottoms (Tank 3 and Tank 16). • VMT Ballast Water Treatment tank floating wax (Tank 94). Crude oil solid samples were refrigerated in sealed containers fitted with Teflon lids. These sample containers were purged with standard grade nitrogen prior to sealing to prevent oxidation. HTGC Instrumentation. All analyses were conducted on a HP 6890 GC with electronic pressure control, cool on-column inlet, HP automatic liquid autosampler, and a FID detector. A summary of the GC operating conditions is presented in Table 2. Two samples were prepared for each crude oil solid analyzed. The first sample was dissolved in cyclohexane and briefly sonified to ensure that it was completely solvated. SIMDIS-IS internal standard (HP Part No. 5080-8723) was added to the second sample. The integrated area values were used to calculate a theoretical total peak area for each sample

a Bias calculated as [(known value - av)/known value] × 100%.

according to methodology used outlined in ASTM D 5307,23 and described by Deo and Neer.24 The procedure distinguishes between n-alkane and non-n-alkane portions of each SCN through the use of a retention time table. The retention time table is developed by analyzing a laboratory standard containing normal paraffins ranging from n-C9 through n-C60. Philp et al.25 recognize a bias in GC response unfavorable to high molecular weight hydrocarbons (HMWHC) as shown with a standard sample of equal concentrations of n-alkanes n-C20, n-C30, n-C40, n-C50, and n-C60. They attributed the bias in large part to the poor solubility of HMWHCs. As a demonstration of capability of the HTGC method used in this study, analysis of 11 replicates taken from a custom mixture purchased from Supelco containing n-C20, n-C30, n-C40, n-C50, and n-C60 in cyclohexane (0.010, 0.010, 0.010, 0.005, and 0.001 wt %, respectively) was performed. The results for these 11 replicates produced similar values for RSD and bias for each SCN weight percent, and are provided in Table 3. This custom mixture was adopted as the laboratory control standard (LCS) for the HTGC procedure. Prior to the analysis of sample batches, the replicate LCS comprised of the custom mixture of n-C20, n-C30, n-C40, n-C50, and n-C60 (all 99%+ purity) in cyclohexane was analyzed to verify GC performance. Data were collected only if the LCS results met the specification for repeatability previously demonstrated (SCN wt % ( 10% RSD). The GC column head was trimmed after 4 to 6 analyses of crude oil or crude oil solids (two runs eachssample and sample plus SIMDIS-IS). The solid samples analyzed were not subjected to homogenization and no attempt was made to determine solid sample variability in terms of SCN distribution by GC. HTGC Method Calculations. The presence of occluded oil in the produced solid samples precludes exact determination of the precipitated solid wax content. Occluded oil is also known to be present in pipeline solids and settled tank bottoms. The occluded oil content of centrifuge solids, pipeline deposits, and tank bottoms can be corrected for occluded oil using HTGC analysis by comparing HTGC results for the (23) ASTM D 5307. Annu. Book ASTM Stand. 2001, 05.03, 398404. (24) Deo, M. D.; Neer, L. A. Simulated Distillation of Oils with a Wide Carbon Number Distribution. J. Chromatogr. Sci. 1995, 33, 133138. (25) Philp, R. P.; Bishop, A. N.; del Rio, J. C.; Allen, J. In Characterization of High Molecular Weight Hydrocarbons (>C40) in Oils and Reservoir Rocks. Cubitt, J. M., England, W. A., Eds.; The Geochemistry of Reservoirs, Special Publication No. 86; Geological Society, 1995; pp 71-85.

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Figure 1. TAPS mix crude oil centrifuge solid at 21 °C HTGC chromatogram.

Figure 2. October TAPS pipeline pig wax HTGC chromatogram. parent crude oil and the associated solid. The carbon number (CN) in the solid where the n-alkane/non-n-alkane ratio drastically increases in comparison with the ratio present in the crude oil is taken as the start of the solid, and the wt % values below that carbon number are totaled as occluded oil. Laboratory Wax Precipitation. An estimation of precipitated solid wax content in a crude oil at temperatures below the crude oil WPT can be obtained by centrifugation of chilled crude oil samples.7 Details of the equipment and methodology used in this study are provided in the Appendix. Centrifugation of crude oil samples was conducted at Westport Technology Center International in Houston, TX. Solid samples were retained in sealed containers, purged with nitrogen prior to sealing for subsequent analysis by HTGC.

Results of Crude Oil Solids Analyses Figures 1 through 3 provide the chromatograms for the TAPS Mix Crude Oil Centrifuge Solid at 21 °C (U0047), October Pipeline Pig Solid (U0005), and VMT Tank 16 (U0130), respectively. Figures 4 through 9 provide data analysis plots for the TAPS Mix Crude Oil, TAPS Mix Crude Oil Centrifuge Solid at 21 °C (U0047), October Pipeline Pig Solid (U0005), VMT Tank 16

(U0130), VMT BWT Tank 94 floating solid wax (U0216), and TAPS Mix Crude Oil Centrifuge Solid at -1 °C (U0069), respectively. Comparison of Figures 4 and 5 illustrates the criteria used to identify what portion of the sample is considered to be solid, and what is considered to be occluded oil. The TAPS Mix Crude Oil data plotted in Figure 4 show a n-alkane/non-n-alkane ratio which is fairly constant, while the Centrifuge Solid data plotted in Figure 5 show a drastic increase in the n-alkane/non-n-alkane ratio. On the basis of this observed difference, the identification of the start of the solid phase involved locating the carbon number (CN) where the n-alkane/non-n-alkane ratio drastically increased. The wt % values below that carbon number were totaled as occluded oil. It is evident from Figures 5 through 10 that these solids were generated from thermal precipitation of solid wax over the temperature range of 25 °C (the wax precipitation temperature measured for TAPS mix crude oil at PS1) to -1 °C. Decreasing crude oil temperature reduces the starting carbon number as well as the peak carbon number of the crude oil solid formed. The centrifuge solids at 21 °C and -1 °C bracket the pig and tank bottoms solids,

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Figure 3. VMT TK 16 tank bottoms HTGC chromatogram.

Figure 4. HTGC data analysis plotsTAPS mix crude oil.

both in terms of starting and peak carbon numbers as shown in Table 4. In general, tank bottom solids formed in low shear environments contain higher amounts of occluded oil in comparison with solids removed from the pipeline by pigging which formed in high shear environments. However, comparison of Figure 10 (Data Analysis Plot for TK 190 Solids (U0295)), with Figure 6 (Data Analysis Plot for October Pipeline Pig Solid (U0005)), shows the TK 190 solid to actually be pig wax. This observation was also exhibited in review of X-ray diffraction test data as will be discussed in a later paper. It should be noted that none of the VMT tank bottoms or BWT tank floating wax showed a comparable nalkane/non-n-alkane ratio (high ratio). Because of this, it is assumed that the Tank 190 solids tested were sent to the tank by open pressure relief valves as the mass of pig wax was pushed past Pump Station 9 by a scraper pig. HTGC analyses of pipeline pig wax solids collected in April and October of the sampling year at the VMT

Figure 5. HTGC data analysis plotsTAPS mix crude oil centrifuge solid at 21 °C (Sample U0047).

indicated a seasonal difference in the wax removed from the pipeline by pigging. This seasonal difference was also evident in DSC analysis of the same samples to be described in a later paper. As summarized in Table 4, the April wax samples exhibited higher start and peak carbon numbers than the October wax samples. This indicates that the April wax is comprised of higher molecular weight paraffin and would, therefore, be a “harder” wax. This trend can be explained by the concept that the majority of wax deposition occurs in direct buried sections of the pipeline, mostly in riverbeds, where “cold” (∼0 °C) groundwater lowers the pipewall temperature below the WPT (∼25 °C) of the transported crude oil. Due to seasonal lag in the arctic and subarctic environments, the October conditions would be anticipated to still have groundwater flowing around the pipe, while the April conditions would be anticipated to have no moving groundwater due to frozen conditions. Thus, the colder pipe wall in October would cause precipitation of lower molecular weight

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Figure 6. HTGC Data Analysis PlotsOctober TAPS pipeline pig wax (Sample U0005).

Roehner et al.

Figure 8. HTGC data analysis plotsVMT BWT TK 94 floating wax.

Figure 7. HTGC data analysis plotsVMT crude oil storage tank TK 16 (Sample U0130).

paraffin, creating a “softer” wax, and possibly increased wax deposition amounts. Conclusion Crude oil solids and waxes up to C60 can be analyzed by HTGC to determine n-alkane and non-n-alkane carbon number distributions. The n-alkane/non-n-alkane ratio can be used to estimate occluded oil in solids samples and to distinguish between certain types of crude oil solids. A tank bottoms solid shown to be pig wax provides information on sources of solids generation in the pipeline system. Acknowledgment. The authors acknowledge the support of Alyeska Pipeline Service Company for this research, which was conducted as part of the Trans

Figure 9. HTGC data analysis plotsTAPS mix crude oil centrifuge solid at -1 °C (Sample U0069).

Alaska Pipeline SystemsCrude Oil Studies Project (TAPS-COS). Core Laboratories performed the TBP analysis for TAPS mix crude oil. Westport Technology Center International in Houston, Texas, performed the centrifugation of the TAPS mix crude oil. The HTGC analyses were performed by the University of Utah, Energy and Geosciences Institute. Appendix A Beckman Instruments model J-6M induction drive centrifuge operating at 1500 rpm with a temperature-

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Energy & Fuels, Vol. 16, No. 1, 2002 217

Table 4. Summary of HTGC Analyses total (wt %) sample no.

a

description

carbon number (CN)

occluded oil

n-alkane

solid start

solid peak

U0047 U0069 U0075 U0082

TAPS Mix Crude Oil: centrifuge solid, 21 °C centrifuge solid, -1 °C centrifuge solid, -18 °C centrifuge solid, -34 °C

25.0 30.3 27.4 22.6

17.6 12.1 12.8 11.2

31 22 19 16

42 28 N/Aa N/Aa

U0005 062665-04

pig wax - October pig wax - April

20.0 27.0

39.0 43.1

28 32

38 42

U0216 U0130 U0199 U0295

VMT BWT TK 92 floating wax VMT Crude Oil TK 16 bottoms VMT Crude Oil TK 3 bottoms Pipeline Breakout TK 190 bottoms

22.8 33.9 37.3 31.3

28.3 21.6 21.8 30.0

25 28 28 30

40 38 40 40

No peak in SCN distribution observed.

standards. Samples for centrifuge testing were prepared by placing 250 mL of oil contained in a glass bottle with a pressure seal cap previously aliquoted from the parent sample. The oil was heated to 65 °C and held at that temperature for 1 h and then cooled to 38 °C for transfer into eight duplicate 50-mL centrifuge tubes. The filled centrifuge tubes were weighed and placed in a temperature-controlled water bath, which was monitored by the calibrated digital thermometer. The tubes were cooled to the centrifuge test temperatures (21, -1, -18, -34 °C) at a controlled rate while the centrifuge was equilibrated at the same test temperature. Once samples and centrifuge were at test temperature, the centrifuge tubes were placed in the centrifuge and spun for a minimum of 40 h at 1500 rpm. The liquid phase was decanted and each tube was swabbed to remove residual liquid. The tubes were re-weighed to obtain solid content by difference. Figure 10. HTGC data analysis plotsPipeline TK 190 solids (Sample U0295).

controlled centrifuge chamber was used to centrifuge the crude oil samples. The centrifuge speed was calibrated and cross-checked during testing using independent measurements from a precision tachometer mounted on the drive spindle and from a laser measuring device providing updated average values for centrifuge chamber rotation. Kimax 50-mL centrifuge tubes were used to hold the crude oil. Capping the tubes prevented loss of light ends during testing. Centrifugation of the samples at 1500 rpm produced an approximate gravity force of 450g. The temperature of the centrifuge chamber was recorded with a digital thermometer certified to (0.3 °C from -40 °C to 100 °C using NIST traceable

Nomenclature ANS ) Alaska North Slope APSC ) Alyeska Pipeline Service Company BWT ) Ballast Water Treatment HTGC ) high-temperature gas chromatography HMWHC ) high molecular weight hydrocarbons MS ) Mass Spectrometry PS1 ) Trans Alaska Pipeline System Pump Station No. 1 RSD ) relative standard deviation SD ) standard deviation TAPS ) Trans Alaska Pipeline System VMT ) Valdez Marine Terminal WPT ) Wax Precipitation Temperature EF010218M