Non-toxic paraffin remover returns flow to long-plugged GOM pipeline

Fig. 1. Chart depicting the departing pipeline pressure, 14 days prior to losing communication, as well as the point at which blockage occurred.

A granular derivative of chemistries conceived for use in the food services and brewing industries, re-formulated as a paraffin removal agent, has effectively restored oil flow in a severely plugged Gulf of Mexico pipeline that had been slated for de-commissioning.

In less than two days of intermittent pumping and soaking, the aqueous-activated solution, acknowledged as the industry’s only non-toxic paraffin remover, had established full communication on a 1.43-mi., inter-platform flowline that had been out of commission for 10 months. Nearly the full length of the 8-in. flowline, in just under 127 ft of water in the Vermilion area offshore Louisiana, was determined to be plugged by paraffin wax, Fig. 1. Previously, a number of high-pressure pumping attempts, using conventional solvents, had proved unsuccessful, leaving the operator little choice but to plan on converting a 6-in. water line to transfer oil between the two platforms.

Unlike traditional solvents, the multi-patented technology, comprising a proprietary blend of surfactants, is not only non-hazardous and temperature-independent, but its density and composition effectively lower surface tension, allowing the solution to penetrate between the blockage and pipe wall, as well as throughout the micro-cracks within the wax deposit itself. A specially formulated and controlled, oxygenated alkaline composition acts on the adhesion intrinsic to paraffin, effectively dislodging the wax into chunks that can flow easily out of the pipeline, and be collected for disposal. Furthermore, the solution is activated by either freshwater or seawater, making it equally effective in both onshore and offshore applications.

PREVAILING PARAFFIN ISSUES

The deposition of paraffin wax and its closely related cousin, asphaltenes, in flowlines and associated production components has long been regarded globally as one of the industry’s most expensive and difficult-to-mitigate flow assurance issues. In the U.S., alone, it is estimated that paraffin deposition costs operators upward of $2 billion/yr in restricted or delayed production, often-fruitless remediation attempts, and pressure-induced equipment damage. While paraffin wax can manifest itself in any onshore or shallow-water pipeline, the costs and removal difficulties are magnified appreciably in the colder subsea temperatures of remote deepwater tie-backs and other flowlines.

Over the years, the numerous economic and HSE issues associated with paraffin build-up are equaled only by scores of chemical and mechanical remediation efforts that have been advanced with widely mixed results.^1,2,3,4,5 For instance, typical chemical treatments, including line heating, warm solvents, hot oil treatments and conventional wax inhibitors, are largely ineffective in longer pipelines, and when temperatures fall to 40°F and below. Pipeline lengths and any bends present, likewise, restrict coiled tubing intervention, which is otherwise relatively effective, but comes with a high cost and risks.

Generally described as a white or colorless soft solid, paraffin is derived from hydrocarbons, coal or shale, and comprises a mixture of hydrocarbon molecules containing anywhere from 20 to 40 carbon atoms (C_x). Paraffin build-up can either occur naturally with the flow of crude through the pipeline, or through mechanical practices, such as vacuum pumping or the injection of stimulating chemicals and some solvents.

Even at moderate temperatures, paraffin displays limited solubility when in contact with most types of inorganic solvents, and is virtually insoluble in aqueous solutions. Once the temperature of the streaming oil falls below the cloud point,⁶ which in crude oil is also defined as the wax appearance temperature (WAT), the end paraffin components begin to crystallize into solid wax particles. Thus, deposition typically occurs when the wax entrained with oil contacts any surface that has a temperature below the cloud point and has a heat sink.

Fig. 2a. Dislodged paraffin being pumped from the 1.3-mi pipeline during the removal process.

Crystallization also is accompanied by a phenomenon that in colloid science is described as the zeta potential,⁷ which propagates the stickiness that makes paraffin wax so enormously difficult to remove, once deposited. The sticky particles will attach to each other as though coated with glue, as well as along the pipeline wall. Obviously, the longer the particles are allowed to coagulate, the larger and more established the blockage, until eventually the entire cross-sectional flow area of the line is plugged, and production halts. Moreover, even before the line is completely blocked, the buildup of paraffin and asphaltene wax along the pipe wall propagates roughness that increases the pumping pressures required to move production and places tremendous strain on pumping equipment.

The HSE risks, as well as the temperature restrictions and other limitations of conventional chemical and mechanical remediation methodologies, prompted development of the non-toxic additive for the removal of paraffin wax.

Fig. 2b. A portion of the removed wax collected during the removal process.

ECLECTIC DEVELOPMENT HISTORY

The origin of what evolved into the uniquely engineered, paraffin removal solution followed a rather circuitous route, that included formulations specially modified for the food service and beer brewing sectors. Two of the seven patents covering what is now an effective oilfield paraffin remediation agent reflect its earliest roots,^8,9 during which a prototype formulation was shown to completely break down fossilized
vegetable matter.

The earliest precursor of the current formulation was developed in 1995, in the form of a high-foaming detergent, based on sodium metasilicate and sodium phosphates, which proved highly effective in removing extremely dense black protein stains left on stainless steel from the production of refried beans. That work also led to a promising new compound, sodium percarbonate—a combination of hydrogen peroxide hydrated on soda ash—which, unfortunately, exhibited extreme volatility in the presence of organic material having 14% available peroxide.

At the behest of a major brewery, the basic research was expanded a year later with the conception of an alkaline cleaner to replace the standard sodium hydroxide-based product used to remove bacterial contamination from cold filtering units. The standard cleaning compound was actually dissolving the brass filter plates at a rate of 1,000 ppm of free copper per wash, while also destroying the digestive bacteria in the brewer’s waste treatment systems.

A series of tests resulted in a novel, and highly effective, hydration technique that isolated the surfactants from the volatile sodium percarbonate in a dry formulation, while eliminating the copper discharge. The then-newly patented formulation laid the groundwork for its eventual use in the oil field, with its capacity to remove all beer deposits and microorganisms, and do so at colder temperatures, lower concentrations and faster than the previous cleaner.

That earlier work served as the springboard for its current use, when it was discovered that a precise combination of surfactants in a alkaline system, in tandem with neutralizing oxygen, could remediate paraffin/asphaltene deposits.

CORE FORMULATION PRINCIPALS

Fig. 3. The platform layout for the paraffin remover injection.

Compared to most conventional solvents, one of the key differentiators of the new additive is lowering of the surface tension, commonly linked to interfacial tension, which is vital to the agent’s emulsification properties. Primarily, interfacial tension penetrates the adhesive forces between the liquid phase of one surface and either a solid, liquid or gas phase of another substance. In a series of internal tests, the interface is a cleaning solution that “wets” a surface on an incline, whereupon the degree of wetting is measured.

Consider that, as measured by the Kruss Bubble Pressure Test, tap water at room temperature exhibits a surface tension force of around 76 dynes/cm, far more than the 42.3 dynes/cm of diesel. At 5% solution, the new paraffin remover measures 22.2 dynes/cm. Quite simply, in an oil-water combination, by adding a blend of surfactants to the aqueous phase, the oil molecules tend to orient themselves into alignment with the water molecules, resulting in miscibility, or the formation of a homogenous fluid.

Furthermore, the formulation of specially blended surfactants optimizes the hydrophilic-lipophilic balance (HLB), defined as a measure of the degree to which a surface active agent is hydrophilic or lipophilic, meaning it is either attracted to water or to oil. Using this type of combined surfactant is advantageous in drawing organics into the water phase.

What results is a solution with a density higher than that of any production fluids or solvents in the pipeline. Thus, once introduced, the heavier solution displaces the lighter fluids, as it migrates down the line and within the wax deposit, with no length, geometric or temperature limitations.

Moreover, the smaller carbon chains, specifically C₁₃–C₁₈, intrinsic to paraffin deposition, comprise open-chain saturated hydrocarbons that are virtually non-reactive and critical to soap and surfactant chemistry. Therefore, coalescing high alkalinity with the correct surfactant package clears the way for emulsifying and sulfonating the shorter-chain alkanes, and in so doing, generate simple soap lubricants. The simple soap generated by sulfonating a small portion of the material present in the oil then becomes water-soluble and begins to break apart the paraffin plug.

To further clarify, the production of a simple soap requires only a base and an organic fatty acid, which, in the case of crude oil, includes naphthenic acid (R(CH₂)_nCOOH). When this and other organics come into contact with the reactive sodium carbonate (Na₂CO₃) of the new paraffin remediation additive, it generates this standard chemical acid base
reaction with:

R(CH₂)_nCOOH+Na₂CO₃→R(CH₂)_nCOONa+NaHCO₃

(Naphthenic acid)(Sodium carbonate)(Sodium naphthanate)(Sodium bicarbonate)

In addition, earlier studies at M.I.T. suggested elemental oxygen under pressure could modify n-paraffins. Taking that investigation further, elemental oxygen, which alone is highly effective at neutralizing the zeta charge of paraffin, was combined in a single chemical package with the synergistic effects of surfactants and other elements. This resulted in a slightly oxygenated system, whereas oxygen was released over an 8-to-24-hr period to negate the zeta potential, and the stickiness of paraffin and asphatelene waxes.

The newly formulated solution was field-tested on an onshore pipeline—30% of which was plugged by paraffin—where it proceeded to remove 100% of the blockage in 24 hr. Afterward, the technology was selected to hopefully re-establish communication on the 7,550-ft Gulf of Mexico inter-platform pipeline.

Over 10 months, four high-pressure injections of a phenylarsine oxide (PAO) solvent had failed to dislodge the extreme wax build-up. One of the unsuccessful attempts involved pumping the PAO solvent at pressures exceeding 1,200 psi, whereas prior to losing communication, the normal operating pressure in the flowline was 75–85 psi. Meanwhile, operational logs showed the pipeline, which was installed with a riser configuration comprising four 5R bends, had not been pigged for 17 years.

DATA-DRIVEN REMEDIATION STRATEGY

Fig. 4. The layout onboard the M/V Abigail Claire support vessel.

Much of the pre-job data analysis dealt with ascertaining the composition and location of the blockages. An acoustical survey had isolated the blockage at 469 ft from its point-of-origin on one platform, with possible blockage also 467 ft from the initiation point on the other platform. Initially, it was believed that the shutdown resulted from bacteria-induced internal corrosion and from metal filings from scale buildup at the riser elbow, on the side of one of the platforms. An earlier analysis of a deposit sample suggested a mixture of only 17% paraffin, with iron oxides making up 83% of the deposition.

However, an evaluation of historical treater pressure data strongly indicated that the 8-in. line, more than likely, contained significant paraffin deposition along its entire length. Reinforcing that supposition is the fact that paraffin and similar wax deposits tend to accumulate over time, thus the increasing treatment pressure volumes documented in the historical treater pressure documentation and the field’s oil line history reports. The comparative analysis showed disparity in the reported operating pressure, the accuracy of which would further confirm pressure increases attributed to a severe flow restriction.

Furthermore, as supporting data were inconclusive as to the presence of microbiological matter, it was presumed that any internal corrosion likely was caused by produced water, rather than bacteria. While a sample analysis by a third-party lab revealed significant amounts of iron oxides, given the long-static condition of the flowline, it was likely that rust along the pipe wall comingled with the deposition, making it non-representative of the actual plug.

After evaluating the accumulated data, it was surmised that the deposition contained considerably higher concentrations of paraffin and formation materials than suggested by the deposit analysis. Thus, a remediation strategy was developed accordingly.

The treatment plan called for injecting the solution at each end of the pipeline, where its specially formulated density and composition would allow the solution to migrate to the blockages. Once the dislodged production fluid had been collected in designated tanks, the solution would be allowed to settle in the line until a pressure drop was observed, suggesting the plugged material had either been penetrated, or released. Once the pressure dropped, and after a sufficient volume of the paraffin removal solution had been injected, pressure would be applied from the farthest platform to determine whether the plugging material had, indeed, been released. At that point, additional solution would be injected until full communication had been restored between the two platforms.

PROJECT RECAP

Fig. 5. Pumping pressure chart, showing the decrease in pressure once full communication was established.

Communication was first established in 8 hr, and after only 44.5 bbl of solution had been pumped; full communication was restored after 45 hr of pumping and an aggregate 133 bbl of solution. Judging from the removal of a cumulative 284 bbl of solids and sludge, and considering the total capacity of the 8-in. line is 397 bbl, it was determined that 72% of the pipeline had been plugged, Fig. 2.

Notably, the equipment rig-up prior to the initial injection was relatively straightforward, with each platform requiring only a 50-bbl marine portable tank (MPT) and a 25-bbl cuttings box to collect flowback and dislodged paraffin solids, respectively. The only other required additions to both platforms were a 2-in. flange and ball valve installed on the bottom of the pig trap, and a 2-in hose connecting the pig trap to the MPT, Fig. 3. As a contingency, a 2-in. hot tap was installed on both risers, though the solution can be injected into the pipeline from any point on the platform offering sufficient entry.

The 220-ft M/V Abigail Claire support vessel, which served as the operational base, likewise required only three 500-bbl tanks to collect both the solid and flushed liquids, a 350-gal mixing tote, two 550-gal product storage totes and a 50-bbl seawater clean-out tank. The solution would be injected from the vessel via a PE5 pump, fitted with a 3-in. air diaphragm pumps for mixing and priming the main pump, Fig. 4.

 As programmed, the treatment schedule provided for varying the injections between the two platforms, with intermittent static periods where the working solution would be allowed to soak and act upon the deposit. During the operation, pumping pressures ranged from 500 psi to a high of 1,350 psi, with equally fluctuating line pressures, Fig. 5.

Within two hours of soaking, the line pressure had equalized significantly between the two platforms, suggesting that the wax was being dislodged. Afterward, with just over one hour of continuous pumping at a final rate of 2 bbl/min., the blockages were totally removed, and full communication was established. After two pigging runs, the line was flushed clean with seawater.  

References

1. Goodman, N. T., and N. Joshi, “A tale of two flowlines—Paraffin plugging and remediation,” SPE paper 166196, presented at the SPE Annual Technical Conference and Exhibition, New Orleans, La., Sept. 30-Oct.2, 2013.
2. Mokhatab, S., and B. Towler, “Wax prevention and remediation in subsea pipelines and flowlines,” World Oil, Novemer 2009.
3. Mansoori, G. A., “Modeling of asphaltene and other heavy organic depositions,” Journal of Petroleum Science and Engineering, April 8, 1996.
4. Bailey, J. C., and S. J. Allenson, “Paraffin cleanout in a single subsea flowline using xylene,” SPE paper 125131, SPE Projects, Facilities & Construction, Vol. 4, March 2009
5. Biswas, S. K., S. Bateja, M. Sarbhai, V. Kukreti, D. Rana and T. Misra, “Application of microbial treatment for mitigating the paraffin deposition in down hole tubulars and surface flowlines of wells—A success story,” SPE paper 154662, presented at SPE Oil and Gas India Conference and Exhibition, Mumbai, India, March 28-30, 2012.
6. Sadeghazad, A., G. A. Sobhi, R. Christiansen and M. Edalat, “The prediction of cloud point temperature: In wax deposition,” SPE paper 64519, presented at SPE Asia Pacific Oil and Gas Conference and Exhibition, Brisbane, Australia, Oct. 16-18, 2000.
7. Jacobasch, H. J., F. Simon and P. Weidenhammer, “Adsorption of ions onto polymer surfaces and its influence on zeta potential and adhesion phenomena,” Colloid and Polymer Science, Vol. 276, pp 434-442, June 1998
8. Talley, C. B., “For cleaning food apparatus,” U.S. Patent No. 5663132 A., issued Sept. 2, 1997.
9. Talley, C. B., “Non-caustic cleaning composition comprising peroxygen compound and specific silicate, and method of making same in free-flowing, particulate form,” US Patent No. 5789361, issued Aug. 4, 1998.