Wax prevention and remediation in subsea pipelines and flowlines

As the industry moves to ultradeep water, mitigation alternatives will be critical to sustain production efficiency.  

Saeid Mokhatab, Contributing Editor; and Brian Towler, University of Wyoming, Laramie

Paraffin wax deposition costs the oil industry billions of dollars worldwide for prevention and remediation. Paraffin precipitation and deposition in crude oil transport flowlines and pipelines is an increasing challenge for the development of deepwater subsea hydrocarbon reservoirs. If sufficiently deposited over time, wax can partially or totally block oil production to uneconomical levels requiring shutdowns and/or various remediation treatments. The increasing exploitation of deepwater fields makes it critical to understand the mechanism of wax depositions and how to prevent and remediate wax deposits in deepwater production operations.

INTRODUCTION

Subsea production systems help exploit deepwater resources, but as tieback distance increases, flow assurance becomes a serious problem. Pipeline plugging—as a result of different physical and chemical reactions, especially wax formation and precipitation—is one of these new challenges, Fig. 1. This problem has led to significant capital losses associated with the loss of production and the replacement of plugged lines.

Fig. 1. Wax deposition in a pipeline. Photo courtesy of Phillips Petroleum Company and Dr. G. A. Mansoori.

Waxes are typically long linear n-paraffin chains within the produced oil. At temperatures below the Wax Appearance Temperature (WAT) or cloud point, the n-paraffin components begin to crystallize into solid wax particles. They may adhere to each other in this state. Deposition of n-paraffin typically occurs when the wax-containing oil comes in contact with any surface that has a temperature below the WAT and provides a heat sink. The buildup of paraffin deposits decreases the pipeline cross-sectional area, limits operating capacities, and places additional strain on pumping equipment. Uninhibited wax deposition can cause complete flow blockage and costly production shutdowns. In extreme cases of deposition, routine shutdowns have to be scheduled and lines have to be hot-oiled to dissolve the wax.

Establishing mechanisms of wax deposition would help identify the parameters that must be controlled to prevent or minimize wax deposition. There are two proposed mechanisms for paraffin deposition.¹ Shear dispersion describes the relationship between deposition rate and shear rate. Deposition rates decrease with higher shear rates. Molecular diffusion describes the process by which the radial temperature gradient in the tubulars causes a concentration gradient of dissolved paraffin components in the liquid phase. This concentration gradient causes paraffin to diffuse to the pipe wall, where it is assumed to deposit.

The widely recognized transport methods contributing to wax thickness on the pipe wall are molecular diffusion of dissolved wax, particle transport of precipitated wax and sloughing of previously deposited wax. Most researchers in this area agree that molecular diffusion of dissolved wax is the most important contributor in wax deposition. However, the contribution of the particle transport mechanism has not been conclusive, and there remains uncertainty as to its role in the overall wax deposition phenomenon.²

Wax deposition in pipelines is dominated by tetracontane (C₄₀H₈₂) through hexacontane (C₆₀H₁₂₂). This is due, in part, to the likely temperatures in the flow path. It is also due to the effects of pressure, structure and concentration of these components. Wax deposits display only limited solubility at modest temperatures in many types of organic solvents and are virtually insoluble in aqueous solutions, although they can be re-melted (120–150°F). Complete blockages due to wax deposition occur slowly. Due to slow blockage formation, and the ability to re-melt deposits, wax deposition is not often a concern for transient operations, such as a production shutdown.

WAX DEPOSITION PROBLEMS

As oil and gas production moves to deeper and colder water, subsea multiphase production systems become critical for economic feasibility. Paraffin deposition can cause a multitude of problems including:
• Reduction of the internal diameter of the tubulars, restricting and ultimately blocking flow
• Increased surface roughness on the pipewall, causing increased pumping pressure and reduced throughput
• Accumulations that fill process vessels and storage tanks, causing system upsets and costly, labor-intensive cleanup and disposal problems.
• Interference with valve operation and instrumentation.

All of these problems may result in production shutdowns and hazardous conditions requiring extensive workovers, and resulting in production losses and possibly irreparable damage to equipment.

Strategies for successful risk abatement incorporate a comprehensive planning and implementation program, typically involving insulation, pigging operations and chemical treatments in the tieback flowlines. A plethora of thermal, chemical and mechanical measures are available to manage paraffin deposition, on either a preventative or a remediative basis.³ Decisions are typically made early in the pipeline flowline design process to address paraffin deposition issues and to select feasible management methods.

Typical paraffin management systems include chemical wax inhibitors and the implementation of operations such as line heating, warm-solvent/hot-oil circulation and, in shorter lines, mechanical scraping. Prior knowledge of a crude oil’s paraffin stability is necessary for designing appropriate remediation.

Paraffin wax treatment methods can be divided into two main categories: removal of deposits and mitigation of deposition.

WAX TREATMENT METHODS

The most common removal methods are mechanical removal, heat application using hot oil or electrical heating, application of chemicals (e.g., solvents, pour-point dispersants) and the use of microbial products.

In some cases, excellent results have been achieved with these methods. In every case, the control program adds significantly to the cost of oil production.

Mechanical removal. Mechanical methods commonly employ a pig, Fig. 2, which is used widely for removal of wax buildup on the internal wall of a pipeline. However, pigging subsea systems is difficult because access to the installations involves complex and costly operations, requiring high-reliability equipment, facilities and procedures. Thus, some subsea piggable equipment (using dual-size scraper pigs) has been developed, and this has contributed to reducing the high risk in subsea pigging operations. Dual-size scraper pigs and optimized pipeline layouts help sustain production in cold subsea conditions.⁴

Fig. 2. Pigging to remove wax. Photo courtesy of Hydrafact.

In general, a regular pigging program should aim to remove all the wax from the pipeline (wax management, meaning not letting the wax deposit grow to the extent that a pressure buildup is noticed) rather than merely to keep the line open (bore management). Bore management is more suited to pigging of problem lines or lines that have been out of service (using progressive cleaning, i.e. gradual removal of the deposit); but, even then, the ultimate aim should be to completely remove the wax buildup.

Usually, pigging should be performed in combination with chemicals or hot oil. Subsea (topsides-accessible, dual) flowlines can have wax removed with round-trip pigging. As a better alternative, hot oil can be circulated in an attempt to melt the deposit. Single-pipe subsea flowlines can be pigged using subsea pig launchers, but this incorporates increased risk. The implication of a stuck pig for a single-pipe flowline is total loss of production. Additionally, if the subsea pig launcher can only be loaded before installation, the risks also include multiple launches, inability to change pig style, inability to service or perform routine maintenance and inability to retrofit.

Part of the flow assurance strategy decision process is to consider the frequency of remediation. It is crucially important to note that incorrect pigging and pig programs are dangerous, as such programs can lead to the plugging of pipelines. Longer well stepouts and greater export distances have added to the problem because the pigs need to push wax farther. To avoid this, judicious selection of pigging frequency and bypass size is required for all such operations.

Heat application. Heat is applied by various techniques, such as hot oil or hot water injection, steam injection and electrical pipe heating. Thermal methods usually involve hot-oiling the well tubulars and flowlines on a regular basis. This, when applied to the wellbore, sometimes results in formation damage by concentrating heavier ends of the oil and paraffin, which can no longer be mobilized by the heat available through hot-oiling.⁵ Generally, hot-oiling is done on a routine basis and has a cyclic production history. Hot oil treatment of a wellbore usually results in increased production rates, but perforations gradually become plugged and, after some time, production drops off.

During a typical hot oil treatment of a well, crude oil is heated and then pumped down the annulus. Heat is transmitted through the tubing and melts the paraffin deposited on the inside tubing wall. Melted paraffin wax is then carried out by the produced oil-gas stream. But the hot oil itself cools as it moves down the annulus, and solid paraffin wax starts precipitating out of it. If increased fluid levels are achieved as a result of the treatment, then hot oil may move into the perforated section of the well and eventually plug those perforations.

Hot water, usually hot KCI or recently produced water, is considered as an attractive alternative to hot oil injection. These fluids are more attractive because they are less depositable and are able to carry more heat energy. Steam is also used for paraffin removal in tubing, casing, flowlines or the reservoir. This method must be used very carefully in downhole applications, because melted paraffin wax from the inner wall of the tubing may be forced into the formation, where it can coagulate before being carried out by the producing stream.

Electrically heated tubing strings have also been used in limited applications with success,⁶ as have exothermic chemical reactions in combination with inhibitors.⁷ Heat treatment should be applied as early as possible, before large paraffin wax deposits are accumulated in the production equipment.

Over the past 10 years, thermal insulation of subsea flowlines and risers has become increasingly important. Subsea facilities, including flowlines, are insulated as required to meet the minimum arrival temperature at the top of the riser. This temperature will be the optimum temperature to mitigate both wax and hydrate formation.

Additionally, the selected wax and hydrate prevention strategy will be taken into account to ensure safe and efficient practices in operation of the subsea system for both regular production and well testing scenarios. Insulation is also designed to provide a minimum reasonable period for repair and restart in the event of an unplanned shutdown, which would result in gelling of the crude in the lines. For single-pipe flowlines and risers, mechanical loads as well as the thermal insulation requirements normally increase with deeper waters. Hence, traditional thermal insulation foam used in shallow waters and the associated design and test methodology may not be applicable to deepwater projects.

Polymer foams change mechanical and thermal properties as a function of foam density. Higher density normally means better mechanical properties, and reduced density improves insulation capacity. For deepwater thermal designs, this could lead to buildup of excessively thick coatings that may cause manufacturing concerns and reduce installation vessel capacity. In addition, excessive coating thickness may reduce seabed stability for the flowline and increase drag on a steel catenary riser.⁸

Wax-removing chemicals. The chemicals used to treat paraffin problems generally fall into four groups, two of which are solvents and dispersants.⁹ Solvents are used to dissolve existing deposits. Certain solvents can cause problems with refining the produced crude oils. Diesel and xylene mixtures have been found to be very effective. Many proprietary formulations are also available for dissolving paraffin deposits.

Solvents. Carbon tetrachloride is considered one of the best solvents but is not in wide application in the US because it can have an adverse effect on refinery catalysts. Chlorinated solvents are being phased out due to their effect on the ozone layer. Carbon disulfide has been declared the universal solvent, but, unfortunately, it is very expensive, toxic and flammable and its application in the oil field is restricted. Solvents such as kerosene, condensate and diesel oil are used to dissolve low-asphaltene paraffin deposits.

Pour-point dispersants. The pour point of crude oil is the lowest temperature at which crude movement is observed. To find the pour point, mobile crude is cooled at a specific rate and examined at intervals for movement. The lowest temperature at which movement of the specimen is observed is recorded as the pour point. When the crude reaches this point, the sample is not frozen solid. What actually happens is that paraffins in the crude form a matrix of wax crystals. The wax crystal matrix holds the bulk of the liquid portion of the crude within it. By trapping the liquid portion within the matrix, the crystals prevent the liquid in the crude from flowing, and the sample no longer moves. Anything that disrupts formation or properties of the wax-crystal matrix—such as Pour-Point Depressants (PPDs)—will affect the pour point.

PPDs have been used with great success for several decades. However, they can be plagued by crude oil specificity, large package treating rates, and waxy components that can be hard to apply.¹⁰ Wax-control additives, which include crude oil PPDs, are polymers with pendant hydrocarbon chains that interact with paraffins in the crude and, thus, inhibit the formation of large wax crystal matrices. The interaction retards crystal formation and growth, alters the paraffin’s heat of crystallization and, subsequently, depresses the crude’s pour point while affecting crystal size and shape.

The industry also uses water-soluble dispersants to remove the paraffin deposits. For example, proprietary dispersant, called Parasperse, is used in 2–10% concentrations, depending on the volume of wax deposit to be removed. This dispersant does not actually dissolve paraffin, but rather breaks up and disperses the wax particles to be carried with the producing flow.

Use of microbial products. Naturally occurring marine micro-organisms, which have the ability to absorb paraffins, have been found to effectively remove paraffin deposits or at least reduce deposition. Application of micro-organisms is a popular technique because they are non-pathogenic, non-carcinogenic, non-combustible and environmentally safe. Generally, in the oil field, microbial products are batch treated and injected into the wellbore annulus. New batches are injected periodically to maintain the size of the microbial colony.

Microbes have only recently been recognized for their ability to control paraffin problems, even though literature references to microbial degradation of oil date back to 1972.¹¹ Since it is a relatively new method for paraffin control, many operators are still unsure about its technical and economic benefits. Microbial systems are often expected to perform like a chemical system and are considered early failures when they fail to meet these expectations. Some reports of successful application of microbial paraffin control systems have been published.¹² However, no literature studies have been found to compare their performance in the field to industry-accepted chemical systems.

Ultrasonic methods. Ultrasonic methods work to chemically reduce the length of the paraffinic molecules so they will not precipitate from the oil.^13,14 A secondary effect of residual heat coming from the ultrasonic transducers serves to melt any waxes formed. The chemical effect depends on the appropriate ultrasonic frequencies being applied. These frequencies must be determined a priori. This technology is in its infancy and has not been deployed commercially.

DEPOSITION MITIGATION METHODS

Mitigation of paraffin deposition can be achieved with the following methods:
• Application of chemicals
• Generation of magnetic fields
• Different pipe materials and coatings
• Production techniques to reduce deposition
• Application of ultrasonic waves.

Several other remediation techniques are being investigated by the offshore industry, including the use of exothermically reacting chemicals and the use of extended reach coiled tubing from the platform to scrape the flowline.

Wax deposition reducing chemicals. Crystal modifiers and deposition inhibitor surfactants are used in the industry to mitigate paraffin wax deposition or at least reduce it.

Wax crystal modifiers prevent formation of paraffin wax deposits by interfering with the bonding of aliphatic wax molecules to each other. Composed of branched chain polymers, crystal modifiers bond to the wax crystal lattice at an active growing site, but disrupt the regular structure of the lattice, preventing further growth and interfering with deposition. Although the paraffins remain unstable in solution, they are prevented from growing crystals of adequate size to block production lines; thus, production is not impeded even for temperatures below the WAT.

Crystal modifiers provide the most effective means of preventing deposits, and will, in combination with solvents or hot oil, provide significant deposit removal, but they tend to be costly. A major disadvantage of crystal modifiers is that they are not universally effective in each case of paraffin problems and, thus, a trial-and-error method is required to find the proper product. Thus, selection of the proper chemical and treating method, particularly for continuous injection or squeeze applications with crystal modifiers, should be based on laboratory and field testing.

Paraffin inhibitors are used to inhibit paraffin deposition on tubulars by altering their crystal growth. The use of these inhibitors has been limited to a few applications, including water-wetting the pipe surface to prevent the adhesion of paraffin to it. Additional volumes of surfactant must be fed into the system to maintain the water film, which prevents paraffin contact with the pipe. Also, some inhibitors may actually solubilize the nucleus and, thus, prevent the paraffin agglomeration. Solvent/surfactant treatments are excellent means of wax deposit removal, but the extent of their wax-carrying ability is limited by temperatures below the cloud point of the wax/solvent combination.

Magnetic fluid conditioning technology. Devices using magnetic technology are called magnetic fluid conditioners or stabilizers. However, this technology has created considerable controversy. A variety of claims have been made about the success of this technique in oilfield applications, with the scientific literature contained principally in Russian and Chinese journals. No credible explanation of the mechanism by which magnetic fields influence paraffin deposition is advanced in any of the papers, though some speculative hypotheses have been proposed.

Controlled production of wax deposits. Wax deposition often occurs at a rate that will not affect the useful life of the flow path. The wax deposits form an insulating layer on the inside of the pipe. This acts to increase the inside wall temperature through additional heat transfer resistance, thus reducing the deposition rate. If the deposit does not need to be scraped away, a complete blockage could take tens of years to form in some systems. If this significantly exceeds the design life of the flow path, then there is no reason to prevent deposition.15 This approach is very risky, and the wax layer should be monitored very carefully.

Different pipe materials and coatings. Plastic pipes or plastic-coated pipes have been proposed to reduce wax deposition, though these pipes have some limitations that may severely limit their usefulness . At present, such pipes are mainly used to eliminate corrosion. The rate of paraffin deposition on plastic pipes is slower than on steel, but the accumulation of wax deposits will progress with the same rate as on steel surfaces after the plastic pipe has been covered with a certain layer of paraffin wax.

When deposits do occur and require cleaning, some paraffin cleaning options used in conventional steel pipes may not be available for plastic or plastic-coated steel pipes, such as hot oiling or solvents, which may damage PVC-type pipes. Also, these pipes are obviously not suitable for high-pressure flowlines, where paraffin deposition is common.

LABORATORY MEASUREMENTS

Proper treating recommendations for cost-effective control of paraffins are complicated by the differences in the produced oil characteristics, variations in system operating conditions and the wide variety of treatment chemicals available for use. Therefore, an important element of paraffin management is to collect a representative reservoir fluid sample for laboratory analysis. Laboratory analysis is required to measure the oil’s cloud point temperature and paraffin content. Based on the laboratory measurements, multiphase flow and thermal simulations of the production system, the potential severity of paraffin deposition in the production system can be evaluated.

Laboratory measurements are important in establishing predictive models to determine wax deposition rates. Intelligent data interpretation of these measurements can provide rules of thumb and accurate models for establishing pigging and treating programs. Modeling can also provide key indicators for profiling pipeline temperatures and wax buildup. These tools can greatly assist the operator in making economic decisions and exploring design options. Current modeling technology includes real-time, online pipeline monitoring and advisory systems that help manage a myriad of flow assurance issues. A number of operators worldwide have deployed such systems.¹⁶

CONCLUSIONS

In deepwater conditions, many operational problems and large production losses may occur due to wax deposition in flowlines and pipelines in which low temperatures, both at the seafloor and in the reservoirs, are dominant. Alternatives for the mitigation of wax deposition in subsea pipelines will remain of fundamental importance as the industry moves to ultradeep water.

Equipment complexity and the difficulty of access to subsea installations increase the need for reliable wax-removal methods. Reliable subsea equipment and instrumentation are needed to follow up production and to control wax removal and prevention efficiently. A common practice among production experts is to approach paraffin control in two ways: 1) preventive, avoiding paraffin growth and deposits, and 2) corrective, removing deposits periodically. Techniques based on chemical inhibition of crystal growth, thermochemical cleaning, mechanical cleaning (pigging), ultrasonic cleaning and heating, electrical heating and thermal insulation have been developed. To prevent and manage paraffin deposition, a combination of thermal insulation, chemical and ultrasonic treatment, and mechanical removal techniques may be used. A cost/benefit analysis of these solutions should be conducted before the final selection of a paraffin management strategy is made.  

LITERATURE CITED

 ¹  Brown, T.S., Niesen, V.G. and D.D. Erickson, “Brief measurement and prediction of the kinetics of paraffin deposition,” SPE 30331, Journal of Petroleum Technology, April 1995, pp. 328-329.
 ²  Todi, S. and M. Deo, “Experimental and modeling studies of wax deposition in crude oil carrying pipelines,” OTC 18368 presented at the 2006 offshore Technology Conference, Houston, TX, USA, May 1-4, 2006.
 ³  U.S Department of Energy, “University of Tulsa embark on wax deposition study,” Oil & Gas Journal, 99, No. 56, 2001.
 ⁴  Lino, A.C.F., Mastrangelo, C., Pereira, F.B. and M.G.F.M. Gomez, “Engineers design new pigging devices to handle flowline wax,” Pipeline & Gas Industry, Aug. 1998.
 ⁵  Barker, K.M., “Formation damage related to hot oiling,” SPE 16230, SPE Production Engineering, pp. 371-375, Nov. 1989.
 ⁶  Sarmento, R., Ribbe, L. and L. Azevedo, “Wax blockage removal by inductive heating of subsea pipelines,” Heat Transfer Engineering, 25, No. 7, pp. 2-12, 2004.
 ⁷  McSpadden, H.W., Tyler, M.L. and T.T. Velasco, “In-situ heat and paraffin inhibitor combination prove cost effective in NPR#3, Casper, Wyoming,” SPE 15098 presented at the 56th California Regional Meeting, Oakland, CA, USA (April 2-4, 1986).
 ⁸  Hansen, A.B. and C. Rydin, “Development and qualification of novel thermal insulation systems for deepwater flowlines and risers based on polypropylene,” paper presented at the 2002 Offshore Technology Conference, Houston, TX, USA, May 6–9, 2002.
 ⁹  Fan, Y. and F.M. Liave, “Chemical removal of formation damage from paraffin deposition part I - solubility and dissolution rate,” SPE 31128  presented at the SPE International Symposium on Formation Damage Control, Lafayette, LA, USA, Feb. 14-15, 1996.
 ¹⁰  Manka, J.S. and K.L. Ziegler, “Factors affecting performance of crude oil wax-control additives,” World Oil, 222, No. 6, 2001.
 ¹¹  Kator, H., Miget, R. and C.H. Oppenheimer, “Utilization of paraffin hydrocarbons in crude oil by mixed cultures of marine bacteria,” SPE 4206 presented at the 2nd Biennial Symposium on Environmental Conservation, Lafayette, LA, USA, Nov. 13-14, 1972.
 ¹²  Pelger, J.W., “Wellbore stimulation using microorganisms to control and remediate existing paraffin accumulations,” SPE 23813 presented at the 1992 International Symposium on Formation Damage Control, Lafayette, LA, USA, Feb. 26-27, 1992.
 ¹³  Towler, B.F., “System and method for the mitigation of paraffin wax deposition from crude oil using ultrasonic waves,” US Patent No. 7,264,056 B2, Sept. 4, 2007.
 ¹⁴  Towler B.F., Chejara A.K. and S. Mokhatab, “Experimental investigations on the effects of ultrasonic waves on petroleum wax deposition during crude oil production,” SPE 109505 presented at 2007 SPE Annual Technical Conference and Exhibition, Anaheim, California, USA, Nov. 11–14, 2007.
 ¹⁵  Wilkens, R.J., “Chapter 29: Flow assurance” of “Fluid Flow handbook,” J. Saleh (Ed.), McGraw-Hill, New York, 2002.
 ¹⁶  Golczynski, T.S. and E.C. Kempton, “Understanding Wax Problems Leads to Deepwater Flow Assurance Solutions,” World Oil, 227, No. 3, March 2006, pp.7-10.

THE AUTHOR
	Saeid Mokhatab is an internationally recognized expert in the field of natural gas engineering with a particular emphasis on raw gas transmission and processing. He has been involved as a technical consultant in several international gas-engineering projects and published over 150 academic and industry oriented papers on related topics as well as the Elsevier’s Handbook of Natural Gas Transmission & Processing, which has been well received by the industry and academia. He has been the Founding Editor and an Editor-in-Chief of the Elsevier’s Journal of Natural Gas Science & Engineering, a member of the editorial advisory board for most petroleum industry journals/book publishing companies, and has served on various SPE/ASME technical committees worldwide.
	Dr. Brian Towler has been a Professor in the Department of Chemical and Petroleum Engineering at University of Wyoming for over twenty years and was Department Head from 2004-2008. He currently holds the position of CEAS Fellow for Hydrocarbon Energy Resources. After receiving a PhD (1978) from the University of Queensland and 2 years of post-doctoral research at the University of California at Davis, he was appointed senior reservoir engineer by Arco Oil and Gas Co. His experience includes working as the principal reservoir engineer for Oilmin and the Moonie Oil Group of Cos. Dr. Towler has been a member of SPE for 29 years and is a registered Professional Engineer in Wyoming.