PRODUCED WATER REPORT

Understanding naphthenate salt issues in oil production

These troublesome salts, formed when oil-soluble naphthenic acids come in contact with high-pH produced water, cause tight emulsions, ragged interfaces, organic deposition and, ultimately, separation difficulties.

R. Anthony Rodriguez and Sen J. Ubbels, Champion Technologies

Various naphthenic acids are present in nearly all crude oils in different forms. Problems occur when the naphthenic acids come in contact with high-pH connate waters. The problems start at the oil-water interface and can cause organic deposition, impede oil-water separation and ultimately lead to poor water quality.

This article reviews the characterization of, problems caused by and remediation of naphthenate salt issues in the upstream environment, drawing information from direct experience and literature.

INTRODUCTION

Crude oil is a complex mixture of 10,000-100,000 distinct compounds.1 Typically, the components are organized into the well-known fractions of Saturates, Aromatics, Resins and Asphaltenes (SARA). Included in these fractions are oil-soluble naphthenic acids. At reservoir conditions, the acids are contained in the oil phase and demonstrate low interfacial activity.2 As the pressure cascades up through the flowline and ultimately into the topside separation equipment, depressurization occurs.

Each fraction is soluble in its respective media, and all are held together in the complex system that is crude oil. The mixture is stable at reservoir conditions, but perturbation can change the fluid’s dynamics enough to cause complex operational issues. For example, asphaltenes are stable at reservoir conditions as a colloidal suspension dispersed with resins and solubilized with aromatics.3 As fluid moves out of the reservoir and into the tubing, its pressure drops, and the lighter components’ relative volume increases, decreasing the colloid solubility. This causes the asphaltenes to become unstable and sometimes sticky, resulting in deposition.

Similarly, the naphthenic acids in crude oil, regardless of their structure, reside harmlessly in the oil phase under reservoir conditions. The depressurization that occurs as oil moves out of the reservoir and up the production tubing can cause the pH of system water to increase, resulting in a salt with ions from the water and naphthenic acids from the oil. An anionic hydroxyl is necessary to create the salt, as is illustrated in the equation:⁴


The migration of the anionic naphthenic acid to the interface allows the reaction with metal ions, yielding the troublesome naphthenate salts.

Specific issues that directly result from naphthenate salts include very tight emulsions, ragged interfaces, high calcium levels in export crude oil and organic deposition. Difficulties in treating produced water and other indirect problems may also result.

ORGANIC DEPOSITION

An offshore facility at field A produced a crude oil-water combination that, when depressurized in the first stage separator, created organic deposits at the oil-water interface.⁵ The deposits plugged the baffles in the separator, as well as in water treatment equipment. The plugging of the separator caused level control problems, which resulted in water being carried over into dehydration stages. Oil was also carried over into the water and overwhelmed the water treatment equipment, resulting in poor water quality.

To control the deposits, the pH was adjusted down to the acid range using acetic acid upstream of the first stage separator. The acetic acid was not completely successful in achieving remediation of the deposit, because strong corrosion and logistics prevented injection of sufficient acid.

Specifically, the use of acids for naphthenate control presents logistical issues with regard to safety and storage. Handling corrosive materials in large quantities presents safety issues for the operations personnel. Chemical storage offshore is always at a premium, as the space available is not flexible. The use of naphthenate inhibitors in this case reduced the amount of acid used, thus simplifying logistical issues. Not until a naphthenate inhibitor was included in the remediation effort was the organic deposition completely controlled.

CHARACTERIZATION

A great deal of research has been pursued to characterize the naphthenic acids responsible for organic deposition, Fig. 1.⁶ Thousands of naphthenic acids have been identified, and with each change in structure comes a change in the acid’s interfacial activity. The structure may vary by the number of rings, saturation or, in some cases, the number of carboxylic groups.

Fig. 1. The characterized standard naphthenic acid shown here is of a polycyclic species, which is not considered likely to be responsible for organic depositions.

Naphthenic acid species have been characterized using Gas Chromatography and Mass Spectrometry (GC-MS), two-dimensional GC-MS, Fourier-Transform Ion Cyclotron Resonance (FT-ICR) mass spectrometry and Nuclear Magnetic Resonance (NMR) spectroscopy. Recently, the naphthenic acid responsible for solids deposition was identified as an archaeal C80 isoprenoid, also known as ARN.⁷ This acid was identified as a tetra-acid, with four carboxylic groups, Fig. 2.

Fig. 2. The naphthenic acid responsible for solids deposition was recently identified as an archaeal C80 isoprenoid, also known as ARN.8 This acid was identified as a tetra-acid, with four carboxylic groups.

These groups afford the molecule unusually high reactivity. The four carboxylic groups tend to create polymeric salt when they are coordinated with divalent metal ions. This weaved polymeric-like structure yields a very sticky deposit that hardens upon contact with air. Once a deposit sets, it can only be dissociated by using a mixture of hot acid and aromatic solvent in laboratory conditions. A remediation using mineral acids in the field would typically be too severe from a safety and corrosion perspective.

INTERFACIAL RAG LAYER

Field B is another offshore facility that did not experience organic deposition, but experienced an unresolved webby interface that impeded water treatment. The overboard water produced had very high oil and grease counts, although the sales oil tank had very dry, clean oil. A total system survey found the interface at four sample-point levels in the Free-Water KnockOut (FWKO). The dirty interface carried over to the water treatment hydrocyclone and float cell. The water treatment equipment was overwhelmed, resulting in dirty overboard water.

Grind-out tests of the individual wells showed that a few wells produced a pad layer, which the operator was unable to break using a standard slugging compound. The addition of a naphthenate inhibitor into the subsequent grind-outs cleared up the interface. Ultimately, a demulsifier not containing a naphthenate inhibitor was applied at the FWKO. It was able to remove the dirty interface from the produced water. After the new demulsifier was plant tested, the FWKO was sampled, and unresolved interface was only found at one level on the FWKO. The carryover to the water treatment equipment had been reduced, and the overboard oil and grease counts met or exceeded specifications. In this case, the use of the demulsifier package was enough to overcome the emulsifying characteristics of the naphthenate salts.

TIGHT EMULSIONS, REMEDIATION AND PREDICTION

Naphthenic acids are interfacially active, which affords them unique stabilization properties, even in a slightly acidic environment of pH ~ 6.5. As the pH goes up, though, the interfacial activity goes up, and salt formation becomes more likely, Fig. 3.⁹ When an added acid brings the pH down, the emulsion problems may decrease in severity.

Fig. 3. In this model system of water and acidic oil, the interfacial tension changed as the pH increased. The change in interfacial tension was correlated to the formation of RCOO- ions. As the pH increased, more RCOO- ions were formed, and the interfacial tension decreased until the interface was saturated. This data follows field observations about the resolution of the emulsion, and the pH in the system.

The structure of the acid strongly affects the interfacial tension and the rate at which the interfacial tension changes with a change in pH. In the model system shown in Fig. 3, it is not clear how even in regions of moderately low pH, the naphthenic acids are still active. In the field, even at pH = 6, problems at the interface still occur.

Field C produced a very stable emulsion that had the consistency of muddy water from some locations, and viscous, stable emulsions from other locations. The operator was unable to break the stable emulsion with a typical non-ionic demulsifier; only a highly acidic demulsifier or acid-demulsifier combination products were effective in treating it. The acid portions included the use of DoDecylBenzene Sulfonic Acid (DDBSA), acetic acid and mineral acids. The addition of a naphthenate inhibitor to a demulsifier allowed the operator to minimize the use of acids and increased the effectiveness of the oil-water separation.

The naphthenate salts in field C, and in most systems during the past 20 yr, have been treated using acids of some kind. The inhibiting mechanism of a pure acid is likely to increase the interfacial tension, thus better defining the interface. As pH decreases with the addition of acid, the dissociation of the naphthenic acid to the anionic functional group is decreased. As the occurrence of the anionic species decreases, the surface tension goes up and the surfactancy of the naphthenic acid goes down. This will limit the tightness of the emulsion or the interface, but these issues can continue to exist into the acidic range.

Another method of controlling naphthenate salts is the use of specialty surfactants known as naphthenate inhibitors. These surfactants use the mechanism of interfacial crowding to inhibit salt formation, Fig. 4. The surfactant is more interfacially active than naphthenic acid, which reduces the probability of a reaction between the salt and the acid.10 If the naphthenic acid is not allowed to reach the interface, it cannot cause solid deposition or emulsion. In our experience, surfactant treatments, in the form of demulsifiers, naphthenate inhibitors, or acid combinations, are much more effective at much lower dosages than acid alone.

Fig. 4. Specialty surfactants known as naphthenate inhibitors use the mechanism of interfacial crowding to inhibit salt formation.

Due to the varying structures of naphthenic acids, the treatments and injection points may vary greatly. For example, the injection point in a fluid with tetrameric naphthenic, or ARN, acid is much more critical than in a fluid with monoacid-type naphthenic acid. In the case of the ARN acid, the treatment must be upstream of the point where polymeric salt is formed because dissociation after the formation is very difficult. The converse is true with a monoacid: After salt formation, dissociation may still be simple, providing some flexibility to the treatment plan. There are case histories that require downhole treatments because of the difficulty of dissociation.

Until recently, naphthenate salt problems have been dealt with reactively, and not planned for in the design phase. Although it is possible to predict high pH, there are no time-tested early indicators of the presence of the naphthenic acids that would cause a problem. The problem can be identified in field as the presence of a strong rag layer or by the solubility of an organic deposit. Analytical techniques have evolved to a point where certain naphthenic acids can be identified in problem fields. For example, the ARN acid has been identified at 1,200 amu via mass spectroscopy. The structure has been plotted with the aid of NMR. As more is learned about naphthenate salt problems, it will become possible to better predict and thus plan for such issues.

Champion Technologies has initiated research to understand emulsion tendency trends associated with troublesome oils. Using the pendant-drop “tracker” technique, one can plot interfacial tension vs. pH, Fig. 5. The technique uses the Laplace equation for bubble geometry change. The collection of this data is empirical at present, but it may shed light on trends for surfactant use. These trends may also predict ragged interfaces or even deposits.

Fig. 5. The pendant-drop “tracker” technique is used to plot interfacial tension vs. pH, Courtesy of the Norwegian University of Science and Technology.

CONCLUSION

Naphthenic acids of varying structures exist in nearly all crude oils, but remain inert in upstream conditions without a perturbation in the system. Certain perturbations in the system may lead to interfacially active naphthenate salts.

The structure of a given naphthenic acid dictates its interfacial activity. More interfacially active naphthenic acids in slightly acidic to basic pH waters may form salts that, in turn, form tight emulsions or rag layers. Some naphthenic acids may coordinate with divalent metal ions to form polymeric salts, which lead to organic deposition. The naphthenate salts may cause direct problems such as emulsions. Indirect problems resulting from the formation of emulsions or organic deposition include oil carryover into water treatment systems and water carryover into oil systems.

Methods for remediation of naphthenate salt issues include the use of acids and/or specialty surfactants (i.e., naphthenate inhibitors). The best treatment at present is only reactive, as solid modeling methods in the early planning stages do not exist. Developing solutions on site with fresh fluids is critical to the success of a treatment program. The use of a standardized naphthenate inhibitor and demulsifier kit simplifies the process. Predictive tools will likely progress as the physiochemical properties of different naphthenate species become better understood.

LITERATURE CITED

¹ Klein, G. C. et al., “Use of saturates/aromatics/resins/asphaltenes (SARA) fractionation to determine matrix effects in crude oil analysis by electrospray ionization fourier transform ion cyclotron resonance mass spectrometry,” Energy & Fuels, 20, March 2006, pp. 668-672.
² Ubbels, S. J. and M. Turner, “Diagnosing and preventing naphthenate stabilized emulsions during crude oil processing,” presented at the 6th Petroleum Phase Behaviour and Fouling Conference, Amsterdam, June 19-23, 2005.
³ Klein et al.
⁴ Arla, D. et al., “Influence of pH and water content on the type and stability of acidic crude oil emulsions,” Energy & Fuels, 21, May 2007, pp. 1337-1342.
⁵ Hurtevent, C. and S. Ubbels, “Preventing naphthenate stabilised emulsions and naphthenate deposits on field producing acidic crude oils,” presented at the 2006 SPE International Oilfield Scale Symposium, Aberdeen, Scotland, May 30-June 1, 2006.
⁶ Qian, K. et al., “Fundamentals and applications of electrospray ionization mass spectrometry for petroleum characterization,” Energy & Fuels, 18, November 2004, pp. 1784-1791.
⁷ Lutnaes, B. F. et al., “Archaeal C80 isprenoid tetraacids responsible for naphthenate deposition in crude oil processing,” Organic & Biomolecular Chemistry, 4, Feb. 21, 2006, pp. 616-620.
⁸ Brandel, O. et al., “Interfacial behavior of C80 tetrameric naphthenic acids responsible for naphthenate deposition in crude oil processing,” presented at the 7th Petroleum Phase Behaviour and Fouling Conference, Ashville, North Carolina, USA, June 2006.
⁹ Arla et al.
¹⁰ Hurtevent and Ubbels.

THE AUTHORS
	Anthony Rodriguez is a flow assurance/flow management specialist working out of Champion Technologies’ main Tech Center in Fresno, Texas. His primary functions are project and customer support of the wax, asphaltene, defoamer, drag reducer, and calcium naphthenate product lines for the Western Hemisphere.
	Sen Ubbels is the Phase Separation section manager for Champion Technologies in the Eastern Hemisphere, working out of the Tech Center in Delden, the Netherlands. His primary functions are as manager of the demulsifier, water clarifier, defoamer and calcium naphthenate product lines and personnel. Mr. Ubbels pioneered the calcium napthenate inhibitor product line for Champion.