Energy & Fuels 2006, 20, 2457-2464
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Effect of Shear on the Performance of Paraffin Inhibitors: Coldfinger Investigation with Gulf of Mexico Crude Oils David W. Jennings* and Klaus Weispfennig Baker Petrolite, Oilfield Technology, 12645 West Airport BouleVard, Sugar Land, Texas 77478 ReceiVed May 16, 2006. ReVised Manuscript ReceiVed August 23, 2006
Paraffin inhibitors are chemicals that are used to reduce deposition of paraffin/wax onto surfaces of flow lines. For some crude oil production systems, paraffin inhibitors can provide significant reduction in wax deposition and be an economically attractive means for increasing production and/or decreasing wax remediation control costs. Paraffin inhibitors function by incorporating into wax deposit structures, altering the deposit structure in order to reduce the deposits’ ability to adhere. Generally, effective inhibitors create weaker deposits which are more susceptible to removal from shear forces in the flow field. As such, the performance of the inhibitors can be related to the shear forces present in respective flow streams. In this paper, results of coldfinger experiments using four Gulf of Mexico crude oils are presented to illustrate the effect of shear on inhibitor performance. Trends from the data indicate that inhibitor performance improves with increasing shear. From the test results, the percent inhibition in the amount of depositing wax (for inhibitor treated crude oil tests compared to untreated crude oil tests) was consistently observed to increase with increasing shear in the various experiments. The amount of coldfinger surface area bare of deposition was similarly found to consistently increase with increasing shear. The percent inhibition of the amount of total deposit weight (deposited wax with entrained crude oil) did not always increase with increasing shear thoughseven decreasing in many cases. This is not related to a reduction of inhibitor performance but rather due to variation in the untreated deposit reference with shear. As the amount of entrained crude oil in a deposit decreases with increasing shear, the percent change on the total deposit weight (deposited wax plus entrained crude oil) will vary for a paraffin inhibitor’s effect on a fixed amount of deposited wax species.
Introduction Waxes (also called paraffins) are natural constituents in all crude oils and gas condensates. Although the wax from petroleum is valued for use in many consumer products after being separated in the refining process, it is responsible for causing problems in some petroleum production operations. The severity of wax problems can range from being just nuisances to causing complete blockage and abandonment of wells and flow lines. Whether a production system will have wax problems and the potential severity depend on the following: (1) the chemistry of the crude oil, (2) production conditions, and (3) methods in place and/or available for managing wax. The amount and molecular weight distribution of waxes present in a crude oil are the predominant chemistry factors affecting the potential severity of wax deposition or other wax problems. Crude oils with high wax concentrations and/or wax distributions containing very high molecular weight waxes are particularly prone to having wax problems. Among production conditions, temperature is the primary driving force affecting wax problems. Wax deposition occurs when flow line surface temperatures are below the temperature at which waxes are soluble in the crude oil and a temperature gradient exists between the crude oil and the colder deposition surface. If the thermodynamic driving force for deposition is great, significant wax deposition can occur. In some cases, if not managed, wax deposition buildup can lead to reduced production and even complete blockage of flow lines. * To whom correspondence should be addressed. Tel.: 281-276-5603. Fax: 281-276-5805. E-mail:
[email protected].
Various preventative and remedial means are used to control wax deposition. These include mechanical, thermal, and chemical methodssor combinations thereof.1-11 The preferred control method will depend on the specifics of the field. Mechanical methods include pigging and cutting. Thermal methods include insulation and heating of flow lines to prevent deposition. (1) Lorimer, S. E.; Ellison, B. T. Subsea Oil System Design and Operation to Manage Wax, Asphaltenes, and Hydrates. Presented at the International Conference on Petroleum Phase Behavior and Fouling, 1999 AIChE Spring National Meeting, Houston, TX, March 14-18, 1999; paper 60C. (2) Carmago, R. M. T.; Gonclaves, M. A. L.; Montesanti, J. M. T.; Cardoso, C. A. B. R.; Minami, K. A Perspective View of Flow Assurance in Deepwater Fields in Brazil. Presented at the 2004 Offshore Technology Conference, Houston, TX, May 3-6, 2004; OTC 16687. (3) Wang, Q.; Sarica, C.; Chen, T. An Experimental Study on Mechanics of Wax Removal in Pipeline. Presented at the 2001 SPE Annual Technical Conference and Exhibition, New Orleans, LA, Sept 30-Oct 3, 2001; SPE 71544. (4) Volkert, B. C.; Shaw, M. N. The Cobia-2 Subsea Satellite Experience. Presented at the 1986 Offshore Technology Conference, Houston, TX, May 5-8, 1986; OTC 5315. (5) Feeney, S. Project Case Histories and Future Applications of Vacuum Insulated Tubing. Presented at the International Conference on Petroleum Phase Behavior and Fouling, 1999 AIChE Spring National Meeting, Houston, TX, March 14-18, 1999; paper 60d. (6) Hight, M.; Davalath, J. Economic Consideration for Flowline Heat Loss Control. Presented at the 2000 Offshore Technology Conference, Houston, TX, May 1-4, 2000; OTC 12036. (7) Brown, L. D.; Clapham, J.; Belmear, C.; Harris, R.; Loudon, A.; Maxwell, S.; Stout, J. Design of Britannia’s Subsea Heated Bundle for a 25 Year Service Life. Presented at the 1999 Offshore Technology Conference, Houston, TX, May 2-5, 1999; OTC 11017. (8) Esaklul, K. A.; Fung, G.; Harrison, G.; Perego, R. Active Heating for Flow Assurance Control in Deepwater Flowlines. Presented at the 2003 Offshore Technology Conference, Houston, TX, May 5-8, 2003; OTC 15188.
10.1021/ef0602170 CCC: $33.50 © 2006 American Chemical Society Published on Web 10/12/2006
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Chemical methods include paraffin inhibitors, dispersants, and solvents. Paraffin inhibitors are used to prevent deposition, and dispersants and solvents are generally used to remove existing deposits. At times, use of paraffin inhibitors can provide a practical economical means for managing wax deposition. Paraffin inhibitors are chemicals that incorporate into wax deposit structures and alter the deposit’s ability to cohesively adhere to surfaces or itself. Ideally, the inhibitor weakens the deposit allowing removal of the deposit by shear forces present in flow streams. Paraffin inhibitors are typically polymers in which the polymer structure contains wax-like portions that allow the molecule to incorporate into the wax deposit structure yet also has other structural features which alter and disrupt crystallization/network growth. The effectiveness of paraffin inhibitors depends on matching correct product chemistries at effective dose levels with the specific crude oil and its production conditions. Selection of inhibitors usually requires testing to determine the best products and required dose rates. Coldfinger and similar laboratory apparatuses are the most common methods used for evaluating paraffin inhibitors. These methods are preferred because screening of several product chemistries can be performed in short time periods and only small crude oil samples are required. Flow-loop testing is also sometimes performed. However, even with small loops, the manpower, time, and crude oil required to perform testing can be appreciably large. One drawback of some of the laboratory apparatuses (such as coldfingers) is that they can have significant different shear regimes than those present in some production operations. Generally, coldfingers operate in a lower shear regime than high rate production flow lines. However, as will be demonstrated in this paper, paraffin inhibitor performance generally increases with increasing shear forces present. As such, paraffin inhibitor evaluations with devices such as coldfingers can often be considered as conservative estimates of the expected field performancesprovided that other field conditions are properly simulated in the testing. Experimental Description Apparatus and Procedure. The apparatus and procedure have been described elsewhere,12 so only a brief description is given here. A schematic of the coldfinger devices used in this study is shown in Figure 1. Each device consists of two coldfingers connected to a circulating water bath. A modular design allows the interchangeability of two different coldfinger geometriesslarge and small. The large coldfingers are 3.34 cm in diameter, and the small coldfingers are 1.59 cm in diameter. The circulating water bath controls the temperature of each coldfinger. The actual coldfinger is centered within a glass jar assembly filled with crude oil. The coldfinger/jar assembly is placed inside a second water bath used to control the crude oil temperature. The crude oil (9) Pausche, M. P.; Creek, J. R.; Stair, M. A. Typhoon Project: Flow Assurances Issues - How They Were Identified and Resolved. Presented at the 2002 Offshore Technology Conference, Houston, TX, May 6-9, 2002; OTC 14053. (10) Marques, L. C. C.; Vieira, L. C.; Machado, A. L. C.; Oliveira, R. C. G.; Louvisse, A. M. T. A Field Case of Paraffin Deposition Control by Continuous Injection of Chemicals. Presented at the 1st International Symposium on Colloid Chemistry in Oil Production: Asphaltene & Wax Deposition, Rio de Janeiro, Brazil, Nov 1995. (11) Jennings, D. W.; Yin, R.; Weispfennig, K.; Newberry, M. Tratamento de Problemas com Agentes Quı´micos na Produc¸ a˜o de Petro´leo. Presented at Rio Oil & Gas Expo and Conference 2004, Rio de Janeiro, Brazil, Oct 4-7, 2004; IBP18904. (12) Jennings, D. W.; Weispfennig, K. Effects of Shear and Temperature on Wax Deposition: Coldfinger Investigation with a Gulf of Mexico Crude Oil. Energy Fuels 2005, 19 (4), 1376-1386.
Jennings and Weispfennig
Figure 1. Schematic diagram of the coldfinger apparatus.
temperature is regulated at the inside wall of the jar. A speedcontrolled magnetic stirring bar in the bottom of the coldfinger jar provides stirring which creates a helical decaying rotating flow field. The stirring rate dictates the shear stress at the coldfinger surface. The nominal operating stirrer speeds used are between 500 and 1000 rpm. Previously computation fluid dynamics modeling was performed to provide an estimate of the shear forces on the coldfinger surface. Though some uncertainty exists in the modeling due to the complexity of the helical decaying swirling flow field in the coldfinger setup, modeling indicated that the shear forces ranged from approximately 1-2 Pa.12 In performing tests, approximately 50 g of crude oil was used for each coldfinger. This loading was used to minimize decay in the shear forces at the top portion of the coldfinger. The crude oil was first conditioned above the wax appearance temperature (WAT) to completely solubilize any precipitated wax. Paraffin inhibitor was then injected (for treated samples) into the crude oil, dispersed, and allowed to sit for about 15 additional minutes at the conditioning temperature. The crude oil was then charged into the coldfinger jar. The jar was then placed around the coldfinger into the preheated water bath. The stirring was started and allowed to run for a predetermined timestypically 16 h. After this time, the coldfinger was removed from the water bath and jar. Surface oil was rinsedoff with cold methyl ethyl ketone. Visual assessments were made of the physical characteristics of deposits and photographs were taken for documentation. The deposit was then scraped from the finger, weighed, and saved for analysis. Crude Oils Studied. Results with crude oils from two different fields are presented in this paper: fields A and B. For the B field, samples from three different wells were used B1, B2, and B3. Hence, test results with four crude oils total are presented. The crude oils were all medium gravity crude oils from the Gulf of Mexico. Testing on crude oil A was performed with both large and small coldfinger geometries. The results presented here for this crude oil were from testing performed almost exclusively for illustrating shear effects on inhibitor performance. The B field crude oils from the different wells were similar in nature to each other with respect to crude oil chemistry, but they were not exactly the same. Also, the conditions of deposition studied for these samples varied slightly such that coldfinger test conditions mimicked as close as reasonably possible actual field production conditions. This was because the testing was performed primarily for actual inhibitor selection work. Later, some supplemental testing was performed to provide additional data for illustrating shear effects on inhibitor performancesas left-over sample permitted. Related to the fact that the testing was for actual inhibitor field selection, available sample sizes and timing commitments did not allow as extensive and controlled testing as with crude oil A. Nonetheless, it was desired to include results for crude oils B in this paper, as they showed, in some ways, different behavior than that of the results from crude oil A.
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Energy & Fuels, Vol. 20, No. 6, 2006 2459
Figure 2. Example of HTGC chromatogram of coldfinger deposit. Table 1. WAT and Test Conditions of Crude Oils crude oil
WAT (°F)
test bulk oil temp (°F)
coldfinger surface temp (°F)
differential temp (°F)
A B1 B2
115 110 112
B3
107
105 110 110 100 105
90 90 95 85 85
15 20 15 15 20
Testing on the B crude oils was solely with the small coldfinger geometry. Also, note that the data presented for the B crude oils are not for the optimum inhibitor performance selectionssas illustrating changes in performance is harder with highly effective treatments giving 90+% inhibition. Similarly, results for ineffective inhibitor treatments do not provide suitable data for illustrating changes in performance with shear either. Table 1 gives the WATs and coldfinger test conditions of the crude oils. Analyses of Wax Deposits. The total content of the coldfinger deposits consists of both wax species physically depositing and crude oil entrained within the deposit matrix. To determine the wax content of the coldfinger deposits, high temperature gas chromatography (HTGC) analyses were performed on the deposits. In the HTGC analysis method used, quantification of n-alkane peaks was accomplished using a valley to valley integration procedure. Unfortunately, with most real petroleum fluids, some baseline shift occurs in the chromatogram analysis due to species not completely resolved. The lack of complete resolution results in potential underaccounting of n-alkanes in the HTGC analysis.13 Also, nonn-alkanes are not accounted. For most crude oils, the n-alkanes account for the majority of wax. In some crude oils, however, nonn-alkanes can account for a significant portion of the crude oil wax. For the purpose of this study, these underaccounting analysis errors are approximately similar for the samples being compared (deposits from the same crude oil formed at similar coldfinger conditions), such that no significant bias of conclusions drawn from data would be expected. For crude oil A, the waxes were actually verified as predominantly n-alkanessverified by NMR analyses on wax isolated from a wet extraction method. The waxes in crude oils B1-B3 were not analyzed to check the relative concentrations of n-alkanes versus isoalkanes. An example of a wax deposit HTGC analysis is shown in Figure 2. It is a coldfinger deposit from crude oil A formed during an experiment run with stirring at 750 rpm without inhibitor. The carbon number chain length of the n-alkane peaks are labeled in the chromatogram. The “second hump”, which covers ∼C33-C65 chain lengths, results primarily from wax species “physically depositing” on the coldfinger. The majority portion of the n-alkane (13) Jennings, D. W.; Hager, H.; Weispfennig, K. Wax in Crude Oil: Analytical Methods and Their Uses for Flow Assurance. Proceedings of the Chemistry in the Oil Industry VIII Symposium, Manchester, U.K., Nov 3-5, 2003; pp 59-69.
peaks eluting before this hump are from wax in the entrained crude oil contained within the deposit. For the crude oil B deposits, similar wax distributions were observed. As such, the amount of C35+ n-alkanes was used to represent the amount of physically depositing wax for each of the crude oils.
Results and Discussion Crude Oil A. Results of coldfinger testing on crude oil A with five different paraffin inhibitor products are presented in Table 2. In the table, inhibitor performance is given as a function of stirring speed/shear rate. The amount of inhibition (for treated crude oil tests compared to untreated crude oil tests run under the exact same conditions) obtained for each product is given for the following: (1) total deposit weight and (2) C35+ n-alkane wax deposit weight.
wt % total inhibition ) (Wtref - Wtinh)/Wtref × 100 (1) wt % C35+ wax inhibition ) 35+ 35+ (Wtref‚x35+ ref - Wtinh‚xinh )/Wtref‚xref × 100 (2)
Where, Wtref ) the weight of reference coldfinger deposit from untreated crude oil,14 Wtinh ) the weight of coldfinger deposit from crude oil treated with paraffin inhibitor,14 x35+ ref ) the weight fraction of C35+ n-alkane wax in reference coldfinger deposit from untreated crude oil, and x35+ inh ) the weight fraction of C35+ n-alkane wax in coldfinger deposit from crude oil treated with paraffin inhibitor. Again, note that the total deposit includes both deposited wax and entrained crude oil and the C35+ n-alkane wax content covers the vast majority of physically depositing wax. An estimate of the amount of bare coldfinger is also included in Table 2. This also gives an indication of the inhibitor performance. Note that, in every case in Table 2, the amount of inhibition in the total weight of the deposit decreases with increasing shear as conditions went from 500 to 1000 rpm. This is not a reflection of a decrease in paraffin inhibitor performance though. Instead, it is simply a result of the amount of entrained crude contained within wax deposits decreasing with increasing shear forces present.12,15-19 This effect of shear on coldfinger deposition from untreated crude oil A is illustrated in Figures 3-5. In the figures, the amount of total deposit (wax and entrained crude oil), wax (14) In the actual calculations, weights per surface area of deposit were used. This nominalizes slight variations in the weight of crude oil charged in one experiment to another experiment. (15) Brown, T. S.; Niesen, V. G.; Erickson, D. D. Measurement and Prediction of the Kinetics of Paraffin Deposition. Presented at the 68th Annual Technical Conference and Exhibition of the Society of Petroleum Engineers, Houston, TX, Oct 3-6, 1993; SPE 26548.
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Table 2. Results of Paraffin Inhibitor Testing versus Shear Rate for Crude Oil A inhibitor
dose (ppm)
coldfinger
stirring rate (rpm)
wt % C35+ wax inhibition
wt % total deposit inhibition
∼ % bare surface
A
300
large
500 750 1000 500 750 1000 500 750 1000 500 750 1000 500 750 1000 500 750 1000 750 1000 500 750 1000 500 750 1000 500 750 1000 500 750 1000 500 750 1000 500 750 1000
43.8 49.8 62.0 30.8 49.6 44.5 53.3 73.3 76.0 41.7 57.7 58.0 56.6 46.1 58.9 15.8 40.8 53.5 66.9 65.6 35.0 29.9 36.0 6.8 16.3 27.8 55.7 25.1 55.3 25.5 19.7 44.4 1.8 24.5 6.2 -10.8 8.7 13.2
87.4 59.6 54.8 80.1 60.4 31.4 87.6 79.1 77.1 82.9 59.5 53.9 88.0 60.4 44.1 69.9 39.0 39.2 68.6 45.1 91.0 59.1 49.4 71.8 29.6 22.4 82.3 61.9 36.3 72.9 28.2 26.2 77.0 68.9 37.6 57.0 39.8 -0.8
12 38 50 40 60 50 40 55 85 45 50 50 0 0 38 18 35 65 70 70 0 20 20 10 25 30 2 3 22 9 15 45 0 1 2 1 1 1
small 350
large small
B
750
large small
C
1250
small
750
large small
D
750
large small
E
750
large small
content of the deposits, and the amount of deposited C35+ wax are shown, respectively, as a function of the stirring rate. The amount of total deposit and deposited C35+ wax are normalized on a weight per surface area basis in the figures. Duplicate test results (from different coldfinger devices) are shown for the small and large coldfinger geometries. As shown in Figures 3 and 4, respectively, the amount of total deposit weight decreases with increasing shear and the wax concentration increases. The net result from these two changes is that the amount of actual deposited wax (C35+ wax) is almost constant over increasing shear for the stirring rates studied. This is illustrated in Figure 5. A consequence of having less entrained oil in deposits at higher shear rates is that, for a reduction of a fixed amount of wax, a lesser amount of reduction in the total deposit weight will occur in higher shear conditions than lower shear conditions. How the percentage of inhibition on total deposit weight (treated crude oil compared to untreated crude oil) will change going from lower to higher shear conditions is uncertain as different (16) Lee-Tuffnell, C. A Laboratory Study of the Effects on Wax Deposition of Shear, Temperature and Live End Addition to Dead Crude Oils. Presented at the Symposium on Controlling Hydrates, Waxes, and Asphaltenes, Aberdeen, Scotland, Sept 16-17, 1996. (17) Dawson, S. G. B. Wax Deposition Modeling. Presented at the Symposium on Controlling Hydrates, Waxes, and Asphaltenes, Aberdeen, Scotland, Sept 16-17, 1996. (18) Lund, H. J. Investigation of Paraffin Deposition during Single Phase Liquid Flow in Pipelines. MS Thesis, The University of Tulsa, Tulsa, OK, 1998. (19) Venkatesan, R. The Deposition and Rheology of Organic Gels. Ph.D. Thesis, University of Michigan, Ann Arbor, MI, 2004.
Figure 3. Effect of shear on the amount of total deposition for coldfinger testing of untreated crude oil A.
untreated references exist for the different shear conditions. For the conditions studied for crude oil A, the trend is clearly a decrease in the percent inhibition in total deposit weight as shear was increased. As will be shown for the B crude oils, this is not always the case though. If one examines the effect of shear on paraffin inhibitor performance on the actual depositing wax in the crude oil A tests, a notable trend of increasing percent inhibition with increasing shear can be observed in the data in Table 2. If the percent inhibition of C35+ wax is examined for the different stirring rates for the different inhibitor products, the percent C35+ wax inhibition can be seen to increase fairly consistently (or at
Effect of Shear on Paraffin Inhibitors
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Figure 4. Effect of shear on wax content of deposits for coldfinger testing of untreated crude oil A.
Figure 6. (a) Effect of shear on inhibitor performance for C35+ wax inhibition in crude oil A testing with large geometry coldfingers. (b) Effect of shear on inhibitor performance for C35+ wax inhibition in crude oil A testing with small geometry coldfingers. Figure 5. Effect of shear on the amount of wax physically depositing for coldfinger testing of untreated crude oil A.
least is approximately the same) as stirring rates go from 500 to 1000 rpm. This is shown graphically in Figure 6 which illustrates the change in C35+ wax inhibition (eq 2) compared to the 500 rpm tests. The large coldfinger geometry results are shown in Figure 6a, and the small coldfinger geometry results, in Figure 6b. In Figure 6a, although three data points at 750 rpm showed a decrease in inhibition, the overall trend was of an increase in inhibition or no change. In Figure 6b, the trend of increasing inhibition with increased shear rate/stirring speed is more clearly evident. Except for one data point, all the data showed increased C35+ wax inhibition with increasing shear. Some of the scatter in the inhibitor testing may be due to experimental repeatability. The repeatability of the coldfinger experiments is nominally on the order of (10%. Periodically, results from tests on inhibited samples may fall outside this range though. The cause of periodic outliers is believed due to the nature of the inhibitor mechanism. In the inhibitor testing, inhibitor performance occurs as various portions of defective deposit (due to incorporation of the inhibitor) give way to the flow field shear forces. If, for whatever reason, the defective deposit portions do not yield/fail in the same consistent manner in each experiment, variations in results can be seen. Hence, there is sequential cause and effect relation that exists in the inhibition process which makes repeatability more challenging than, say, performing experimental measurements to determine fixed, defined physical or chemical properties. No individual inhibited tests were, however, repeated to confirm whether some of the negative percent change results in Figure 6a and b could be from a poor or unrepresentative
test result. Note that, in the untreated duplicate crude oil A tests shown in Figures 3-5, experimental repeatability is better than (6% for total deposit weight and (4% for C35+ wax weight for every duplicate test run. In addition to measuring the actual amount of total deposit or amount of deposited wax to gauge inhibitor performance, indications of inhibitor performance often can be gained from visual assessment of coldfinger deposits. Coldfinger deposits from crude oil treated with an effective paraffin inhibitor often have portions of the coldfinger surface which are bare from deposit due to “defective” deposit being sheared off by the flow field. For the crude oil A tests, the effect of increasing shear was relatively apparent from visual observations of coldfinger deposits. As seen in the estimated percent bare coldfinger surface in Table 2, the amount of coldfinger surface area bare of deposit increased with increasing stirring speed in almost all of the tests with the different inhibitors. Examples are shown in Figure 7a and b. Pictures of coldfinger deposits are shown from tests at different stirring rates using inhibitor A at 350 ppm with the large coldfinger geometry and inhibitor B at 750 ppm with the small coldfinger geometry, respectively. In both of Figure 7 parts a and b, a significant increase in the amount of wax deposit sheared-off from the flow field can be observed as stirring rates go from 500 to 1000 rpm. B Crude Oils. As mentioned, the testing with the B crude oils was not as extensive or controlled as with crude oil A due to limited sample size. The most predominant effect this had on crude oil B testing was a constrained range of shear rates examined. In general, it was only possible to run two stirring rates for each crude oil with the samples available. Crude oils B1 and B2 were tested at 750 and 1000 rpm, and crude oil B3 was tested at 600 and 800 rpm.
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Figure 7. Example of deposit changes with increasing shear rates. (a) Example of the effect of shear on the deposition of crude oil A in coldfinger testing using the large coldfinger geometry with inhibitor A at 350 ppm. (b) Example of the effect of shear on the deposition of crude oil A in coldfinger testing using the small coldfinger geometry with inhibitor B at 750 ppm.
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Table 3. Results of Paraffin Inhibitor Testing versus Shear Rate for Crude Oil B1 inhibitor
dose (ppm)
coldfinger
stirring rate (rpm)
wt % C35+ wax inhibition
wt % total deposit inhibition
∼ % bare surface
F
500
small
G
500
small
H
500
small
750 1000 750 1000 750 1000
36.9 18.0 -2.3 43.2 0.6 60.0
49.0 32.3 31.9 55.2 17.9 45.6
25 18 10 60 5 45
Table 4. Results of Paraffin Inhibitor Testing versus Shear Rate for Crude Oil B2 inhibitor
dose (ppm)
coldfinger
stirring rate (rpm)
wt % C35+ wax inhibition
wt % total deposit inhibition
∼ % bare surface
F
500
small
G
500
small
H
500
small
750 1000 750 1000 750 1000
11.6 19.8 52.3 67.0 55.2 53.5
29.0 0.5 55.6 64.5 40.9 27.2
20 5 70 80 55 45
inhibitor
dose (ppm)
coldfinger
stirring rate (rpm)
wt % C35+ wax inhibition
wt % total deposit inhibition
∼ % bare surface
F
500
small
G
500
small
H
500
small
600 800 600 800 600 800 1000
-12.8 27.5 8.6 34.1 9.2 67.0 39.3
-36.7 44.7 0.4 42.6 6.9 59.4 42.7
2 35 50 63 50 80 75
Table 5. Results of Paraffin Inhibitor Testing versus Shear Rate for Crude Oil B3
A couple of other minor differences also existed which could have lessened repeatability. First, with crude oil A, all inhibited tests were compared back to untreated crude oil test runs on the exact same coldfinger device. With the limited samples of crude oils B, this was not practical for the B crude oil testing. As such, small errors from finger to finger variations (which can exist but are nominally less than 10%) were not eliminated in this data set. Second, the B crude oils all contained small amounts of emulsified water. The emulsified water was not removed as it was desired to test with conditions as close as possible as actual field conditions. Although the samples were well shaken to attempt to uniformly disperse the emulsified water prior to the initial subsampling of aliquots for individual coldfinger runs, it is very possible that small differences existed in some of the subsamples. The individual subsamples were not de-emulsified to quantify the water cut of the individual samples after testing. Although, crude oil B testing was not as extensive or controlled as the A crude oil testing, it is included here as it shows, in some manner, different behavior than crude oil A testing. In the crude oil A testing, the amount of inhibition in the total deposit weight was found to decrease with increasing shear due to the changing entrained crude oil concentrations occurring under different shear conditions. In contrast, in the crude oil B testing, no clear trend of total deposit weight decreasing with increasing shear was present. An increasing trend in C35+ wax inhibition and percent of bare coldfinger surface were still present as with the crude oil A results though. Crude Oil B1. Results of crude oil B1 coldfinger testing are given in Table 3. Note that in going from stirring rates of 7501000 rpm for inhibitors G and H, the performance increased in the inhibition of C35+ wax and percent bare coldfinger surface area from little or no performance to significant performance. The amount of inhibition in the total deposit weight increased as well going from 750 to 1000 rpm. This contrasts with the clear behavior of the decrease in the total deposit weight with increasing shear shown with crude oil A.
The results for inhibitor F showed a slight decrease in performance in the 1000 rpm test versus the 750 rpm. It is believed this is more related to isolated data scatter due in part to the more limited tests and corresponding less controlled nature of testing with the B crude oils, rather than any indication of behavior trends. Supporting this belief is the general inhibitor trends (including inhibitor F) seen with crude oils B2 and B3 discussed below. Crude Oil B2. Results of crude oil B2 coldfinger testing are given in Table 4. In these tests, the general trend was that the amount of inhibition in C35+ wax increased, though the inhibitor H results were about constant. The inhibition in total deposit weight decreased with two of the inhibitors and increased with the other. Crude Oil B3. Results of crude oil B3 coldfinger testing are given in Table 5. As seen, inhibitor performance improved for each inhibitor in going from 600 to 800 rpm with respect to inhibition of C35+ wax, percent bare coldfinger surface area, and inhibition of the total deposit weight. The only data against the trend was in the one test run at 1000 rpm. The performance of inhibitor H in the 1000 rpm test was not as good as the 800 rpm test. It was, however, still significantly better than the 600 rpm test. OVerall. Overall the crude oil B testing indicated improved inhibitor performance with increasing shear. Though some scatter exists in the data, results indicated that the percent inhibition of C35+ wax and the percent bare coldfinger surface area increased with increasing shear. The inhibition of total deposit weight did not, however, necessarily decrease with increasing shear as with the testing of crude oil A. In many of the tests, it increased. Conclusions A series of coldfinger tests were performed with four Gulf of Mexico crude oils to illustrate the effect of shear on paraffin
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inhibitor performance. The results of the testing illustrated a general trend of improved paraffin inhibitor performance with increasing shear force. General trends with increasing shear were seen in an increase in the following: (1) the inhibition in the amount of wax in the deposits and (2) the amount of coldfinger surface area bare of deposit.
Jennings and Weispfennig Acknowledgment. The authors thank Helen Hager and Gerard Baham of the Baker Petrolite Analytical Department for performing numerous high temperature gas chromatography analyses of coldfinger wax deposits. EF0602170
