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Narrowing the gap between laboratory and oilfield using real-time paraffin fouling measurement Christopher Russell, Lilian Padula, Saugata Gon, Emily Pohl, Andrew Neilson, and Ron Sharpe Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.9b01091 • Publication Date (Web): 14 May 2019 Downloaded from http://pubs.acs.org on May 15, 2019

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Narrowing the gap between laboratory and oilfield using real-time paraffin fouling measurement Christopher Russell1*, Lilian Padula1, Saugata Gon1, Emily Pohl1, Andrew Neilson1, and Ron Sharpe2

1Flow

Assurance Paraffin and Asphaltene RD&E, Nalco Champion, An Ecolab Company, Sugar Land TX, USA

2Refinery

Process and Fuel Additives RD&E, Nalco Champion, An Ecolab Company, Fawley, Hampshire, UK

Paraffin related flow assurance issues have become more prevalent over the last two decades as more unconventional oil reserves are produced. Depending on the maturity of the source rock and selective alterations during expulsion and migration, these crude oils, as well as those from conventional plays, can contain significant amounts of wax (nC18 and above). As these crude oils are produced, there may be instances when the fluid

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drops below a certain temperature that induces wax insolubility, and therefore increases the risk of paraffin deposition. The deposition can lead to constrictions in tubing, fouling of rod pumps and other mechanical lift methods, and restrictions in separating facilities and export lines. There are several solutions available to the operator to mitigate such paraffin fouling events, one of which is chemical based. However, the design, selection, and reputation of such production chemicals have suffered greatly because of laboratory testing procedures providing less than satisfactory results and, more importantly, field performance correlations. Here, we present a novel test method development that overcomes the main drawbacks of traditional paraffin fouling testing procedures by providing a real time measurement of the initial layer of foulant formation by measuring near infra-red (NIR) light transmittance on a temperature controlled reflective surface, the

para-window. The equipment and procedure are described relative to standard industry testing protocols. Further developments are also demonstrated that permits the generation of a unique paraffin fouling profile. The profile encompasses relatively more representative temperature conditions than the traditional methods allow, and therefore generates more field like deposits. This then affords the opportunity to develop the next


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generation of paraffin control production chemicals tailor made for the most insoluble and problematic wax fractions.

*Corresponding Author: [email protected]


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1. INTRODUCTION

Crude oils are generally dominated by n-alkanes that are a result of liberation and cracking reactions occurring during the thermal maturation of organic rich petroleum source rocks under pressure and in the presence of water1, 2. The composition of the source rock, maturity, and the subsequent migration distance play significant roles in the character of the petroleum fluids generated3-7. Conventional reserves are generated from source rocks well into the oil generating maturity window as quantified by vitrinite reflectance (0.5 – 1.2 VRo.) and have often migrated many kilometers before pooling in an appropriate reservoir-cap rock configuration8. Alkane distributions from these oils are usually dominated by those formed from naturally occurring bitumen and cracking reactions during the maturation process and are often referred to as macrocrystalline paraffin wax (n-C18 – n-C30)9. An exception may occur if the source rock organic matter is primarily composed of material rich in wax10,

11.

Unconventional reserves, namely the

organic rich shale rocks that are hydraulically fractured in horizontal wells to obtain petroleum fluids, produce alkane distributions that are more enriched in longer chains,


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and branched and cycloalkanes, also referred to as microcrystalline amorphous wax (>

n-C30 – n-C50)9. This is thought to be a consequence of the immature character of the source rock. As the organic material is being liberated by hydraulic fracturing as opposed to the thermal and pressure related forces associated with peak maturity source rocks (catagenesis), the petroleum fluids retain some of their character from diagenesis. For example, Killops et al, (2000)12, suggest that these long chain alkanes may be liberated from cutan or cutin sources within the kerogen by the decarboxylation of esters. These molecules, which are a mixture of normal, branched and cyclic alkanes, have a relatively higher melting point range than their macrocrystalline paraffin wax counterparts. This can cause significant problems during production that are mainly related to fouling13. In both offshore and onshore environments, the risk of paraffin wax fouling increases when the process surface drops below a temperature point that causes wax to become insoluble, i.e. the wax appearance temperature14. At the fluid and process surface interface, a viscous boundary layer may form, where laminar flow dominates, and it is in this layer that the initial stages of paraffin wax fouling occurs. As is the case with most descriptions of fouling, the process may be broken down into several stages, that includes


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initiation, attachment and removal terms. It is thought that wax crystals that form in the viscous boundary layer may travel to the surface, and stick, if the wall friction is high enough, by a process called shear dispersion, whose flow pattern results in a net transport of particles to the surface. This forms an initial gel layer containing oil and wax. The wax deposit may harden due to the aging process. Here, molecular diffusion of lower molecular mass material out into the oil phase coupled with the relative concentration of higher molecular mass material often results in a hard-microcrystalline wax rich deposit15. The formation of these deposits can cause significant production problems, which include losses attributed to flow restriction, hindered lift mechanism, and frequent interventions. In an attempt to minimize the risk of paraffin related production problems, the operator will often investigate the potential of chemical additives to disrupt the formation of problematic wax, thus extending run times between costly interventions. Selection and qualification of these products often requires the use of laboratory experiments that permit the measurement of waxy deposit from the crude oil, with deposition driven by temperature differential. There are various configurations of these test methods (flowloops16, 17, cold discs18, Taylor-Couette systems19, 20 and cold fingers21), and all of them


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have their advantages and disadvantages. For example, Taylor-Couette systems may provide an excellent laboratory representation of flow regimes, and the cold finger permits a rapid turnaround of many samples. However, all these methods have a colder surface relative to the bulk oil from which deposition is measured. An excellent summary is provided by Frenier et al., (2010)14, where the authors describe a wide variety of deposition tests that have been used to measure paraffin wax fouling in the laboratory. One of the simpler and widely accessible instrument setups is referred to as the cold finger. In this test configuration, metal cylinders, or fingers, cooled by fluid flow, are placed into glass sample containers. The assembly is placed into a water bath or heating block that maintains the crude oil at a set temperature. The finger assembly has coolant fluid pumped through it that reduces the temperature of the metal surface, with the intent of driving wax adhesion through temperature driven mass diffusion. Once the test is complete, the test fingers are removed from the oil. There are several methods to measure the amount of material adhered to the finger that are used throughout the industry22. For example, the fingers may have detachable sheaths that may be removed and weighed, the material may be wiped from the finger and weighed, or the material may


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be melted from the finger, collected and weighed. However, the deposits often contain relatively large amounts of crude oil, that often times may mask any meaningful mass measurements and therefore the effect of anti-foulant chemical. In an attempt to reduce the impact of this material, the fingers may be dipped in a known paraffin precipitant such as acetone or methyl-ethyl-ketone, and then measured by mass. Furthermore, the wax content of these deposits may be calculated for comparison, for example, via differential scanning calorimetry (DSC) or high temperature gas chromatography (HTGC). All these deposition methods have one step in common: The test surface must be removed from the test fluid to examine the foulant generated. It is this step that introduces the largest amount of variability to the test and reduces the universal applicability to all crude oil paraffin risk assessment. Depending on the character of the crude oil, the removal of the finger may in fact cause some of the target deposit to slough off giving erroneous results. Of further concern, is the oftentimes large temperature differential (ΔT) between the crude oil and the test surface / finger required to generate measurable deposit from the parent crude oil21. These conditions are usually unrealistic to the field,


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where typically there can be only a few degrees difference between process fluid and process surface. Having operated the cold finger apparatus and experienced the disadvantages associated with it, namely unsatisfactory assessment of deposit, unrealistic temperature conditions, and poor correlation to field experience, particularly regarding product dosage response, Nalco Champion has investigated the possibility of an alternative. The work discussed here introduces a new method for examining the paraffin fouling potential of crude oils, where near infra-red (NIR) light transmittance and reflectance are used. Previously, NIR transmission measurement has been used for determination of WAT23, but not for deposition or to monitor the formation of an initial gel layer surface deposit in real time. The new test therefore avoids all the pitfalls of having to remove a test surface from the fluid for evaluation and opens up the possibility to develop the next generation of paraffin control chemical products.


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2. EXPERIMENTAL METHODS

Crude Oil Samples: The samples used in this study are listed in table 1. Wax Appearance Temperature: The temperature at which wax crystals initially appear in crude oil is termed the wax appearance temperature (WAT) or cloud point. There are many methods used to identify this temperature region, however, it is likely that none of the methods can measure the true wax appearance temperature of a crude oil as it is impossible to erase the inherent thermal history completely and move all wax to the liquid phase. Here, a differential scanning calorimeter (DSC; TA Instrument DSC 910S Thermal Analyst 2100) was used to measure the WAT. A DSC measures temperatures and heat flows associated with phase transitions in materials (e.g. crystallization or melting). As the paraffin crystals are forming, energy is released, which is detected by measuring the difference in heat flow between the sample and an empty reference cell. Sample cells (TA hermetic pan and lid) were loaded with around 5 mg crude oil or 2 mg field deposit and placed in the sample chamber with the reference. The chamber was then cooled from


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70 to -20 °C at a cooling rate of 2 °C per minute, with the first temperature of heat flow deviation noted as the WAT. Cold Finger Apparatus: There are several iterations of this equipment in Nalco Champion’s laboratory, with the main difference being fluid volume and finger geometry. In all cases however, the test begins by heating samples of crude oil well above the detected WAT, usually by 10 °C or so for sixty minutes. At this point, anti-foulant chemicals may be dosed, with the oil left for a further thirty minutes. The oil is then placed in the test cells, and these are placed in the cold finger apparatus temperature-controlled water bath or heating block. The temperature of this bath or heater block is usually dictated by field experiences, for example, the maximum temperature that the oil will be exposed to, or just above WAT. Once the samples are loaded, the cold finger assembly is attached, and the stirring speed is applied. The temperature of the finger is again usually selected from field conditions, for example, the minimum temperature that the oil will be exposed to. Once assembled, the test may run for anywhere between two and thirty-six hours, depending on the nature of the crude oil. At the end of the test, the fingers are removed, and depending on the scope of the project and the character of the oil, the


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fingers may be dipped in cold methyl-ethyl-ketone or acetone and left to dry. The remaining material is then removed by a paper towel of known mass, with the mass increase of the towel calculated to be the mass of deposit. When screening paraffin antifoulant chemicals, the mass of deposits are compared to the mass of the untreated fingers to provide a measure of inhibition in percent mass reduction. High Temperature Gas Chromatography: The analysis presented here was performed at a third party laboratory, with the general methodology resembling the following. Around 0.1 µl to 1.0 µl of sample was introduced by syringe into a split / split-less injector of an Agilent 6890N gas chromatograph (GC) held at a temperature of 275 °C. From there the sample passed through a 60 m, 0.25 mm I.D. Agilent DB-1 column using a constant pressure of helium as the carrier gas. The column oven was programmed to hold at 30 °C for 5 minutes, then set to increase to 320 °C at 3 °C min-1 at which point it was held for 20 minutes. Components eluting the column were detected by a flame ionization detector (FID) held at 350 °C. The addition of an internal standard prior to injection allowed the components to be quantified. Under these chromatographic conditions, compounds from n-C4 to n-C42 are observed, with n-alkanes, key isoprenoids, key


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aromatic compounds and the lighter hydrocarbons are reported. Crude oil standards are run periodically to check retention times and other chromatographic performance criteria. Temperature Controlled Reflectance Cell Para-Window: Samples of crude oil are first heated in an oven to a temperature well above the detected WAT, usually around 10 °C above, following the same procedure as described for the cold finger test above. The oil is placed in the test cell. The test cell comprises a 500 ml double walled glass bottle with a custom modified screw top head to house the remaining apparatus. A schematic diagram of the apparatus is shown in figure 1. A stir bar is placed in the test cell, to which 400 ml crude oil is added. The oil temperature is then set by adjusting the chiller attached to the outer wall of the test vessel. The header assembly space comprises fittings for a fiber optic NIR (980 nm) immersion probe, fluid inlet and outlet, and a thermocouple. The NIR probe and fluid transfer pipes are attached to the reflectance assembly where the probe can be held in place to a known path-length from the reflective surface, or mirrored steel plate. Fluid flows beneath the plate that serves to heat or cool the reflective surface, which is monitored by a second thermocouple positioned directly below the underside of the mirror, providing an expected surface temperature. Once the crude oil and mirror are


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at equal temperature, the head assembly is attached to the double walled glass bottle, after which data recording of bulk oil temperature, mirror temperature and NIR transmittance is initiated. Usually, the experiment resides for five minutes with zero difference between bulk oil and mirror to obtain a definitive zero fouling baseline. After this period, the temperature of the mirror is lowered to the pre-determined target at a cooling rate of ~ 1 °C min-1 and left to soak for typically one hour. After the soaking period has ended, the mirror is heated back to the temperature of the bulk oil, where it again remains for five minutes and the test is terminated. A representation of low and high fouling scenarios is also shown in figure 1. The fouling propensity recorded during a single test is determined by transforming the raw light transmittance to optical density and then comparing the standard deviation over the whole curve generated during the target temperature soak time. The standard deviation is multiplied by 10000 and termed the fouling factor. Optical density is calculated from equation 1, where TRANS represents transmittance at a given time during the test. 𝑂𝑝𝑡𝑖𝑐𝑎𝑙 𝐷𝑒𝑛𝑠𝑖𝑡𝑦 = ― 𝐿𝑂𝐺 ∗

(𝑇𝑅𝐴𝑁𝑆 100 )

(1)


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3. RESULTS AND DISCUSSION

The current industry practice for determining the paraffin wax fouling propensity of crude oils, and for the selection of the most appropriate anti-foulant chemical product relies on a tool that is commonly referred to as the cold finger apparatus. There are many iterations of this equipment, but most require the removal of a test surface from the crude oil sample for assessment of fouling, a step that introduces a large amount of experimental error. Nevertheless, it is still the current industry standard, but it is hoped the information discussed here can perhaps initiate some change. We begin therefore, by examining the results from a typical cold finger project at the Nalco Champion Flow Assurance laboratory. The project in question concerned a wax deposition risk from crude oil A in a subsea flowline, where the operator had identified the test conditions of interest by taking the hottest (32 °C) and coldest (16 °C) temperature that the oil would potentially experience. Further test parameters included a stir rate of 600 rpm over a duration of 16 hours. Of course, for the actual flowline, these temperatures may be rather unrealistic, as in most cases it is unlikely that the bulk oil would be 16 °C hotter than the process surface


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in the laminar viscous boundary layer under discreet transient conditions unless there are some extreme topography surrounding the wellhead. A series of paraffin chemical antifoulants were screened with a starting dosage of 1000 ppm. The results of the test are displayed in table 2a. Under these conditions, four products appear to perform well, providing the highest inhibition, products A, C, E and J. Inhibition here is calculated from equation 2, where MB is the mass of deposit from the untreated test and MT is the mass of deposit from the treated test. 𝐼𝑛ℎ𝑖𝑏𝑖𝑡𝑖𝑜𝑛 % =

[

(𝑀 𝐵 ― 𝑀 𝑇 ) 𝑀𝐵

] ∗ 100

(2)

These most promising candidates were then examined further by varying their dosage, the results of which are also displayed in table 2a. It is thought that the most appropriate product will display the greatest performance at the lowest dosage. There are two products that maintain performance at the lowest tested dosage (250 ppm), products A and J. However, it is at this point where the cold finger test fails to differentiate the products any further considering the error associated with the test, which is usually in the order of 10 to 20 %. This situation is not uncommon for paraffin anti-foulant selection


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projects based the cold finger apparatus. The fundamental flaw in the test design is the removal of the test surface to measure the deposition, rendering a reliable measure of deposition all but impossible. Furthermore, the application of unrealistic testing conditions produces a very poor representation of wax deposit compared to that encountered in the field. This aspect will be discussed in far greater detail later in this section. To provide further clarity on product selection, Nalco Champion has developed an alternative to the test, where near infra-red (NIR) light is used to measure and monitor deposition in real time, thus avoiding the complications and pitfalls of removing the test surface from the fluid for assessment, which is especially important for the risk assessment of relatively dark, low wax crude oils, such as the subject of the cold finger project described previously. The results from the para-window testing of the four candidate products identified above are displayed in table 2b for a dosage of 250 ppm. It appears that the real time para-window testing is far more sensitive to product performance than the cold finger, with a far greater spread of inhibition values. Interestingly, the two products that appeared to give the best performance on the cold finger, products A and J, also revealed the best performance on the para-window.


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However, the para-window provides far greater resolution and differentiation in their performance, with Product A clearly revealing the greatest antifouling potential. The worst performer on the cold finger test, Product C, is also the worst performer under the parawindow assessment, but here it appears to promote fouling. It is not unusual for certain paraffin control chemicals in combination with certain crude oil wax compositions to perform in such a manner. Although the connection requires further research and is beyond the scope of the current study, it is thought that a relatively denser and more organized wax crystal structure forms in the initial gel layer causing the light transmittance to dramatically decrease. Product E appears to promote relatively little performance improvement. The initial comparison described above demonstrates how the para-window permits far greater sensitivity and resolution to paraffin control chemical product performance and selection over the conventional cold finger test. The next part of the discussion examines in more detail how the data from the para-window is generated and interpreted. An example of the raw data from the para-window is displayed in figure 2. Here a crude oil from the Eagle Ford petroleum system was used whose wax appearance temperature


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was determined to be 42 °C. The temperature conditions in this case were deliberately severe to demonstrate the transmittance data fully. The bulk oil (brown data points) was maintained at 50 °C, with a target surface soak temperature (blue) of 20 °C. The transmittance data (red) remains relatively steady for the first sixteen minutes or so at which point a steady decline is recorded. This initiation of deposition can be correlated to just below the detected WAT. The time lag makes some sense, as there should be a period between crystal formation and detectible concentration and organization in the viscous boundary gel layer on the reflective surface. As the temperature of the reflective surface decreases to the target soak temperature, the transmittance decreases, and continues to do so throughout the soak period. It appears that there are instances of deposit sloughing, denoted by sharp increases in transmittance, after which the deposit gel layer reorganizes and rebuilds once more. At the end of the designated soaking time, the reflective surface temperature is returned to that of the bulk oil, where it resides for a further ten minutes. As the surface temperature heats up, the wax rich gel deposit begins to melt and solubilize, designated by the smooth curved increase in transmittance at around 105 minutes. At a higher temperature, the deposit loses its adhesive strength


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completely and is removed from the surface. The transmittance increases sharply and returns to the baseline value as it was at the start of the test. The transmittance data is then transformed into optical density, and the fouling factor is calculated. There is little change in the optical density of low fouling fluids over the test temperatures, therefore the fouling factor is low. Test conditions that are conducive to large changes in optical density have a high fouling factor. The example shown in figure 2 has a fouling factor of 355. The effect of a common paraffin control product on the optical density change under the same test conditions and oil as described above is displayed in figure 3. The paraffin control chemical is a typical maleic-copolymer type wax crystal modifier. The application of three dosages were investigated: 250, 500 and 1000 ppm. There are several interesting observations from the data. With each incremental increase in dosage, there is a systematic reduction in the overall fouling factor, as displayed in the graph inset. The fouling factor appears to have a linear trend with increasing dosage in this case. The fouling factor reduction is a consequence of a decrease in the maximum optical density measured, even though the initial fouling event occurs at the same time and temperature in each case. An explanation for this observation could be due to modification of the wax


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crystal lattice structure in the gel layer. Although there is a common initial fouling event, indicating that the WAT remains similar, the organization and thus the density of the crystal lattice in the initial gel layer on the reflective mirror with the wax crystal modifier decreases. The strength of the crystal lattice layer in the dynamic fluid test environment is therefore decreased and is easier to remove. Further evidence to support this theory may be found at the end of the test. In each case, the end of the soak period is very close to 100 minutes. For the untreated sample, there appears to be an almost ten-minute lag between the end of the soak period and removal of the wax rich deposit, which is denoted by the sudden decrease in optical density. With 250 ppm treatment, the gradual reduction in optical density is far more pronounced than for the untreated test, with the reduction in optical density occurring just after 100 minutes, however, the sudden reduction in optical density is around about the same time as the untreated test. The strength of the crystal lattice forming on the reflective surface has therefore become somewhat weaker. This trend continues with increasing dosage. At 500 ppm, the maximum optical density is much lower, forming a far weaker crystal lattice layer than 250 ppm. The data suggests that a critical thickness is formed, beyond which it is too disorganized to withstand the dynamic


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conditions in the test cell. It is anticipated that future developments in the equipment will address deposit thickness detection. At 1000 ppm, the adhesive strength of the crystal lattice structure is so low, that it cannot form, giving a virtually undetectable foulant layer. The initial data summarized in figure 2 and 3, which is only a very small portion of a much larger experimental data set, provided much encouragement for the application of the test to become one of the primary methods for Nalco Champion’s paraffin control product design and selection process, offering relatively greater sensitivity and resolution than the current cold finger test. The next stage in the development of the method and procedure was to address the subject of test temperature gradient. It had become somewhat routine for cold finger test temperatures to encompass a large gradient, in the order of 15 to 25 °C, which were often dictated by request, i.e. the maximum and minimum temperatures the oil would experience in the system of interest. However, these large temperature gradients are somewhat unrealistic relative to the field, with only a few exceptions that are due to some extreme geology and topography surrounding the well head. The temperature differential between the bulk crude oil and the inner pipe wall is often much lower, typically between


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2 – 5 °C, depending on the geographic location, time of year, pipe material, internal diameter, wall thickness, and surrounding media. These temperatures have been observed by several internal and confidential modelling reports that cannot be referenced here. Furthermore, it is evident from the analysis of many paraffinic field deposits that it is only the most insoluble microcrystalline wax that dominates the composition and therefore appears to be the main cause of fouling. Although molecular diffusion and deoiling undoubtably play a major role in the enrichment of these moieties and hardening of the deposit, controlling the most insoluble wax fractions may permit control over the whole fouling problem. Unfortunately, the current laboratory test technique, the cold finger, has been repeatedly demonstrated to be unsuccessful in producing reliable data to probe these small temperature gradients over a range of oils. For instance, the target, most insoluble, wax fractions are often masked due to the large temperature gradients employed, and by entrained oil during the removal of the finger for deposit assessment, rendering any meaningful paraffin control product evaluation inconclusive. The parawindow, on the other hand, has the sensitivity to examine the initial formation by the most insoluble wax rich constituents of the crude oil in the initial boundary wall gel layer.


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A secondary exemplar crude oil, crude oil C from the Permian Basin, was selected to investigate the fouling tendency over these discreet temperature windows, whose WAT was determined to be 32 °C. The optical density profiles for six of these temperature windows are displayed in figure 4a. The windows span conditions above and below the measured WAT. The reflective surface temperatures are noted on the table in figure 4a. Above the WAT, at surface temperatures of 40 and 35 °C, the change in optical density is minimal, which is to be expected as very small amounts of wax are becoming insoluble. At a surface temperature of 30 °C, which is very close to or just below the WAT, there appears to be a subtle but steady increase in optical density for the duration of the test. The change becomes further accentuated as the temperature windows decrease. Of further interest is the observation that the starting optical density increases as the bulk oil temperature decreases, indicating an increasing presence of wax crystals in the oil. Perhaps the increasing optical density with decreasing surface temperature is a consequence of the wax fraction that forms on the test surface in that temperature window trapping further wax crystals already formed in the bulk fluid. This opens the tantalizing prospect of the ability to examine the effect of so called dispersant paraffin control


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chemicals, the purpose of which is to curtail the interaction of wax crystals thus preventing further fouling and in some cases aid removal. It is hoped that this will be discussed in a future publication, but it is already ongoing internally at Nalco Champion yielding some positive field recommendations. Fouling factors were calculated from the each of the optical density profiles, and these are plotted against surface temperature in figure 4b. A distinct fouling profile with decreasing process surface temperature is observed. This profile is unique for each crude oil, and in general follows a monotonic relationship. Also, the 30 °C data point indicates the excellent experimental reproducibility of the test, which in this case was calculated from two tests three months apart and on different para-window equipment. As explained above, at 40 °C there is negligible fouling, but as the surface temperature approaches the WAT, as determined by DSC, there is a definitive increase in the fouling factor. At both surface temperatures of 35 and 30 °C, the fouling factors are very similar, at 33 and 38 respectively. It is accepted throughout the industry that there is no method that definitively determines the WAT, so it is quite possible that above this temperature there will be deposition of insoluble wax. Perhaps the sensitivity of the para-window test is identifying


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a discrepancy with the method of WAT determination used in this study. Nevertheless, it is around this temperature window where the first sign of insoluble wax deposition is detected. Below a surface temperature of 30 °C, the fouling factors increase significantly with every 5 °C temperature decrease. As stated above, this may be a consequence not only of the wax fraction forming on the surface at that temperature, but also the entrapment of already formed wax crystals pulled from the flowing bulk oil. It is essential to understand which temperature driven wax fraction from the fouling profile most represents the wax foulant material that is encountered in the field. Identification of these conditions may therefore permit the design and selection of paraffin fouling control chemicals to a much higher degree of accuracy than previously available. For this part of the study, the cold finger apparatus was again utilized, with the test conditions finely tuned to accurately achieve the 5 °C temperature windows. In the context of the present discussion, mass of deposit from these cold finger tests are irrelevant, as a measure of relative fouling was already obtained from the para-window. Deposit data and wax content from the cold finger will be the subject of a subsequent publication. Thus, the aim was to remove the matieral present at the end of the test so that the relationship


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of the deposit generated from the discreet temperature windows to actual field deposit could be explored. However, the cold finger tests were deployed for twenty four hours as opposed to one hour for the para-window test, and so raises the question of the validity of the comparison. Internal testing has demonstrated that the para-window is sensitive enough to identify the initial deposition of the most insoluble wax fraction, not least by the close relationship to wax appearance temperature. Our laboratory is therefore confident that by extending the run time at this narrow temperature window, it is possible to generate enough of the target material for further analysis. The comparison between the deposits was performed by examining the paraffin distributions using HTGC. Representative chromatograms from the parent crude oil C and the associated field deposit are displayed in figure 5. The temperature driven depositional processes involving the most insoluble wax fraction from this crude oil, followed by hardening or aging by molecular diffusion provides the characteristic n-alkane distribution, in this case, in the region of n-C35 to n-C60. As these moieties are the most insoluble wax fraction in this crude oil, they are the fraction that initiates the fouling. Therefore, as mentioned above,


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disrupting the formation of these fractions can prevent or reduce the surface fouling event. Our traditional approach to selecting a paraffin control chemical product would be to use the cold finger test with the bulk oil temperature set just above the WAT (35 °C) together with a relatively large temperature gradient (20 °C) for twenty hours at a stir rate of 400 rpm. A representative sample of material was recovered from the cold finger test and submitted for HTGC analysis, the results of which are displayed in figure 6. Also on the figure, is the n-alkane distribution from n-C30 for the field deposit. Under this view, the microcrystalline wax material deposited on the cold finger is not fully representative of the material that is causing the most fouling problems in the field. Thus, an examination of paraffin fouling control product performance would be inaccurate under these conditions and would lead to erroneous selection and recommendation. The crude oil was analyzed again under the same stir rate and duration, but this time followed the temperature profile as described from the para-window testing in figure 4b. It is important to note again that final deposit mass was not important for this discussion, only generating enough material for HTGC analysis. The results from these tests are shown in figure 7. The uppermost chromatogram displays the n-C30 and greater distribution for the lowest temperature


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window, where the bulk oil was held at 20 °C and the finger temperature was at 15 °C. The lowermost chromatogram is from the field deposit. It is again clear that under these conditions, the microcrystalline wax distribution is very different to that of the field deposit, even though these conditions generated the highest fouling rate, in terms of largest increase in optical density during a single test on the para-window. Through the series of temperature window tests, there is a definitive shift in wax distribution towards that of the field deposit that correlates to the monotonic relationship observed in figure 4b. Significantly, the window of 35 – 30 °C provides the most field representative deposit fraction, suggesting that this wax fraction is responsible for the field deposit. It is unlikely that the distributions are due to long term aging of a crude oil like deposit as the production history of this well site includes severe and frequent paraffin issues. The temperature zone that provides the most representative n-alkane distributions is right around the determined WAT. The 40 – 35 °C temperature window was not examined on the cold finger test as it was decided to keep the finger test surface below detected WAT. The demonstration of this shift in graphical form is shown in figure 8. Here, the chromatogram peak area ratio of ((n-C41 + n-C55) / (n-C47 + n-C48)) is used as this best


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describes the microcrystalline wax distribution in the field deposit. The final bar on chart represents the field deposit. The first bar describes the traditional temperature window cold finger conditions, giving a value that is relatively far removed from the field deposit. There is a systematic reduction in the n-alkane ratio as the temperature window is increased, and it is clear how well the 35 – 30 °C temperature window generated material relates to the field deposit. In this case, the subsequent paraffin control chemical product screen was performed using the para-window apparatus at the 35 – 30 °C temperature window, with the most promising candidates examined under the temperature windows above and below (40 – 35 °C and 30 – 25 °C), particularly as the fouling profile indicated detectable fouling at the higher temperature window. Performance and screening of commercial chemical products will not be described here. A further example of the identification of temperature conditions that generate foulant material that most represents field deposit is described in figure 9. Here, the n-alkane distributions for crude oil D, from the Niobara petroleum system, and the associated deposit are displayed. Once more, the deposit is enriched in microcrystalline waxes suggesting that control of these paraffin fractions should mitigate fouling at the production


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site. Interestingly, the most abundant paraffin chain length range is very similar to that of the previous example described in figure 5, between n-C45 and n-C50. However, in the case of the oil D deposit it appears that the overall distribution is extended, with a notably reduction in relative abundance after n-C50 and a relatively high abundance of n-C60. This could be due to a mixed source or contamination during sampling. The parent crude oil was examined using the narrow temperature conditions on the para-window equipment to generate the fouling profile, which is displayed in figure 10. The profile reveals some differences to the first example described in figure 4b. Again, there is a general monotonic increase in fouling factor as the temperature window decreases, but this increase is very much lower than for crude oil C. It was thought that this could be related to overall wax content, however, quantification of paraffins of chain length n-C16 and above from HTGC indicate that oil D has a wax content of 7.6 % wt. compared to 5.8 % wt. for crude oil C. Thus, just as for the stability of asphaltenes in crude oil, the actual amount may not indicate the fouling propensity of an oil; it could be far more closely related to the solubility systematics as the temperature decreases.


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The WAT of crude oil D was determined to be around 38 °C, and right around this temperature on figure 10, there is a subtle increase in fouling rate. However, it is at the next temperature window that the most dramatic increase in fouling is observed. This is consistent with the previous example, that just below the WAT the fouling rate increases. However, the fouling rate over each temperature window for crude oil D does not increase systematically as was observed for crude oil C. In fact, the fouling factor decreases from 35 to 30 °C, before dramatically increasing at a surface temperature of 20 °C, before again declining. Perhaps this is a consequence of differing wax crystal lattice network strength that forms from the wax fractions generated at these narrow temperature windows, and the constituents in the viscous boundary layer that may influence their solubility. Nevertheless, a unique fouling profile was generated, so as with crude oil C, extended cold finger tests were used to generate material to be analyzed via HTGC to investigate the paraffin constituents in the foulant, and provide some insight into the rather unusual fouling profile generated from the para-window. A summary of the HTGC data is displayed in figure 11. The coldest temperature conditions are displayed in the upper most chromatogram, with the field deposit displayed


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at the bottom. Only the microcrystalline wax portion is displayed. The temperature conditions that generate the most field like deposit are when the surface is at a temperature just below the WAT. However, as mentioned above, the paraffin distribution in the field deposit appears somewhat extended beyond that which is generated with a surface temperature of 35 °C. Further investigation is required, but it may be that this feature is a consequence of how the field deposit was collected and if the sample was contaminated with another. Nevertheless, it is clear that from n-C35 to n-C50, the experimental conditions that most closely resemble the field deposit are generated at a surface temperature of 35 °C. As was observed for crude oil C in figure 7, as the bulk oil and surface temperatures are decreased, the distribution of deposited paraffins decreases in chain length indicating that the higher molecular mass moieties have already crystallized out and are not part of the initial fouling process. The next dramatic change in microcrystalline wax distribution is observed at a surface temperature of 20 °C. Here there is a significant reduction in the intensity of the bimodal n-alkane distribution, with greater emphasis on n-C30 and below. It is also at these conditions that a large jump in


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fouling rate was observed on figure 10, suggesting that this shift in n-alkane distribution is closely linked to the increased fouling rate. A chromatogram peak area ratio was again used to describe the n-alkane distribution of the field deposit, much in the same way as for crude oil C, except in this case, the ratio describes the front and central portions of the n-alkane distribution as there is some concern over the back portion representing contamination or mixed sources in this particular field deposit. The behavior of this chromatogram peak area ratio under various test conditions is displayed in figure 12, where the ratio (n-C35 + n-C36) / (n-C45 + n-C46) is used. The last bar on the chart shows the ratio for the field deposit, which is very low as n-C45 and n-C46 are the most dominant. This result is very similar to the deposit collected when the surface temperature was 35 °C, indicating that these n-alkane distributions are most representative. As the temperature decreases, the chromatogram peak area parameter increases, moving far away from the field deposit value. Interestingly, the dramatic change from surface temperature of 25 to 20 °C is also captured using this method. The deposit collected from a typical traditional cold finger test, where the bulk oil was held at 40 °C and the surface was maintained at 15 °C is also


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shown on the figure as the first bar. Just like the previous example with crude oil C, this is very different form the actual field deposit, indicating that any product selection and recommendations based on these conditions could be misleading.


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4. CONCLUSIONS

A novel test procedure to characterize paraffin wax fouling from crude oils was developed called the para-window. The technique uses near infrared (NIR) laser light transmission to a temperature controlled reflective surface to measure changes in optical density that relate to paraffin wax crystal formation, organizational strength and adhesion in the viscous boundary layer at a process surface – process liquid interface. The technique has several advantages over current technologies, with the primary advantage being that fouling can be monitored in real time, negating the requirement to remove the test surface for inspection and measurement, a step that often introduces significant error. In the first example described here, the test is used to discern product performance where the traditional technology (cold finger) fails. Furthermore, as the para-window relies on optical technology as opposed to gravimetric analysis, as is the case with the cold finger, the technique is sensitive enough to resolve discreet changes in fouling rate over very small temperature gradients for all crude oils, a feature that is not available from current routine technology (cold finger). The examples described in the present manuscript


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demonstrate how unique fouling profiles may be generated for a particular crude oil using narrow 5 °C temperature gradients, e.g. bulk oil 35 °C and surface 30 °C, bulk oil 30 °C and surface 25 °C etc. The HTGC characterization of the deposited material from these temperature gradients revealed the conditions that generate deposit paraffin distributions that most closely resemble that from the field. The temperature conditions that most favored these distributions were observed to be just below the wax appearance temperature for the oil. This is a significant advancement as it now enables Nalco Champion to specifically design and screen antifoulant paraffin control chemicals that are tuned to the most problematic paraffin fraction, thus greatly improving the probability of successful field application.


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5. ACKNOWLEDGEMENTS

The authors would like to acknowledge Nalco Champion, An Ecolab Company, RD&E management for their support and encouragement during the preparation of this manuscript, and regional sales personnel for providing representative samples, without which the development work would not have been possible. We would also like to thank two anonymous reviewers for their constructive feedback and recommendations to improve the manuscript.


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6. REFERENCES

1.

Tissot, B. P.; Welte, D. H., Petroleum Formation and Occurrence. 2nd ed.; Springer-

Verlag: Berlin, Heidelburg, New York, Tokyo, 1984.

2.

Hunt, J. M., Petroleum Geochemistry and Geology. 2nd ed.; Freeman and

Company: New York, 1996.

3.

Bennett, B.; Chen, M.; Brincat, D.; Gelin, F. J. P.; Larter, S. R., Fractionation of

benzocarbazoles between source rocks and petroleums. Organic Geochemistry 2002,

33, 545-559.

4.

Horstad, I.; Larter, S. R., Petroleum migration, alteration, and remigration within

Troll Field, Norwegian North Sea. The American Association of Petroleum Geologists

Bulletin 1997, 81 (2), 222-248.

5.

Larter, S. R.; Bowler, B. F. J.; Clarke, E.; Wilson, C.; Moffatt, B.; Bennett, B.;

Yardley, G.; Carruthers, D., An experimental investigation of geochromatography during


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secondary migration of petroleum performed under subsurface conditions with a real rock.

Geochemical Transactions 2000, 9.

6.

Larter, S. R.; Bowler, B. F. J.; Li, M.; Chen, M.; Brincat, D.; Bennett, B.; Noke,

K.; Donohoe, P.; Simmons, D.; Kohnen, M.; Allan, J.; Telnaes, N.; Horstad, I., Molecular Indicators of Secondary Oil Migration Distances. Nature 1996, 383 (6601), 593-597.

7.

Hong, Z.; Guanghui, H.; Cuishan, Z.; Peirong, W.; Yongxin, Y., The quantitation

and origin of C40+n-alkanes in crude oils and source rocks. Organic Geochemistry 2003,

34 (7), 1037-1046.

8.

England, W. A.; Mackenzie, A. S.; Mann, D. M.; Quigley, T. M., The movement

and entrapment of petroleum fluids in the subsurface. Journal of the Geological Society 1987, 144, 327-347.

9.

Nizami, A., Waxes fraction of crude oil. Energy Educ. Sci. Technol., Part C 2016,

8 (2), 55-62.


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10. Bush, R. T.; McInerney, F. A., Leaf wax n-alkane distributions in and across modern plants: Implications for paleoecology and chemotaxonomy. Geochimica et

Cosmochimica Acta 2013, 117, 161-179.

11. Peters, K. E.; Moldowan, J. M., The biomarker guide. interpreting molecular fossils

in petroleum and ancient sediments. Prentice Hall: Englwood Cliffs, N. J., 1993.

12. Killops, S. D.; Carlson, R. M. K.; Peters, K. E., High-temperature GC evidence for the early formation of C40+n-alkanes in coals. Organic Geochemistry 2000, 31 (6), 589597.

13. White, M.;

Pierce, K.; Acharya, T., A Review of Wax-Formation/Mitigation

Technologies in the Petroleum Industry. SPE-189447-PA 2018, 33 (03), 476-485.

14. Frenier, W., Ziauddin, M., Venkatesan, R., Organic Deposits in Oil and Gas

Production. Society of Petroleum Engineers: 2010.

15. Singh, P.; Venkatesan, R.; Fogler, H. S.; Nagarajan, N., Formation and aging of incipient thin film wax-oil gels. AIChE Journal 2000, 46 (5), 1059-1074.


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16. Towler, B. F.; Rebbapragada, S., Mitigation of paraffin wax deposition in cretaceous crude oils of Wyoming. Journal of Petroleum Science and Engineering 2004,

45 (1), 11-19.

17. Chi, Y.; Daraboina, N.; Sarica, C., Effect of the Flow Field on the Wax Deposition and Performance of Wax Inhibitors: Cold Finger and Flow Loop Testing. Energy Fuels 2017, 31 (5), 4915-4924.

18. Ahn, S.; Wang, K. S.; Shuler, P. J.; Creek, J. L.; Tang, Y., Paraffin Crystal and Deposition Control By Emulsification. In SPE International Symposium on Oilfield

Chemistry, Society of Petroleum Engineers: The Woodlands, Texas, 2005; p 9.

19. Akbarzadeh, K.; Zougari, M., Introduction to a Novel Approach for Modeling Wax Deposition in Fluid Flows. 1. Taylor−Couette System. Industrial & Engineering Chemistry

Research 2008, 47 (3), 953-963.

20. Zougari, M.; Jacobs, S.; Ratulowski, J.; Hammami, A.; Broze, G.; Flannery, M.; Stankiewicz, A.; Karan, K., Novel Organic Solids Deposition and Control Device for LiveOils: Design and Applications. Energy & Fuels 2006, 20 (4), 1656-1663.


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21. dos Santos, J. d. S. T.; Fernandes, A. C.; Giulietti, M., Study of the paraffin deposit formation using the cold finger methodology for Brazilian crude oils. J. Pet. Sci. Eng. 2004,

45 (1-2), 47-60.

22. Weispfennig, K. In Advancements in paraffin testing methodology, Society of Petroleum Engineers: 2001; pp 174-179.

23. Paso, K.;

Kallevik, H.; Sjöblom, J., Measurement of Wax Appearance

Temperature Using Near-Infrared (NIR) Scattering. Energy & Fuels 2009, 23 (10), 49884994.


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TABLE & FIGURES

Table 1. Crude oil samples used in this study

Sample

Provenance

WAT (°C)

A

Gulf of Mexico

30

B

Eagle Ford

42

C

Permian

32

D

Niobara

38


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Table 2a. Typical Cold-Finger paraffin antifoulant screening and dosage response results for crude oil A

Product and Dosage (ppm)

Inhibition (%) 250

500

1000

A

37

35

37

B

-

-

6

C

24

37

43

D

-

-

10

E

26

39

40

F

-

-

20

G

-

-

24

H

-

-

21

I

-

-

12

J

44

41

44

K

-

-

11


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Table 2b. Cold-Finger compared to Para-Window performance for four candidate products using crude oil A

Product, Method and Dosage (ppm)

Inhibition (%) Cold Finger 250

Para-Window 250

A

37

61

C

24

-74

E

26

6

J

44

29


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Figure 1. Schematic diagram of the para-window apparatus with cartoon depictions of low and high fouling scenarios


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Figure 2. Typical raw data generated from para-window test using crude oil B


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Figure 3. Optical density profiles and fouling factors for exemplar crude oil B


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Figure 4a. Optical Density profiles over 5 °C temperature windows for exemplar crude oil C. Bulk oil temperature is 5 °C hotter than tabulated surface temperature


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Figure 4b. Fouling profile for exemplar crude oil C whose WAT is 32 °C. Solid blue line represents general increase in fouling factor with decreasing temperature


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Figure 5. HTGC chromatograms displaying n-alkane distributions from parent crude oil C and solid deposit


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Figure 6. HTGC of deposit generated from typical cold finger temperature conditions of crude oil C: Bulk oil T: 35 °C; Surface T: 15 °C


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Figure 7. HTGC of deposit generated from cold finger tests at 5 °C temperature windows using crude oil C


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Figure 8. Normal-alkane HTGC response ratio ((n-C41 + n-C55) / (n-C47 + n-C48)) depicting paraffin distributions from various test temperature windows compared to the field deposit for crude oil C


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Figure 9. HTGC chromatograms displaying n-alkane distributions from parent crude oil D and solid field deposit


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Energy & Fuels

Figure 10. Fouling profile for exemplar crude oil D whose WAT is 38 °C. Solid blue line represents general increase in fouling factor with decreasing temperature


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Figure 11. HTGC of deposit generated from cold finger tests at 5 °C temperature windows using crude oil D


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Energy & Fuels

Figure 12. Normal-alkane HTGC response ratio ((n-C35 + n-C36) / (n-C45 + n-C46)) depicting paraffin distributions from various test temperature windows compared to the field deposit for crude oil D


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Narrowing the gap between laboratory and oilfield ... - ACS Publications

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