Crude Oil Refinery Impact Testing with LiquidPower Flow Improvers Ray Johnston ConocoPhillips Specialty Products Inc. USA Abstract CSPI has been treating pipelines with LiquidPower Flow Improvers for over 17 years with no reported adverse effects to refinery operation and finished product quality. CSPI has verified these results with full-scale refinery testing and lab scale testing. ConocoPhillips Specialty Products Inc. (CSPI), a wholly-owned subsidiary of ConocoPhillips Company, is the global leader in the science and application of drag reduction. CSPI has provided solutions that allow pipelines to maximize their flow potential, increase operational flexibility, and increase bottom-line profit potentials. DRAs are hydrocarbon-based materials which reduce frictional pressure loss during turbulent flow in a pipeline, enabling companies to strategically reduce or avoid capital expenses, improve pipeline operating costs and/or expand their pipeline system capacity. CSPI has a range of products to drag reduce crude oil, refined products, heavy oil, and multiphase. 1.0 Product Characteristics and Testing Summary LiquidPower Flow Improvers consist of very fine particles of polymer suspended in an aqueous carrier. This aqueous carrier may contain some glycol for freeze protection and small amounts of surfactants and additives to maintain the stability of the suspension. When the LiquidPower Flow Improver is injected into a pipeline (typically at 10 to 80 ppm), the product disperses throughout the crude oil with the polymer going into solution in the crude oil to create the drag reduction effect. The aqueous portion of the carrier remains dispersed. Once the treated crude oil reaches the refinery and, eventually, the desalter process, the polymer remains in solution in the crude oil along with some oil-soluble components of the DRA and the carrier components partition largely to the effluent wastewater from the desalter. With this in mind, in terms of refinery impact testing, the following observations and tests were conducted:

1.1 Real life applications 1.2 Full-scale refinery test with monitoring of the desalters and the finished

product quality 1.3 Desalter mimicking tests to evaluate the dewatering rates of crude oil

treated or untreated with LiquidPower Flow Improvers 1.4 Crude oil distillation (pilot plant) of crude oils treated with

LiquidPower Flow Improvers followed by quality testing of the product cuts from the crude oil

1.5 Fouling propensity tests to evaluate for any effect of LiquidPower Flow Improvers on preheat train fouling.

7th Pipeline Technology Conference 2012

1.1 Real Life Applications LiquidPower Flow Improvers have been used for increasing the flow rate of crude oil pipelines for over 17 years since their development in the 1990s. Today, LiquidPower Flow Improvers are used to treat over 1 billion barrels of crude oil worldwide per year and CSPI has sold flow improvers in 45 countries. The majority of the refineries in the United States are processing crude oil treated with LiquidPower Flow Improvers. Treatment levels at some refineries have been approximately 250 ppm in the crude oil feed for over a 5 year period. In Europe, a refinery has been processing crude with CSPI flow improvers containing a cumulative DRA concentration exceeding 200 ppm for over 15 years. During these periods, there have been no mechanical or operating problems, no catalyst effects, and no finished product issues reported by the refineries related to the use of these flow improvers. 1.2 Full-scale Refinery Test The purpose of the full-scale refinery test was to evaluate the effect of LiquidPower Flow Improvers on refinery operations by treating the majority of crude oil feeding a Midwest refinery over a multi-day period. Two pipelines representing 85% of the crude oil feeding the refinery were simultaneously treated with 25-40 ppm of LiquidPower Flow Improver for a five day period. The refinery operations were monitored closely for a time period prior to the arrival of the treated crude oil and during the processing of the treated crude oil. The refinery operators reported no observed changes outside of standard operating conditions during the test period. All daily operational logs showed no significant variations in operating parameters. Because any effects of the aqueous form of LiquidPower Flow Improvers would most likely be observed in the desalters, these units were most closely observed. All logged operating parameters of the desalters were consistently within the normal operating range during the treatment period, as reflected in Table I.

Table I. Desalter Observations during Treatment Period

PARAMETER POTENTIAL NEGATIVE EFFECT

OBSERVED EFFECT

Rag Layer Thickness Increased if surfactant effects occur

At or below acceptable levels; no increase

Demulsifier Injection Rate Increased rate to decrease or control rag layer

No increases required or made

Voltage and Power Draw Change; indicates differences in separation

Voltage and amperage were constant

Salt Content Increased values Values ranged from 1.0 to 2.0 lbs/1000 bbl before, during, and after testing

Effluent Water Color Discoloration or cloudiness

Clear; no change

The refinery ran very smoothly during the test period and all products from the refinery during the test period met all quality standards as reported by the refinery control laboratory. Tables II and III in the Appendix show refinery control lab release data for refined product samples pulled during the untreated and treated portions of the test period. 1.3 Desalter Mimic Tests The desalter mimic tests were conducted with a desalter simulator apparatus similar to a portable electrostatic dehydrator unit. The unit consists of a heated block and wells for the placement of sample tubes which have electrodes to generate voltage difference within the tubes. The experimental tests involve obtaining a raw crude oil sample and a desalter wash water sample from a refinery, forming emulsions with the samples, and then monitoring water breakout rates in the samples with or without the presence of various additives. The test parameters for the desalter simulator were established to mimic refinery desalter operation as much as possible. The unit and samples were heated to 280F (138C) for testing. The wash water was added to the crude oil at a 6% level; emulsion breaker was added to the mixtures at 12 ppm. High speed mixing occurred for 5 seconds, followed by separation and monitoring with an applied voltage to the tubes. Three series of tests were conducted in the desalter simulator utilizing three different crude oils: Alaska North Slope, Norsk Hydro and West Texas Intermediate. In these tests, LiquidPower Flow Improvers were added to the crude oil at 0, 100 and 200 ppm levels. In all test results, the separation rate and volume for water from the treated crude oil was equal to that of the untreated crude oil. Water quality following separation was not affected by addition of the flow improver.

1.4 Crude Oil Distillation Product Cuts Laboratory tests were conducted on drag reducer treated crude oil samples pulled from pipelines. These tests were conducted to analyze for any potential effects on quality of the refined products distilled from the crude oil. Crude oil samples, representing four different oil batches (two sweet and two sour) were pulled from the pipelines during drag reduction performance testing. The flow improver treatment rate of the crude oils ranged from 25 ppm to 40 ppm. At a ConocoPhillips downstream operations control laboratory, these samples were fractionated into cuts, treated to mimic refinery treatment, and then analyzed for critical quality parameters. Tables IV and V in the Appendix show results of the analyses. All measured parameters of the finished product samples met the required specifications. Of special note, Water Separation Index numbers were typical, showing that the water soluble components present in LiquidPower Flow Improver had no adverse effect. 1.5 Fouling Propensity Tests Prior to entering the first distillation tower, crude oil will typically pass through a series of heat exchangers to heat the crude oil. A series of laboratory tests was run on crude oil treated with LiquidPower Flow Improvers, to ascertain whether the presence of the DRA affected the potential for fouling of these preheat train heat exchangers. For these tests, a North Sea crude oil was treated with 1000 ppm LiquidPower Flow Improver (an excessive level) and compared to the same crude oil without treatment. The crude oil asphaltene stability was tested using an automated flocculation titrimeter (AFT). The test results yielded similar asphaltene stability values for both the untreated and the treated crude oil, with both being stable. The flow improver showed no affect on crude asphaltene stability. Fouling propensity was tested using a hot liquid process simulator (HLPS) unit. The testing conditions were 500 psig (34.5 bar) with a 370C heater. The resultant temperature traces were identical for the treated and untreated crude oil. The test results showed that the flow improver had no effect on the crude fouling rate. Based on these lab test results, LiquidPower Flow Improver was not expected to alter fouling characteristics of treated crude oil in refinery preheat trains. 2.0 Conclusion CSPI has been treating pipelines with LiquidPower Flow Improvers for over 17 years with no reported adverse effects to refinery operation and finished product quality. CSPI has verified these results with full-scale refinery testing and lab scale testing. During the full-scale refinery tests, the refinery reported the following results;

no observed changes outside of standard operating conditions during the test period,

no significant variations in operating parameters, and

all products from the refinery during the test period met all quality standards as reported by the refinery control laboratory.

The labscale desalter tests demonstrated the following results;

no decrease in the water separation rate was observed,

no change in the volume of water separated, and

the wastewater quality was not affected.

In pilot plant crude oil distillation, the following results were reported;

flow improvers had no effect on finished product quality, and

all crude oil cut samples met the required specifications, The fouling propensity tests demonstrated flow improvers did not increase the characteristics for fouling rate in the crude oil preheat train. Extensive research and testing indicate that there is no adverse impact to refinery operations or finished product quality from the use of LiquidPower Flow Improvers. Decades of expertise and industry leadership in DRA formulation allow ConocoPhillips Specialty Products, Inc. to match products with specific applications for maximum benefit, while alleviating concerns on the impact to refinery operations.

APPENDIX

Table II. Refinery Control Lab Results on Gasoline Product Release

Table III. Refinery Control Lab Results on Diesel and Jet Fuel Product Release

Table IV. Test Results on Distillation Product Cuts Sour Crude

Table V. Test Results on Distillation Product Cuts Sweet Crude

Table II. Refinery Control Lab Results on Gasoline Product Release

Refinery Control Laboratory Product Release (COA) -- Lab Test Results Unleaded Gasoline Super Gasoline Product Parameter Untreated Treated Untreated Treated API @60F Composite 58.9 60.0 59.0 58.6 API @60F Top 58.9 60.0 59.3 58.8 API @60F Middle 58.9 60.0 58.9 58.5 API @60F Bottom 58.9 60.0 59.3 58.5 Distillation - ASTM D86 Deg F IBP 90 82 85 87 10% EVAP 111 110 123 126 50% EVAP 193 188 210 206 90% EVAP 313 313 297 298 End Point 410 415 389 384 Recovery, Vol% 96 96.4 95.9 96.9 Residue, Vol% 1.0 1.0 1.0 1.0 Sulfur Wt% 0.03 0.02 0.01 0.01 Reid Dry VP 9.8 9.8 9.8 9.8 v/l of 20 Deg F 129 128 135 135 CST 3hr, @122 Deg F 1 1 1 1 Sulfur, mercaptan, Wt% 0.0016 0.0016 0.0023 0.0019 Exist Gum mg/100ml 1 1.6 1.6 0.6 Induction Period Min 300 300 300 300 Research Octane 91.8 91.8 95 95.7 Motor Octane 82.3 82.2 87 86.8 Road Octane 87.1 87 91 91.3 MTBE Vol %

Table III. Refinery Control Lab Results on Diesel and Jet Fuel Product Release

Refinery Control Laboratory Product Release (COA) -- Lab Test Results

DIESEL JET FUEL A

Product Parameter Untreated Treated Product Parameter Untreated Treated

API @60F Composite 32.9 33 Acidity, total, mg KOH/gm 0.02 0.02

API @60F Top 33 33.2 Aromatics, Vol% 18 19

API @60F Middle 32.9 33.2 Sulfur, mercaptan, Wt% 0.0023 0.0029

API @60F Bottom 32.8 32.8 Sulfur, Total Wt% 0.14 0.15

Distillation - ASTM D86 Deg F Distillation, IBP, Deg F 332 328

IBP D86 Deg F 347 345 10% REC 364 367

10% REC 426 403 50% REC 414 415

20% REC 461 425 90% REC 484 487

50% REC 533 537 Final Boiling Point, Deg F 516 517

90% REC 619 627 Distillation Residue, % 1 1.5

95% REC 642 653 Distillation Loss, % 1.5 1.4

End Point 666 679 Flash Point, Deg F 122 128

Recovery, Vol% 98.4 98.2 API @ 60F 42.3 42.2

Residue, Vol% 1.5 1 Freezing Point, Deg F -42.7 -42.3

Colonial Haze 1 1 Viscosity @ 4F, cSt 5.48 5.69

Vis @ 40C 3 3 Net Heat of Comb., BTU/lb 18551 18548

Pour Point, Deg F 0 10 Smoke Point 22.9 23.7

Cloud Point, Deg F 12 16 Napthalenes, Vol% 2.5 2.6

Flash PM Avg Deg F 148 157 Copper Strip Test, 2 hrs @212 1 1

Rams CR 10% Btms Wt% 0.12 0.06 Thermal Stability:

16 Hr. Oxygen Bomb Stability Filter Pressure Drop, mmhg 0 0

16 Hour Color L4 L4 Tube Rating 1 1

Soluble mg/100ml 17.8 12.8 Existant Gum, mg/100ml 0.8 0.4

Insoluble mg/100ml 0.2 0.7 Water Reaction:

Thermal Stability, 90 min Interface Rating 1 1

300 Deg F DuPont Scale Separation 2 1.1

Pad Rating 2 2 Aniline Point Deg F 141 141

Sulfur Wt% 0.39 0.42 Water Separometer Index Mod. 85 95

Ash Wt% Particulate matter, mg/gal 0.53 0.4

Cetane Index 45.7 46.7 Saybolt Color 20 16

Color L2 L2

CST 3hr, @ 122 Deg F 1 1

BS, Vol% Trace Trace

Table IV. Test Results on Distillation Product Cuts Sour Crude

ConocoPhillips Downstream Operations Control Laboratory Lab Blends of Refined Products from Treated Pipeline Samples Sour Crudes

Vasconian ANS

Product Parameter Naphtha Kerosene Diesel Naphtha Kerosene Diesel Distillation 10% REC, Deg F 180 316 408 107 296 381 50% REC, Deg F 240 406 495 220 459 534 90% REC, Deg F 327 529 611 319 557 626 JFTOT (Pressure/Tube) 0/1 0/1 ----- 0/1 1 ----- WSIM 98 98 ----- 99 98 ----- Water Reaction 0.5/1/1 0.5/1/1 ----- 0.5/1/1 0.5/1b/2 ----- Cold Test, Deg F ----- ----- -5 ----- ----- -10

BS&W ----- ----- TR water ----- ----- TR

water Haze ----- ----- 1 ----- ----- 1 Carbon Residue, wt% ----- ----- 0.03 ----- ----- 0.02 16 Hr. Stability: Color ----- -----

Table V. Test Results on Distillation Product Cuts Sweet Crude

ConocoPhillips Downstream Operations Control Laboratory Lab Blends of Refined Products from Treated Pipeline Samples Sweet Crudes

WTI-Scurry WTI

Product Parameter Naphtha Gasoline Kerosene Diesel Naphtha Gasoline Kerosene Diesel

Distillation:

10% REC, Deg F 126 120 306 410 124 128 323 430

50% REC, Deg F 229 231 377 500 236 245 420 539

90% REC, Deg F 319 380 503 604 327 411 544 615 JFTOT (Pressure/Tube) 0/1 ----- 0/1 ----- 0/1 ----- 0/1 -----

WSIM 99 ----- 99 ----- 98 ----- 98 -----

Water Reaction 0.5/1/1 ----- 0.5/1/1 ----- 0.5/1/1 ----- 0.5/1b/2 -----

Cold Test, Deg F ----- ----- ----- -10 ----- ----- ----- -2

BS&W ----- ----- ----- Trace ----- ----- ----- Trace

Haze ----- ----- ----- 1 ----- ----- ----- 1

Carbon Residue, Wt% ----- ----- ----- 0.03 ----- ----- ----- 0.05

16 Hr. Stability:

Color ----- ----- -----