Energy Fuels 2010, 24, 2337–2349 Published on Web 11/16/2009
: DOI:10.1021/ef900972u
Paraffin Inhibitor Formulations for Different Application Environments: From Heated Injection in the Desert to Extreme Cold Arctic Temperatures† David W. Jennings* and Justin Breitigam Baker Hughes Incorporated, 12645 West Airport Boulevard, Sugar Land, Texas 77478 Received September 1, 2009. Revised Manuscript Received October 26, 2009
Paraffin inhibitors are used in petroleum production operations to reduce wax deposition and/or reduce viscosity or complete gelling of high-wax-content petroleum fluids. When the treatment is for viscosity reduction or gel prevention, the paraffin inhibitor is commonly called a pour-point depressant. The active chemistries of paraffin inhibitor/pour-point depressant products are specialty polymers that alter the wax crystallization process, which, in turn, changes the characteristics of wax deposits and wax gel networks. The polymers are typically formulated in a carrier fluid for easy delivery (with a simple injection pump) to the petroleum stream that is to be treated. Most commonly, the polymer is dissolved in a solvent. This formulation must, of course, be stable and suitable for use in its particular application environment. The environment (principally ambient temperature) can vary widely depending on the geographical region and the season of the year. Similarly, constraints placed on paraffin inhibitor formulations vary accordingly. For example, paraffin inhibitors have been applied in conditions ranging from stringent extreme cold arctic locations (with temperatures to -40 °C and below) to tropical locations where warm year-round ambient temperatures are very amenable to the formulation of stable, high-activity products in carrier solvents. Paraffin inhibitors are also used in deep-water umbilical applications in which the formulation not only must be stable at the cold ambient seafloor temperatures (∼4 °C) but also must handle the combined effect of elevated pressure present in the umbilical line. In contrast, paraffin inhibitors are also applied, in applications in which thermal conditions are controlled with heated storage and injection. Although not widely used, heated injection allows the most active concentrated formulations to be applied and the widest range of chemistries to be selected. This paper discusses different paraffin inhibitor formulations and continuous injection applications in a variety of different environments. The applications discussed range from heated injection, to surface injection, to deep-water dry-tree applications, to deep-water umbilical applications, and to applications in subfreezing environments (from moderate freezing to extreme cold arctic conditions). gradual process that builds up over time. Flow problems in high-wax-content crude oils occur more rapidly. Flow problems occur as the solubility of wax is lost as crude oil temperatures drop during the production process of removing it from the hot reservoir. As more and more wax precipitates, the formation and growth of the wax crystal gel network occurs. If the network becomes extensive enough, the crude oil viscosity will increase significantly or the crude oil might completely gel solid. These problems are often referred to as pour-point problems. The pour point is the lowest temperature at which a crude oil (or other petroleum fluid) containing wax constituents will flow or pour, as defined by ASTM test methods.1,2 Parts A and B of Figure 1 show examples of cases of severe wax deposition. Figure 1A is a picture of several production flowlines (mostly onshore from the continental USA) that were either severely restricted or completely blocked with paraffin deposition. Figure 1B is a picture of an offshore transport line with severe paraffin blockage. Figure 2 shows examples of three crude oils that are solid at room temperature (below their pour-point temperatures) due to wax gelation. Various preventative or remediation means are available to handle wax problems. These means include mechanical,
Introduction Paraffin Production Problems and Control Methods. In petroleum production, some fields experience production problems related to the wax (paraffin) present in the crude oil. The two principle problems experienced are (1) wax deposition and (2) flow problems due to dramatic viscosity increases or complete gelling caused by the formation of branched wax crystal networks in the crude oil. In some instances, if not dealt with appropriately, both can cause serious production limitations or complete blockage of the flowlines. Correspondingly, wax problems are responsible for significant economic loss in the petroleum industry. Whether wax problems occur depends on the chemistry of the crude oil and the conditions in the production system. Crude oils with high wax contents and/or wax distributions with very high molecular weight waxes are particularly prone to having wax problems. Similarly, if the temperatures in the production lines are low, wax problems will more likely occur. Wax deposition occurs when flowline surface temperatures are below the temperature at which the waxes are soluble and a temperature-gradient exists between the crude oil and colder deposition surface. Deposition is generally a † Presented at the 10th International Conference on Petroleum Phase Behavior and Fouling. *To whom correspondence should be addressed. E-mail: david.
[email protected].
r 2009 American Chemical Society
(1) ASTM D5893-09. Standard Test Method for Pour Point of Crude Oils. (2) ASTM D97-09.Standard Test Method for Pour Point of Petroleum Products.
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Figure 2. Examples of waxy crude oils gelled solid at room temperature.
inhibitors, dispersants, and solvents. Paraffin inhibitors are used to reduce wax deposition and improve the flow properties of waxy crude oils. If the paraffin inhibitor is used for improving the flow properties, the inhibitor is more commonly referred to as a pour-point depressant (PPD). Paraffin dispersants and solvents are generally used to remove existing deposits. The wax management method chosen for a particular field depends on the specifics of the field and operator preferences. Performance and economics are generally the controlling drivers for selection. For some fields, paraffin inhibitor and PPD applications are the preferred treatment methods. Paraffin Inhibitor Mechanism and Formulation. Paraffin inhibitors/PPDs are chemicals that incorporate into and alter wax crystal structures. For this reason, paraffin inhibitors are also referred to as wax crystal modifiers. The wax crystal structures can be either wax deposits on flowline walls or branched wax network growth within the crude oil, causing pour-point issues. Paraffin inhibitors/PPDs are polymers in which the polymer structure contains waxlike portions that allow the molecule to incorporate into wax crystal growth, yet also has other structural features that alter and disrupt the crystallization. For wax deposition, the inhibitors can alter the deposit’s ability to cohesively adhere to surfaces. The inhibitors can prevent effective incorporation of wax into the deposit and/or weaken the deposit, which allows shear forces present in the flow stream to remove the weakened wax deposit. Paraffin inhibitors generally do not completely prevent all deposition though. The function of paraffin inhibitors is usually to reduce wax deposition and not
Figure 1. (A and B) Examples of cases of severe deposition.
thermal, and chemical methods, or combinations thereof.3-13 Mechanical methods include pigging and cutting. Thermal methods include insulation and heating of flowlines to prevent deposition. Chemical methods include paraffin (3) 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. (4) Feeney, S. Project Case Histories and Future Applications of Vacuum Insulated Tubing. Paper presented at the International Conference on Petroleum Phase Behavior and Fouling, 1999 AIChE Spring National Meeting, Houston, TX, March 14-18, 1999; Paper 60d. (5) Singh, P.; Walker, J.; Lee, H. S.; Gharfeh, S.; Thomason, B.; Blumer, D. An Application of Vacuum-Insulated Tubing (VIT) for Wax Control in an Arctic Environment. SPE Drilling Completion 2007, June, 127-136. (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. (9) Straub, T. J.; Autry, S. W.; King, G. E. An Investigation into Practical Removal of Downhole Paraffin by Thermal Methods and Chemical Solvents. Presented at the SPE Production Operations Symposium, Oklahoma City, OK, March 13-14, 1989; SPE 18889.
(10) Slater, G.; Davis, A. Pipeline Transportation of High Pour Point New Zealand Crude Using Pour Point Depressants. Presented at the 61st Annual Technical Conference and Exhibition of the Society of Petroleum Engineers, New Orleans, LA, October 5-8, 1986; SPE 15656. (11) Jennings, D. W.; Newberry, M. Application of Paraffin Inhibitor Treatment Programs in Offshore Developments. Presented at the 2008 Offshore Technology Conference, Houston, TX, May 5-8, 2008; OTC 19154. (12) Jennings, D. W.; Newberry, M. Paraffin Inhibitor Applications in Deepwater Offshore Developments. Presented at the International Petroleum Technology Conference, Kuala Lumpur, Malaysia, December 3-5, 2008; IPTC 12127. (13) Jennings, D. W.; Yin, R.; Weispfennig, K.; Newberry, M. Tratamento de Problemas com Agentes Quı´ micos na Produc-~ao de Petr oleo. Presented at the Rio Oil & Gas Expo and Conference 2004, Rio de Janeiro, Brazil, October 4-7, 2004; IBP18904.
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completely prevent it. In addition, it is desired that the paraffin inhibitor cause a softer deposit to be formed. In some instances, some inhibitors can reduce the amount of wax deposition but create harder deposits. In the selection of a paraffin inhibitor for an application, an inhibitor that reduces deposition and gives a softer (or equivalent) deposit to untreated deposition is desired. Because paraffin inhibitors do not usually completely prevent all deposition, depending on the amount of inhibition achieved, some additional method of remediating wax deposition may still be needed. Other remediation methods include pigging, wireline cutting, hot oiling, solvent treatments, and dispersant treatments. When used in conjunction with paraffin inhibitors, the frequency of other remediation operations can be reduced. Also, for pigging and wirelinecutting operations, these may potentially be performed more easily if paraffin inhibitors that produce weaker/softer deposits are applied. For pour-point concerns, PPDs prevent the spread of the wax crystal network through impeding the crystal branch growth by incorporation into and modifying the crystal structure. In addition, the PPDs also weaken the altered network structure, which allows production flow shear forces to more easily break the network branching. The overall result is lower crude oil viscosity and the potential prevention of solidification of the crude oil at system operating temperatures. In some instances, the performance of the PPDs can be dramatic. PPDs have been used in many applications in which production would not have been possible without the PPD. Over 30 °C depression in the pour-point temperature has been achieved in some crude oils. As one would expect, the performance of paraffin inhibitors/PPDs is dependent on the specific crude oil, production conditions, and the paraffin inhibitor/PPD used for treatment. The performance is also related to the dosage of active polymer applied. The dosage of the active polymer depends, of course, on the overall product treatment rate and the product activity. As such, the formulation and application method can strongly influence the performance of an application. Paraffin inhibitors are typically formulated into products with active polymer(s) contained in a solvent. The amount of polymer that can be placed into solution depends on the thermodynamic phase behavior of the polymer solution. This depends on the polymers, solvents, and temperature. Depending on the temperature, pressure can also significantly affect the phase behavior of the polymer solution. Pressure effects will be discussed later with applications in deep-water systems. Also discussed later are two other types of applications that do not employ traditional solvent-based formulations: heated injection and use of dispersions. Parts A and B of Figure 3 show pictures of some active polymers and traditional solvent-based products of paraffin inhibitors. Figure 3A is a picture of four different highly concentrated polymer chemistries, as produced from the reactor. These particular polymers contain small amounts of residual solvent (from the reaction process) but are all solid at room temperature. Figure 3B is a picture of three traditional solvent-based products used for surface injection and deep-water umbilical applications.
Figure 3. (A) Examples of concentrated paraffin inhibitor polymers, as manufactured from the reactor. (B) Example paraffin inhibitor products formulated in the solvent.
of interest at conditions simulating actual field conditions (as best as possible in the simplified laboratory tests). Paraffin Inhibitor Evaluation. Paraffin inhibitors are typically evaluated using cold fingers (or similar type apparatuses) and flow loops.14-17 Cold-finger-type methods are more common, largely because of the advantages of small sample size requirements and ease of operation. This is important because the selection of a paraffin inhibitor for an application often involves a multitude of testing for (A) screening the performance of different inhibitors to determine the most effective products and (B) evaluating the effect of the dose rate on the performance for recommending a treatment dose rate. In cold-finger testing, a temperature differential is set between the bulk crude oil temperature and the cold-finger probe to simulate (as best as possible in a simple single test) the deposition region of a section of a flowline. Comparison (14) Bern, P.; Withers, V. R.; Cairns, R. J. R. Wax Deposition in Crude Oil Pipelines. Presented at the European Offshore Petroleum Conference and Exhibition, London, October 21-24, 1980; EUR 206. (15) Thomas, D. C. Selection of Paraffin Control Products and Applications. Presented at the SPE International Meeting on Petroleum Engineering, Tianjin, China, November 1-4, 1988; SPE 17626. (16) Wang, K.-S.; Wu, C.-H.; Creek, J. L.; Shuler, P. J.; Tang, Y. Evaluation of Effects of Selected Wax Inhibitors on Paraffin Deposition. Pet. Sci. Technol. 2003, 21, 369–379. (17) Jennings, D. W.; Weispfennig, K. Effect of Shear on the Performance of Paraffin Inhibitors: Cold Finger Investigation with Gulf of Mexico Crude Oils. Energy Fuels 2006, 20 (6), 2457–2464.
Evaluation of Paraffin Inhibitors and PPDs The selection of paraffin inhibitors and PPDs is usually based on laboratory tests of products on the specific crude oils 2339
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of the deposition in tests of untreated crude oil samples with paraffin-inhibitor-treated samples provides an indication of the performance of the inhibitors. This not only provides the basis for selection of the best performing inhibitors and recommended treatment rates but sometimes also is a source of information on the field performance. If wax deposition is severe, the effect of deposition is generally very evident. So too will be evident whether the paraffin inhibitor is performing well. If the deposition build-up is just gradual, like in most systems, the effect of deposition (or the change in deposition from the inhibitor application) may not be easily used to quantitatively gauge the performance, particularly over short time periods. Because deposition monitors do not exist, field data are often limited to the examination of pigging returns, changes in production, and pressure drops across flowlines (if adequate instrumentation exists). Correspondingly, later in this paper, cold-finger testing will be presented to provide some indication of the field performance for some example applications. Note though that cold-finger testing can sometimes be more severe on the paraffin inhibitor performance than field conditions because (1) the temperature differential is exaggerated to simulate a long section of flowline and (2) shear conditions in the coldfinger testing may be significantly less than those in highrate-production fields. An exaggerated temperature differential causes increased wax deposition, which makes a more difficult treatment situation for the paraffin inhibitor. Increasing shear force (as present in many high-rate-production fields) has been shown to increase the paraffin inhibitor performance.17 As a result, in some cases, the paraffin inhibitor performance in the field may actually be better than the cold-finger testing performance. The apparatus and procedure for the cold-finger testing presented later have been described elsewhere.18 A brief description is given here though. A schematic of the coldfinger device used is shown in Figure 4. Each device consists of two cold fingers connected to a circulating water bath. The circulating water bath controls the temperature of each cold finger. The actual cold finger is centered within a glass jar assembly filled with crude oil. The cold finger/jar assembly is placed inside a second water bath used to control the crude oil temperature. The crude oil temperature is regulated at the inside wall of the jar. A speed-controlled magnetic stirring
bar in the bottom of the cold-finger jar provides stirring, which creates a rotating flow field. The stirring rate dictates the shear stress at the cold-finger surface. In the tests, the cold fingers are inserted into samples of crude oil, which are stirred for a specified amount of time (usually ∼16 h). Afterward, the cold fingers are removed to compare wax deposit differences between treated and untreated crude oil. The surface oil is rinsed off with cold methyl ethyl ketone. Visual assessments are made of the physical characteristics of the deposits, and photographs are taken for documentation. The deposits are then scrapped from the finger, weighed, and sometimes saved for further analysis. Parts A and B of Figure 5 show examples of how coldfinger testing is used for selecting paraffin inhibitors and treatment rates. Shown are cold-finger results for treating an offshore Gulf of Mexico (GOM) crude oil. Figure 5A shows a comparison of the performance of three paraffin inhibitors applied at 500 ppm. As shown, product A gave the best performance, with ∼80% inhibition of the deposition on a weight and surface area basis. It also outperformed the other products at other dose rates. Figure 5B shows the performance of product A at dose rates ranging from 300 to 1000 ppm. At dose rates of 500 ppm and above the inhibitor, the performance was the same. At dose rates below 500 ppm, the performance declined. For this application, product A was recommended at a treatment rate of 500 ppm. From the testing, the paraffin inhibitors provide good inhibition with this particular crude oil. The performance of paraffin inhibitors can vary widely depending on the crude oil, its production conditions, and the available choice of paraffin inhibitor products for treating the application. In some cases, paraffin inhibitors can be very effective at reducing wax deposition. In other cases, however, they might provide only little performance. As such, performance testing is essential for evaluating the potential for paraffin inhibitor applications. PPD Evaluation. PPDs are typically evaluated using ASTM pour-point tests, rheology measurements, and model pipeline studies.10,12,19 The testing is often used to evaluate the PPD’s ability to keep waxy crude oil fluid and to reduce the strength of the gelled crude oil. To evaluate the ability to remain fluid, ASTM pour-point test methods and rheology measurements are typically used. The rheology measurements are typically viscosity profiles versus temperature run at a controlled cooling rate. In the viscosity profile, when the crude oil starts gelling, the viscosity dramatically increases upward. To evaluate reducing gel strength, rheology yield stress measurements and model pipeline measurements are used. Figures 6 and 7 show two examples of rheology testing for evaluating PPDs. Figure 6 shows the effect of a PPD on the alteration of the viscosity profile of a waxy African crude oil. Shown is the viscosity profile of untreated and treated highpour-point crude oil. In this example, the crude oil is treated with (1) a low-wax-content diluent crude oil and (2) the diluent crude oil and a PPD. The viscosity measurements were performed on a rheometer using a parallelplate geometry at low shear stress and a cooling rate of 0.5 °C/min. The untreated crude gels on the rheometer at
(18) Jennings, D. W.; Weispfennig, K. Effects of Shear and Temperature on Wax Deposition: Investigation with a Gulf of Mexico Crude Oil. Energy Fuels 2005, 19 (4), 1376–1386.
(19) Carniani, C. Merlini, M. Basic Design of Waxy Oil Transportation through Improved Lab Testing. Presented at the SPE European Petroleum Conference, Milan, Italy, October 22-24, 1996; SPE 36836.
Figure 4. Schematic of the cold-finger apparatus used in evaluating paraffin inhibitors.
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Figure 5. Example of cold-finger testing for the selection (A) of paraffin inhibitors and of (B) paraffin inhibitor dose rate recommendation.
Figure 6. Example of PPD evaluation using rheometry measurements: viscosity-temperature ramp profiles.
∼40 °C. The addition of the diluent crude oil alone only shifts the gelling temperature to about 36 °C. The diluent does, however, reduce the wax content enough that the addition of a PPD is able to provide a very significant reduction in the viscosity profile of the crude oil. With diluent and PPD addition, the gel point was lowered to ∼9 °C, approximately a 31 °C reduction. This example illustrates the great potential
of PPDs to affect the ability of waxy crude oils to flow. If the gel point/pour point is very high (greater than 35 °C), a diluent often will be required in the addition to the PPD to achieve the desired performance. If the gel point/pour point is lower, the PPD application alone may be sufficient. In addition to altering the viscosity and gel point of waxy crude oils, PPDs can also alter the strength of a gelled waxy 2341
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Figure 7. Example of PPD evaluation using rheometry measurements: yield stress of a gelled waxy crude oil.
crude oil. This can be important for restarting shut-in flowlines with crude oil below its pour point. The most common method for measuring the effect of PPDs on the alteration of the strength of gelled waxy crude oil is to perform yield stress measurements with a rheometer. Figure 7 shows an example of a PPD changing the yield stress of a gelled Far East crude oil. In this example, crude oil samples were allowed to gel at 18 °C and condition for 3 h in between the parallel plates of a rheometer. Afterward, the samples were subjected to stress ramps to measure the point at which the samples would yield. Shown in Figure 7 are the results for the untreated crude oil and crude oil treated with a PPD at 500 and 2000 ppm. Shown is the stress applied on the sample versus the shear rate that the rheometer turns. If the sample does not yield, the rate is zero. The yield stress is the stress at which the rheometer starts turning. The yield stress of the untreated crude oil was ∼20 000 dyn/cm2. The yield stresses of the PPD-treated samples were considerably less. The sample treated at 500 ppm yielded at ∼500 dyn/cm2. The sample treated at 2000 ppm yielded at the first commanded stress ramp step (∼100 dyn/cm2).
Figure 8. Example heated injection skids (A) on site and (B) in operation in Africa.
tions, the heating at the injection tank is sufficient to keep the product liquid through the injection pump and injection lines because ambient temperatures are not extremely cold and the injection skids are located in close proximity to the injection point. As mentioned earlier, with heated injection the potential to apply the lowest dose rate exists. The treatment rate can often be reduced by 50% or more with heated injection. Figure 9 illustrates a typical difference of using heated injection versus a standard surface injection formulation. In the figure, the PPD performance of a heated injection product is compared with that of a surface injection product on a waxy African crude oil. The untreated crude oil has a “gel point” on the viscosity profile of ∼37 °C. Both the surface injection and heated injection PPDs are very effective at reducing the gel point. A reduction of approximately 25-27 °C is obtained at the dose rates presented in Figure 9. The surface injection product requires a higher dose rate because it is less active. Here the surface injection product was applied at 3750 versus 1500 ppm for the heated injection product. Note that the two products are not just different formulation packages of the same chemistry but actually have different chemistry classes. If examined on the basis of the active PPD polymers, the surface injection product
Applications Heated Injection. Heated injection allows very concentrated products (potentially up to 100% active) to be used. In addition, the full range of paraffin inhibitor/PPD polymer chemistries can generally be considered because chemistries are not rejected because of their inability to be sufficiently formulated in traditional solvent-based products for the application. As such, heated injection will give the lowest treatment rates and yearly chemical costs. Note that evaluation of the overall chemical cost will, however, need to factor in the cost of the injection system. For heated injection, heating may be required for the chemical storage, injection tanks, injection pump, and injection lines. Typically, only moderate temperatures (∼50-60 °C) are required to be maintained though because the melting points for the concentrated paraffin inhibitor polymers are not high. Parts A and B of Figure 8 show heated injection skids at a customer facility in Africa. Figure 8A shows skids awaiting installation, and Figure 8B shows a skid in operation located very near the injection point at the well-head. In these applications, the skids only provide heating to the injection tank. Note that in Figure 8A the pumps (at the lower right) are not heat-traced. For this customer’s applica2342
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more than three billion dollars for a large development. Hence, there is much design work and many decisions to be made up-front in deep-water developments regarding how potential concerns for flow assurance issues related to wax, asphaltene, scale, and hydrate control will be collectively managed. Because development of deep-water fields is very expensive, it is important that all components of a development function appropriately, including any chemical injection systems. In some cases, the chemical may be an integral part of the development’s flow assurance management process. Subsea Wells. In subsea wells, the well-head and tree are situated on the seafloor. These wells are tied-back to the host production facility via the particular subsea configuration employed for the development. The subsea system can be as simple as a single flowline tie-back from the well to the host facility riser. More commonly, multiple wells are manifolded to combine production through dual flowlines, leading back to the host facility. Dual flowlines are commonly used to allow capabilities for pigging the flowlines. With dual flowlines, a pig can be launched from and return to the host facility. For controlling wax deposition, pigging is the most used method in deep-water subsea systems today. Wax deposition is common in production from subsea wells because deepwater seafloor temperatures are cold (∼4 °C) and the wells are often miles from the host facility. Whether deposition occurs and the potential severity of the deposition depend on the crude oil composition and the flowline temperatures. If the crude oil has an appreciable wax content and the flowline is a significant distance from the host facility, deposition is usually certain. Flowline heating and insulation can change the deposition characteristics. Flowline heating can prevent deposition completely if the flowlines can be heated above the crude oil wax appearance temperature. Heating is rarely used though. Costs and reliability concerns are major issues with heating. Insulation is widely used though. It is primarily employed to prevent hydrate formation during steady-state production. Depending on the particular crude oil and system, insulation in some incidences may keep flowline temperatures warm enough (under steady flow conditions) all the way to the host facility such that wax deposition does not occur. In other incidences, it may only be able to shift the wax deposition region to a location further downstream in the flowline. Insulating flowlines incurs significant cost though. An insulated flowline can cost approximately twice that of an uninsulated flowline. Pigging is the primary wax control method used in deepwater subsea systems. Although the actual cost of running a pigging operation is minimal, significant costs can be associated with using pigging for wax deposition control. There is always a danger associated with the potential for sticking a pig in the flowline as well. The primary costs associated with pigging are the capital cost of installing dual flowlines and deferred production costs during pigging operations. The capital cost of installation of dual flowlines over a single flowline can be substantial. However, there may be other reasons for selecting dual flowlines. For example, dual flowlines can offer possibilities for individual well testing. The cost of deferred production depends on the particular system: the frequency of pigging and the amount of production lost during pigging. For a deep-water development, 1/2 to 1 day deferred production is typically incurred in each pigging run because production is usually required to be
Figure 9. Example of typical PPD dose rate reductions possible by using heated injection versus typical surface injection products.
chemistry actually provides a slightly better performance than the heated injection product chemistry. However, the surface injection product is a commercial product initially formulated for use at temperatures down to near-freezing (0 °C) for winter-time use in the GOM. Subsequently, this product has been (and continues to be) used in other geographic regions as well. However, as a result of being formulated to pump at near-freezing temperatures, it requires more than twice the heated injection product dose rate for an approximately equivalent performance on this particular waxy Africa crude oil. Again, this example is representative of the typical reduction in chemical dosage that can be achieved with heated injection. Surface Injection. Climates vary greatly depending on the geographical location and time of year. As such, conditions placed on paraffin inhibitor/PPD surface injection products often vary depending on where the application is located and the time of year. In tropical regions, temperatures are warm year-round and traditional solvent-based formulations that have relatively high activity can be used. In temperate regions, temperatures can vary greatly from summer to winter. Hence, there is the potential to customize treatments by switching-out products for seasonal use to optimize treatments. In practice, this is rarely done because many customers prefer just one product that can be used yearround. As a result, most products applied at a location are formulations suitable for the coldest periods of the year. Consequently, the product activity is not always the optimal activity that could be applied in the warmer periods of the year. For example, in the GOM winter temperatures occasionally will approach near-freezing (0 °C/32 °F). Consequently, many surface injection products for GOM applications are formulated for use at temperatures down to freezing. Summer temperatures are significantly warmer though. GOM summer daytime high temperatures can reach to 100 °F/ 37.8 °C (or more) and summer night-time low temperatures rarely go below 70 °F/21.1 °C. Deep-Water Applications. Deep-water developments may handle production from either subsea or dry-tree wells. The chemical delivery and constraints placed on deep-water application chemicals differ depending on whether subsea or dry-tree wells are being treated. Deep-water field developments can range from approximately one-quarter billion dollars for a small development to 2343
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shut-in to send the pig from the host facility. For high-rate production systems, this can be a significant amount of deferred production, particularly if the operation has a high pigging frequency. In these instances, reducing the pigging frequency can provide a substantial economic return. This is the most common reason that paraffin inhibitors are applied in deep-water developments. Because paraffin inhibitors do not typically provide 100% inhibition, they are often used in conjunction with remediation methods such as pigging. If the value of saved deferred crude oil production (from a reduced pigging frequency with paraffin inhibitor application) is greater than the cost of the paraffin inhibitor program, then paraffin inhibitor use is usually judged worthwhile. Paraffin inhibitor applications may potentially allow pigging operations to be performed more easily if a paraffin inhibitor is selected, which produces a weaker/softer deposit. Hence, with paraffin inhibitor use, the danger of blocking a flowline with a stuck pig can be decreased by reducing pigging frequencies, reducing the amount of wax the pig pushes, and making softer deposits. There are also some safety concerns with pigging operations that would be reduced with less frequent pigging. For these reasons, in some instances, operators have placed a high premium on the use of paraffin inhibitors for reducing pigging. In situations where deep-water flowlines do not have pigging capabilities and appreciable wax deposition occurs, paraffin inhibitor applications are often more valuable to the operator than those for reducing pigging frequencies. Situations where pigging may not be possible include singleflowline tie backs and instances where a dual flowline becomes incapable of being pigged (from damage, stuck pig, etc.). If an operator can use a single flowline, the potential for significant capital savings exists. Paraffin inhibitor application may control wax deposition in some systems to the extent that the operator has confidence to go with a single-flowline development. Delivery of paraffin inhibitors (and other chemicals) for subsea wells is through an umbilical line. The umbilical line is a bundle of small-diameter tubing cores, cables, and shielding that carries chemicals, hydraulic fluid, electrical power, and fiber-optic signals along the seafloor to the subsea system. The chemicals in the umbilical line are subjected to fairly stringent conditions with respect to temperature and pressure. The temperatures of the chemicals in the umbilical reach deep-water seafloor temperatures (∼4 °C). The pressure in the umbilical chemical lines is closely related to the flowing pressure in the flowline at the chemical injection point. The most common injection point for paraffin inhibitors is at the subsea tree. Capillary injection downhole into the well is also used. If the paraffin inhibitor is injected downhole, the pressure in the umbilical line is greater because the downhole pressure is greater than the well-head pressure. At cold deep-water seafloor temperatures, the solubility of the waxlike paraffin inhibitor polymers is significantly reduced from that at higher temperatures (even room temperature). In addition, as illustrated below, the pressure also affects the stability of the paraffin inhibitors. This is very important because product requirements for deep-water umbilical applications are very stringent. The products must remain completely fluid and solids-free so as to not jeopardize the umbilical injection line. In particular, flow paths through check-valve assemblies, often at the end of the umbilical injection path, are very narrow and may not be
Figure 10. Effect of the elevated pressure on the paraffin inhibitor product stability.
Figure 11. Effect of the concentration on the paraffin inhibitor product stability at 4 °C and elevated pressure.
sufficiently robust to withstand any particles. A plugged or otherwise damaged umbilical line is most often unable to be repaired. Also, spare umbilical lines are generally nonexistent. As a result, the activities of paraffin inhibitors formulated for deep-water subsea injection are lower than paraffin inhibitors formulated for surface injection. Also, some of the more effective paraffin inhibitor chemistries are not used because of problems in formulating them for deep-water umbilical conditions. Figures 10 and 11 illustrate the effect of the pressure and polymer concentration on the paraffin inhibitor product stability at deep-water temperatures. Shown are high-pressure viscosity measurements for different paraffin inhibitor formulations. A commercial high-pressure viscometer has been found useful to not only measure product viscosities but also detect conditions where paraffin inhibitor products have exhibited signs of instability because of increasing pressure at cold temperatures. Because fluid samples in the viscometer sit in a very narrow annulus (only thousands of an inch gap), the viscometer is very sensitive to fluid changes. At cold temperatures, many of the paraffin inhibitor products were found to be unstable (continual increasing viscosity readings) after reaching certain pressure limits. Because this phenomenon was observed only at subambient temperatures, it is believed to be related to the pressure affecting the solubility of the waxlike paraffin inhibitor polymer at 2344
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Figure 13. Paraffin inhibitor cold-finger performance on a GOM deep-water subsea well crude oil (example 2). Figure 12. Paraffin inhibitor cold-finger performance on a GOM deep-water subsea well crude oil (example 1).
example. Often higher dose rates are required and inhibition levels are lower because of reduced product activities in order to meet stability requirements at the respective deep-water injection conditions. Such is the case in the second deepwater application example shown in Figure 13. In this field, the crude oil has a high wax deposition rate. In addition, the wells are single-flowline tie backs without pigging capabilities. As such, paraffin inhibition is important for this operation. The paraffin inhibitor used in this field was found to provide approximately 40% inhibition at 1000 ppm in cold-finger testing simulating the flowline. Even though the inhibition levels are not near 100% (like in the first deepwater example), achieving 40% reduction in wax deposition is very significant. Also, with the higher shear forces and lower bulk fluid-wall temperature differentials in the actual flowline, the paraffin inhibitor performance in the field can be greater than that in the cold-finger testing.17,20 Dry-Tree Wells. For capillary injections in deep-water dry-tree wells, the capillary tubing is typically either run within the production tubing or strapped to the outside of the production tubing and connected to an injection mandrel. As a result, the chemical injected in the capillary tubing is warmed by the production flow and does not reach the seafloor temperature during normal operation. Consequences during an extended shut-in (where the capillary tubing will cool) are generally not a concern either. Once production is restarted, the capillary line will warm back up. Also, only a limited portion of the capillary tubing is located near the seafloor. The capillary line portions located below downhole and above (in shallower water depths) will be warmer because of geothermal heating from the reservoir and warmer water temperatures in shallower water. As a result, paraffin inhibitor products used in capillary injection in deep-water dry-tree wells do not necessarily need to be restricted to the same low seafloor temperature and pressure constraints as products injected through an umbilical line to subsea wells. This can allow products with higher activities and potential alternative chemistries to be included in product selection. This translates into obtaining a better performance from the paraffin inhibitor application. Figure 14 illustrates the cold-finger performance of a paraffin inhibitor currently being applied to the treatment of deep-water dry-tree wells in a GOM field. This particular
cold temperatures. The pressure at which paraffin inhibitor products have exhibited these solubility issues at deep-water temperatures varies depending on the specific polymers, solvent, and polymer concentrations in the formulation. Note that other oil-field treatment product line chemistries have not exhibited pressure sensitive behavior like the paraffin inhibitor polymers. Figure 10 shows measurements of one paraffin inhibitor product, which at 4 °C has stability concerns at 3000 psi and above. At 2000 psi and below, the product is stable. As such, this product is not suitable for deep-water umbilical application because pressures from just the head of the liquid can be ∼2000 psi. Depending on the water depth/water temperature and injection pressure, the product is suitable for some shallower water applications. At room temperature (21 °C), there is no effect of the pressure on the product stability within the limits tested. If the concentration of the polymer is varied, the point of instability can be altered. This is illustrated in Figure 11, which shows high-pressure viscosity measurements of the same paraffin inhibitor product as that shown in Figure 10 and dilutions thereof. If the product is diluted 50%, the pressure limit of instability is shifted from approximately 3000 to 10 000 psi. If it is diluted further to 70%, the product is stable to greater than 15 000 psi. The pressure at which a certain paraffin inhibitor product might exhibit signs of instability depends on the temperature and product formulation: polymer chemistry, polymer concentration, and solvent. As a result, recommended maximum pressure limits are given with each paraffin inhibitor product formulated for deep-water umbilical applications. Figures 12 and 13 illustrate the performance of paraffin inhibitors in two deep-water GOM subsea developments. Shown is cold-finger testing for the two different field crude oils. Figure 12 shows cold-finger testing at conditions closely simulating the deposition region of the flowline for a field with pigging capabilities. In this system, the crude oil has a mild to moderate wax deposition rate, which is very effectively controlled with paraffin inhibitors. As shown in the figure, the paraffin inhibitor applied in the field controls the deposition almost completely at 300 ppm. Over 90% inhibition was obtained in the cold-finger testing. Unfortunately, paraffin inhibitor performance is not always as effective as that in the first deep-water application
(20) Subsea Control of Paraffin Deposition. Baker Petrolite Case History BPCH7273 PET-9-26617 (a GOM field pigging experience using paraffin inhibitor).
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Figure 15 shows the viscosity profile of treated and untreated samples of the West African crude oil as a function of the temperature. The viscosity profiles are from rheometer measurements conducted with a parallel-plate geometry, where the crude oil was cooled from 60 °C under low shear conditions at a cooling rate of 0.5 °C/min. The umbilical PPD data are from the actual product selected and applied during the well test. The dry-tree PPD data are from a GOM surface injection/deep-water dry-tree product. Both products provided very good performance at reducing the gel point of the crude oil in the rheometer testing. Approximately 30 °C reduction over that of the untreated crude oil was obtained. Relatively high dose rates were required though. A dose rate of 4000 ppm was required for the umbilical-qualified product and 3000 ppm for the dry-tree product. Not only did the dry-tree product require a lower dose rate, but the drop-off in the performance at lower dose rates was not as great as that with the umbilical product. Improving Deep-Water Subsea Paraffin Inhibitor Formulations. One method to increase the activity (and therefore performance) of paraffin inhibitor formulations for deepwater umbilical applications is to optimize the solvent in the formulation. Unfortunately, because the aromatic solvents used in most formulations are very good solvents of the paraffin inhibitor polymers, there is a limit to how much improvement can be obtained. The waxlike paraffin inhibitor polymers are just not inherently highly soluble at cold temperatures, in even the best solvents. If the solvent is optimized, a significant increase in the solubility and stability can be obtained though, or, alternatively stated, the activity of a product for use at a given temperature and pressure can be increased, or an increase in the pressure limit at which the product can be applied is achieved. Optimizing the solvent for paraffin inhibitor formulations is discussed in the United States Patent literature.21 Figure 16A illustrates the potential increase in the product stability that can be obtained for deep-water umbilical products. Shown are high-pressure viscosity measurements at 4 °C of a paraffin inhibitor product, as currently formulated and as a potential product formulated with optimized solvent. The product, as currently formulated, exhibits stability to 5000 psi, whereas, with the optimized solvent formulation, the product exhibits stability to 12 000 psi. The optimized solvent formulation cost would be only slightly greater than that of the product as currently formulated. However, this formulation does have a significantly lower flash point. Figure 16B provides another illustration of the potential increase in the product stability of another product with two different optimized solvent formulations. Like Figure 16A, it is a comparison of high-pressure viscosity measurements at 4 °C of the paraffin inhibitor as currently formulated with alternative solvent formulations. The product as currently formulated exhibits stability to 7500 psi. When formulated with an optimized solvent with a lower flash point (like in Figure 16A), the stability can be increased to 12 500 psi. If the flash point cannot be lowered, a different alternative solvent formulation could be used to increase the maximum pressure limit for stability to 10 000 psi. This equivalent flashpoint formulation would, however, have significantly higher cost.
Figure 14. Paraffin inhibitor cold-finger performance on a GOM deep-water dry-tree crude oil.
Figure 15. Comparison of the PPD performance of a deep-water umbilical product with deep-water dry-tree product on a deep-water African crude oil.
paraffin inhibitor is suitable for near-freezing winter-time surface injection conditions in the GOM but not suitable for handling the combined cold deep-water temperature and pressure effects. The cold-finger testing in the figure was performed with a temperature differential closely simulating that of the deposition region in the dry-tree production tubing string for the well. Note that the paraffin inhibitor provides very good inhibition (∼80% or better) once the dose rate increases to 300 ppm and greater. Although not shown, corresponding deep-water subsea umbilical products required an approximately 200 ppm higher dose rate to achieve a similar performance. To further illustrate the potential for improved performance for dry-tree products over subsea umbilical products, Figure 15 compares the performance of two PPD products for reducing the viscosity and gel point of a waxy West African crude oil. The data are from actual testing for product selection for a PPD application for use during a deep-water well test. Because the gel point of the crude oil was ∼34 °C, concerns existed about the ability to flow the crude oil during the well test and to restart, should production be shut down. Because this was not a conventional production system, it was uncertain as to whether the PPD needed to be deep-water umbilical-qualified or whether a product suitable for deepwater dry-tree application could be used. As a result, products used for both deep-water umbilical and GOM dry-tree applications were initially tested. Ultimately, it was decided that an umbilical-qualified product would be used.
(21) Jennings, D. W. Paraffin Inhibitor Compositions and Their Use in Oil and Gas Production. U.S. Patent 7,541,315, 2009.
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Figure 17. Example of winterized dispersed paraffin inhibitors.
dispersion products. Note that their appearance is much different from that of the traditional solvent formulations shown in Figure 3B. Figure 18 shows the performance of a range of different types of paraffin inhibitor formulations. This figure illustrates how the ability to increase the paraffin inhibitor activity and/or use more favorable chemistries can improve the performance. Cold finger testing at 500 ppm is shown for a range of different types of paraffin inhibitor formulations compared to an untreated Canadian crude oil. On the top row, the performances of four solvent-based products are shown. The surface injection subarctic product is very dilute with respect to the active chemistry. It is also not one of the more favorable chemistries. As a result, it provides little to no performance at 500 ppm. The surface injection product for temperate climates is starting to provide some inhibition, but the inhibition level is only ∼12% at 500 ppm. The two surface injection products for tropical climates give very good performance. Approximately 90% inhibition was obtained. These products have favorable chemistries at relatively high activities because the products are restricted to use in warm regions only. On the bottom row, the performances of products formulated for cold-temperature applications are shown. The results for a deep-water umbilical product (unoptimized solvent), a winterized solvent-based product, and two winterized dispersion products are presented. The deep-water umbilical and winterized solvent products yield respectable inhibition with ∼36 and 43% inhibition, respectively. If the dose rates were increased, these products would provide better inhibition. The deep-water product is usable to only ∼4 °C. The winterized solvent product is usable to -20 °C. Better performance is observed from the winterized dispersions, which can be applied to -40 °C. These provided inhibition similar to that of the tropical surface injection products, ∼90%. The reason that the winterized paraffin inhibitor dispersions performed better than the solventbased products (excluding the tropical surface injection
Figure 16. Effect of optimizing the solvent formulation for increasing the maximum operating pressure limit for deep-water umbilical paraffin inhibitors: (A) example 1; (B) example 2.
Subfreezing Applications. As temperatures get colder, the challenges get even harder for formulating paraffin inhibitor products that are fluid and pumpable without heated injection. Depending on the temperature, there are a couple of different options that can be pursued that do not require heated injection. Heated injection is still a very desirable application method if it is a viable option for a site. Moderate-Freezing Conditions (0 to -20 °C). If the temperatures do not get too extreme, the option for using winterized solvent-based formulations based on optimization of the solvent (as discussed for deep-water umbilical products) is a possibility. These formulations have limitations, of course, in that high polymer activity cannot be achieved. Also, certain chemistries are not favorable for these types of formulations. However, despite these limitations, good performance at reasonable dose rates can be achieved on some crude oil production systems. These winterized solvent-based formulations are also less expensive than winterized dispersion formulations required for colder temperatures. Extremely Cold Conditions (-20 to -40 °C and Below). If temperatures go below -20 °C, then traditional solventbased formulations are not practical because the activity becomes too dilute. A method to obtain high-activity products that are pumpable without heated injection is to use winterized paraffin inhibitor dispersions. In winterized dispersions, the paraffin inhibitor is suspended as micrometersized solid particles in an aqueous alcohol-based carrier fluid. In this manner, relatively high activity products that are fluid and pumpable in extreme cold temperatures can be manufactured. In addition, favorable chemistries can be used. Figure 17 shows two winterized paraffin inhibitor 2347
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Figure 18. Comparison of the cold-finger performances of different types of paraffin inhibitor formulations on a Canadian crude oil.
products) is that the dispersions have a combination of favorable chemistries at relatively high activities. In fact, the winterized dispersions shown in Figure 18 actually contain the same chemistries as the tropical surface injection products shown but are formulated such that the products can be pumped at temperatures down to -40 °C. Winterized dispersed paraffin inhibitors have been applied at various locations in continuous, batch, and squeeze applications. Continuous injection is always preferred. Application down the backside of a well is one of the most common applications. Potential New Application for Development. Winterized dispersed paraffin inhibitors were developed for applications in extremely cold locations. However, they are also suitable for applications in less stringent temperatures. In fact, a winterized dispersed paraffin inhibitor formulation has the ability to contain higher activities and more favorable chemistries than traditional solvent-based formulations used at just near-freezing temperatures (0 °C). This leads to the question as to whether a winterized dispersed paraffin inhibitor formulation may provide advantages for applications in deep-water subsea wells. As discussed, the paraffin inhibitor performance is depressed in deep-water subsea applications because of constraints in formulating the paraffin inhibitors to be stable at seafloor temperatures and elevated injection pressures.
The challenge in applying a dispersed paraffin inhibitor in subsea umbilical applications would be in ensuring that the products are suitable for injection in all of the subsea components. Currently subsea products must be stable and solids-free because narrow flow paths in the injection lines and check-valve assemblies might not tolerate solids. Many operators even require products to pass certain National Aeronautical Standards for cleanliness. Because winterized dispersions are suspensions of solid particles, these products would not pass these standards even immediately following manufacture. Also, overtime separation can occur in products. The stability and type of separation depends on the product. Nonetheless, the stability of the product and consistency of manufactured batches would be major issues needing to be addressed for applying dispersions in subsea umbilicals. As such, significant engineering would likely be required to develop and test a dispersed paraffin inhibitor deep-water umbilical injection system. The potential payoff for developing such a system is improved paraffin inhibitor performance, which may enable an operator to choose a single flowline development over dual flowlines in some instances. This could provide significant capital savings. Figure 19 illustrates the potential improvement in paraffin inhibitor performance. Shown is cold-finger testing for a relatively difficult-to-treat deepwater crude oil. The figure shows a comparison of the 2348
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Paraffin inhibitors are typically formulated into products with the active polymer(s) contained in a solvent. This allows the active portion to be easily delivered to the desired stream to be treated. The amount of polymer that can be placed in the solution depends on the thermodynamic phase behavior of the polymer solution, which depends on the polymers, solvent, and temperature. Depending on the temperature, the pressure can also significantly affect the phase behavior of the polymer solution (as occurs in deep-water umbilical applications). If the temperature constraints can be controlled through the use of heated injection, very highly concentrated products (potentially 100% active) can be applied. As such, heated injection provides the best performance at the lowest treatment rates. If heated injection is not possible, then means to optimize formulations may be worth considering. Two methods to improve formulations include (1) optimizing the solvent used to dissolve the polymers and (2) formulating the product as pumpable dispersions. Examples of both of these methods were discussed in the paper. The paper also discussed a variety of different continuous injection applications in different environments. The applications discussed included heated injection, surface injection, deep-water drytree injection, deep-water umbilical applications, and applications in subfreezing environments (from moderate freezing conditions to extremely cold arctic temperatures). Several examples of applications in these different environments were presented to illustrate the performance of paraffin inhibitors for reducing wax deposition and PPDs for improving flow properties.
Figure 19. Comparison of the cold-finger performance of a deepwater umbilical paraffin inhibitor with a winterized dispersed paraffin inhibitor.
performance at 750 ppm of a deep-water umbilical paraffin inhibitor compared to a winterized dispersed paraffin inhibitor. The dispersed paraffin inhibitor is able to almost completely inhibit deposition at 750 ppm in the cold-finger test, whereas the deep-water umbilical product provides only ∼24% inhibition. Although the product chemistries are different, the improved performance is largely a result of increased product activity. Conclusions Paraffin inhibitors are used worldwide in a variety of applications and environments. These applications include inhibitors for preventing wax deposition and PPDs for improving petroleum flow properties. The formulation of products for specific application environments plays a big role in the performance of the products. Constraints from the conditions that the products are subjected to can limit how much of the active polymer is contained in the product.
Acknowledgment. The authors thank and acknowledge Marwin Saleh for information and pictures regarding Baker Hughes Africa operations. The authors also thank Mike Newberry for many helpful discussions.
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