Prevention and Removal of Naphthenate Deposits in Oil and Gas Production—Historical Background and Novel Attitude towards Inhibition and Solution

Abstract

The authors studied the problem of naphthenate deposits in the oil and gas industry. Currently, there are few ways available to inhibit or dissolve naphthenate deposits in oil facilities. Naphthenate deposits can block pipelines and aggregate in other parts of the installation, i.e., in the separators. In Europe, the issue of deposition on oil rigs is commonly encountered in Norway and the United Kingdom, as well as in some African countries, i.e., Angola and Nigeria. Many tons of chemicals are used to combat naphthenate deposition, usually through inhibition, but also via the dissolution of the scale that precipitates over time. The presented work examines the characteristics of naphthenate fouling, historical ways to inhibit it, and current approaches to the problem, as well as the results of the laboratory testing of naphthenate inhibitors and solvents. The process of the naphthenate creation is as follows. When oil exhibits a high TAN (total acid number) and high content of salty water, naphthenate deposits can emerge via the reaction of naphthenic acids and metal salts (mostly calcium ones). Naphthenates are partially insoluble in water, and they usually float below the oil/water interface. The standard methods of naphthenate inhibition involve lowering the pH of the production water, which can result in serious problems, especially related to corrosion. This study addresses experiments conducted in the laboratory in Poland and on oil rigs in Angola and is based on contemporary knowledge and standards. The objective of this paper was to investigate the most suitable naphthenate inhibitors and solvents, as well as to undertake bottle tests of naphthenate inhibitors with a focus on the main indicators (water clarity, quality of separation surface, and clarity of oil). The use of citric and formic acids in this paper is a novelty, and it is compared with the results obtained with the more commonly used acetic acid, hydrochloric acid, and ABS acid. It was proven that formic acid can effectively inhibit and dissolve naphthenic deposits (99% efficiency of inhibition and 100% efficiency of dissolution). It was found that some acids used in naphthenate inhibition create more deposits than were originally present. Formic acid and ABS acid yielded significantly better results than other types. It is also here hypothesized that there are substances other than acids that can effectively remove naphthenate deposits, and the other novelty of this study is in the use of mutual solvents in the removal of naphthenate salts. Another important outcome is the finding that not only acids but also mutual solvents (EGMBE and isopropyl alcohol) can effectively remove naphthenate deposits. The test results show that formic acid dissolved all of the naphthenates, while citric acid had 97% efficacy, isopropyl alcohol had 95% efficacy, and EGMBE showed 94% efficacy. The impacts of commercial naphthenate inhibitors on the bottle test results and interfacial tension measurements were also investigated. It was shown that commercial naphthenate inhibitors can decrease the interfacial tension between oil and water by more than 30% when used at dosages of 400 ppm.

1. Introduction

During oil exploitation, oil is produced in the form of an emulsion with water; this can show very high viscosity, resulting in several problems regarding flow assurance and structural properties [1]. Petroleum-derived organic acids are known as naphthenic acids (NAs); these naturally occur in oil via the bacterial biodegradation of petroleum and can be present at different concentrations, mostly between 2% and 4% [2]. Lawal et al. [3] indicated that the high total acid number of crude oil and high concentrations of metal ions (Ca²⁺ and Na⁺) were the main factors contributing to creating these types of deposits. Furthermore, the calcium salts they contain cause serious problems in oil and gas exploitation, including pipeline blockages that are hard to remove. When the topside pressure drops, CO₂ is released and the pH increases, converting more naphthenic acids to naphthenate ions, which can then bind to calcium ions. This results in precipitate formation at the water–oil interface [4] in the form of a sticky, sludgy, solid deposit that aggregates on oil-production equipment. The naphthenate salts that build up on the equipment create a hard, rock-like deposit, which is difficult to remove [5]. The higher the alkalinity of the water, the more likely it is that the dissociated acid will form a soap. Sulaimon [6] showed that a pressure drop will cause carbon dioxide to be lost from the solution during oil production. This results in an increase in the pH value of brine and leads to the dissociation of NAs. The soap created upon the dissociation of the naphthenic anion (RCOO⁻) reacts with the metal (usually calcium or sodium). Sodium soaps are soft, emulsion-type substances, while calcium salts precipitate on the oil/water interface.

RCOOH → RCOO⁻ + H⁺

(1)

The dissociation of carboxylic acids explains why the interface between the water and oil layer is pH-dependent, resulting in increased emulsion stability at a higher pH [7].

Commonly, this problem is resolved by reducing the water’s pH using acids, thus preventing the dissociation of naphthenic acids and the creation of naphthenic salts. The acids most often used include inorganic mineral acids, small organic acids (acetic acid, glycolic acid), and surfactant acids (i.e., aromatic acids). The addition of acids results in an equilibrium shift from naphthenate ions to NAs, which are less surface-active and water-soluble and do not create metal salts. In this paper, the pH of the water was decreased by the addition of hydrochloric, citric, acetic, and formic acids. Furthermore, LDNIs (low-dosage naphthenate inhibitors) were examined; these could act in conjunction with NAs to maintain the pH of water and combat naphthenate precipitation [8]. In Norway, these products have been successfully used in the Heidrun oilfield, where they are mixed with a demulsifier, as they were shown to be ineffective when used alone [9]. A similar situation arose in Blake Field [10]; nevertheless, the authors have herein attempted to use acids as well. Due to problems with HSE and logistics, glycolic acid was not considered, and we focused on the removal of naphthenate deposits and demulsification.

The problem with naphthenate deposits persists in all parts of the world. At Gimboa oilfield in Angola, such deposits create serious issues in relation to blocked pipelines, and this necessitates the installation of a proper, low-dosage naphthenate inhibitor (LDNI) [11].

Debord and Srivastava [5] proposed the utilization of LDNI instead of other previously discussed acids (500–750 ppm of acetic acid). Moreover, parameters related to water clarity, crude oil BS&W < 0.5%, and deposit elimination in water with a pH higher than 6.2, as well as significantly reduced acetic acid (25%) have yet to be reported.

In general, the inhibitor is typically a surfactant (anionic, amphoteric, or a combination). These inhibitors contain a hydrotrope concentrated along the oil/water interface, which acts with carboxylate salt, increasing solubilization in water; this inhibits the formation of organized phases, such as that of calcium naphthenates [12].

Simon [13] described the formation of high-molecular-weight ARN acid and calcium ions; here, three parameters were taken as important to estimate the effectiveness of naphthenate inhibitors: interfacial tension, interfacial rheology measurements, and bottle tests. In the case of the bottle test, a mixture of an aqueous phase and a xylene phase (xylene + ARN acid + crude oil, in a ratio of 1:1) was shaken overnight. The shaken samples were centrifuged for 5 min at 7500 rpm, while the deposit was measured under a microscope, and the water’s pH was determined. Herein, other parameters were measured, including the sharpness of the water–oil layer, water clarity, and water content in the oil (the BS&W should be lower than 0.5%). The naphthenate inhibitor acted in conjunction with the demulsifier or as an inhibitor and demulsifier. Other tests were conducted to examine the efficacy of different acids against naphthenate deposition and naphthenate deposit dissolution and the impacts of the final formulas of naphthenate inhibitors on the interfacial tension between the water phase that contained the calcium ions and the standard. Synthetic oil (made of aliphatic and aromatic solvents) was used for these tests.

Nordgard [14] has claimed that one of the most popular methods for inhibiting naphthenate deposition is through pH reduction. Thus, herein, five types of acids were investigated for their ability to decrease the pH of water containing 14 mg/L of CaCO₃ (pH of 9.71).

Furthermore, we also sought a good solvent for naphthenate deposits. Afdhol et al. described the different applications of solvents in the oil and gas industry [15]. For example, in standard wax deposition removal, solvents are used to avoid wax blockages, but this approach is not economical compared to other methods (e.g., the use of pour point depressant). Eke et al. claimed that the incorrect selection of solvents in the oil and gas industry causes serious problems related to the incompatibility of liquids. The appropriate selection of a naphthenate solvent is vital for preventing blockages in pipelines, and these blockages result in the inhibition of the inhibitor. In industrial practice, all oil-soluble chemicals added to the oil stream are treated as oil components. Water-soluble acids can improve the corrosion rate, which is the main side effect of naphthenate inhibition.

The novelty presented in this paper refers to the use of formic and citric acid as naphthenate inhibitors. The results were compared to those of other, standard inhibitors: hydrochloric, acetic, and ABS acids. Another important outcome was the use of mutual solvents as naphthenate solvents, which can significantly mitigate, i.e., corrosion problems. The other aspects are the bottle test of commercial naphthenate inhibitors and their impact on interfacial tension.

2. Materials and Methods

Before the test, FTIR (Fourier transform infrared) analysis was performed on naphthenate deposits obtained from crude oil (after water separation, the deposit was flowing below the oil layer; crude oil and water were poured through a 100-mesh sieve; afterwards, the deposit was flushed with acetone in order to remove crude oil). The results are shown in Figure 1. Picture of the deposit is shown in Figure 2.

Via FTIR analysis, six peaks could be observed. The range between 3100 and 3700 cm⁻¹ refers to the stretching of OH bonds of alcohols and phenols. The peak at 2960.29 cm⁻¹ is related to the O-H group of the carboxylic acids. The next two peaks (1632.49 and 1402.80) correspond to the C=O ketonic group and the bending coordinates of the O-H group. The last two peaks (875.17 and 711.63) indicate the presence of aromatic hydrocarbons.

One of the objectives of this paper was to investigate the most suitable naphthenate inhibitors and solvents, as well as to undertake bottle tests of naphthenate inhibitors with a focus on the main indicators (water clarity, quality of separation surface, and clarity of oil).

The laboratory investigation started with inhibition tests. Our method of inhibitor selection was based on Nordgard’s [14]: 60 mL of water was placed in a bottle; the pH was decreased to below 7 using different acids (except one blind sample and ABS acid in 800 ppm, calculated by water amount), which prevented any naphthenate deposition. Then, 20 mL of naphthenic acids (CAS: 1338-24-5) was placed in a bottle with water and a small amount of acid, which was hand-shaken for 2 min and allowed to stand for 2 h. Then, 75 mesh sieves were weighed, and the mixture was passed through the sieves and washed. The sieves were later heated up to 120 °C for 1 h and then cooled to ambient temperature and weighed again. The amount of naphthenate deposit was determined as the difference between the weights of the sieve after and before the test. The test was repeated three times to confirm the results using five types of acids as inhibitors (hydrochloric, acetic, citric, formic, and ABS acids).

The second most important objective of this paper is to determine the most suitable solvents. Here, 0.1 g samples of naphthenate deposit were placed on probes. Then, 8 mL samples of different solvents were added to the probes and left for 2 h, after which the samples were passed through 75 mesh sieves. The sieves were placed in an oven and heated at 140 °C for 2 h to remove all the volatile components. The deposit was then weighed, and the mass values before and after the test were compared. The test was repeated twice in order to compare the results. In the section below (Results), the values of these results are average.

Then, bottle tests of demulsifiers/naphthenate inhibitors obtained from an oil rig were conducted (naphthenate inhibitors are often part of commercial demulsifiers; moreover, the strong acids can be used as demulsifiers themselves). In general, the temperature and concentration of the demulsifier had the greatest effects on the amount of separated water [16].

Standard bottle tests of demulsifiers were conducted in the following manner [17,18]:

• An exact quantity of oil was placed in a series of small bottles (the crude oil came from South-West Africa and had a water content of 80%).
• An exact quantity of demulsifiers was added to the bottles (except for one bottle, which acted as a reference).
• The bottles were hand-shaken for 2 min.
• The bottles were placed in a water bath at the appropriate temperature (ambient temperature, at ca. 20 °C).
• The results were recorded after 30 min (similar to the duration of retention in the separator).
• The following parameters had to be determined—water separation in time, water clarity, quality of the separation surface, water content in the oil, and oil salinity. Oil salinity is dependent on the amount of residual water in the oil (most inorganic salts dissolve in water, while they do not dissolve in oil). Consequently, the rate of water separation is highly connected to the impact of the demulsifier on oil salinity.

Nowadays, a desire for less harmful demulsifiers is prevalent [19]. Even plant extracts are sometimes used in demulsification processes [20].

The two best naphthenate inhibitors identified via this test were subjected to tests of the interfacial tension between the oil and water phases (test taken on Force Tensiometer K20, according to ASTM D971, using Wilhelmy plate). Such tests were conducted using synthetic oil (consisting of 50% aromatic and 50% aliphatic hydrocarbons); the inhibitors were added at different quantities, and the interfacial tension between the synthetic oil and water was measured. The objective of this test was to reveal the magnitude of the drop in interfacial tension.

3. Results

Firstly, we examined naphthenate deposit inhibition, whereby the impacts of different substances on naphthenate salt formation were investigated. Second, the solubility of the naphthenate deposits in different solvents was measured. Finally, bottle tests of LDNI were conducted, and the impacts of two inhibitors on the interfacial tension between the artificial hydrocarbon solution and tap water were assessed.

3.1. The Use of Different Acids as Naphthenate Inhibitors

This step was conducted twice; the average efficiency values are presented in

Table 1. Results of naphthenate inhibition test.

No.	Product	Water pH Before	Water pH After	Quality of Acids	Quality of Water	Efficiency (%)
1	Blank	9.71	9.71	Small quantity of deposit	Water turbid a little	0%
2	Hydrochloric acid solution	9.71	6.37	No deposit	Clear water	27%
3	Acetic acid solution	9.71	6.71	Small quantity of deposit	Water turbid a little	−39%
4	Citric acid solution	9.71	6.24	No deposit	Clear water	−35%
5	Formic acid solution	9.71	6.91	No deposit	Clear water	99%
6	ABS acid	9.71	9.71	No deposit	Turbid water	99%

and Figure 3. The blank sample contained no extra ingredients (oil and water without any acidic additive). The use of hydrochloric, acetic, and ABS acids is discussed in the literature [3,9,10,11,13]. No references to citric or formic acid were found.

ABS acid is widely used as a dispersant in the oil and gas industry [21]. According to our results, ABS acid may not only dilute the deposit but also disperse it, thus allowing it to pass through the sieves. Acetic acid and citric acid negatively impact the process due to the dissociation of acids and the creation of salts. This may increase the risk of inorganic deposition at points further along the installation. Formic acid showed the best efficiency of all the water-soluble acids. The inhibition it achieved (99%) was significantly higher than the values of other examples, except for ABS acid, which is not water-soluble. Importantly, the final pH of the water after the application of formic acid was slightly higher than that following the use of other water-soluble acids. The formic acid reacted with metal ions (calcium, sodium, etc.) and created highly water-soluble salts.

3.2. Determination of Optimal Naphthenate Solvent

Table 2. Efficiency of solvents used on naphthenate salts.

No.	Solvent	Remarks	Efficiency of Solvent
1	Hydrochloric acid solution	Small amount of deposit on the top	76%
2	Acetic acid solution	Small amount of deposit on the bottom	86%
3	Citric acid solution	No deposit, cloudy solution	97%
4	Formic acid solution	Clear solution, no deposit	100%
5	ABS acid	Deposit on the bottom	27%
6	Toluene	Turbid dispersion	82%
7	Aliphatic hydrocarbons, C12–C15	Turbid dispersion	59%
8	Water	No solution	1%
9	EGMBE	Dispersed deposit	94%
10	Isopropyl alcohol	Dispersed deposit	95%
11	Ethyl acetate	Dispersed deposit	30%
12	Acetone	Deposit on the bottom	4%

shows that the citric acid, formic acid, and other solvents (ethylene glycol mono butyl ether (EGMBE) and isopropyl alcohol) effectively removed the naphthenate deposits. Due to the corrosive effects of these acids on installations, the use of mutual solvents is more appropriate. Furthermore, acetone did not effectively dissolve the deposit; hence, it is ideal for washing sieves (inhibition of naphthenates).

It is clear that formic acid can be used for both naphthenate inhibition and the dissolution of existing deposits. ABS acid is much more effective when used for inhibition, while hydrochloric, acetic, and citric acids are more effective in naphthenate dissolution.

3.3. Bottle Test of Naphthenate Inhibitors and Interfacial Tension Measurement

In general, the clearer the water, and the lower the amount of deposit that has precipitated below the interface, the better the inhibitor. Five commercially available naphthenate inhibitors were tested here. The results of bottle tests undertaken at the industrial facility are presented in

Table 3. Results of the bottle tests of naphthenate inhibitors.

No.	Product	Retention Time (min)	Surface Quality	Water Quality	Observations
1	Blank	30	Rough	Dirty	A lot of oily deposit in water
2	NI-2	30	Smooth	Very clear	No deposit under oil layer
3	NI-3	30	Smooth	Clear	No deposit under oil layer
4	NI-4	30	Smooth	Clear	Small deposit under oil layer
5	NI-5	30	Rough	Moderate	Moderate water quality, hard to estimate deposit content under the layer
6	NI-6	30	Smooth	Clear	No deposit under oil layer

. Pictures of the bottles after test are shown on Figure 4 and Figure 5.

Based on the photos shown in Figure 4 and Figure 5 and visual investigations of the separation surface, we can infer that the inhibitors NI-2 and NI-6 were the most effective. Simon et al. [13] stated that in the absence of ARN naphthenic acid, the interfacial tension between brine and an xylene/oil solution is lower when the crude oil content in xylene is increased. Furthermore, some naphthenic acids and asphaltenes inhibit the formation of calcium naphthenate salts. Therefore, in certain areas, there was no naphthenate salt deposition, despite the presence of ARN acid or other naphthenic acids.

In this paper, the impacts of two commercial naphthenate inhibitors (NI-2 and NI-6) on the interfacial tension between artificial crude oil and tap water were assessed. The artificial oil contained 50% aromatic and aliphatic hydrocarbons, respectively (

Table 4. Composition of artificial crude oil.

Ingredient	Content
Hydrocarbons, C10, aromatics, >1% naphthalene	50%
Hydrocarbons, C16–C20, n-alkanes, iso-alkanes, <2% aromatics	50%

). Two inhibitors were added, in different concentrations up to 1000 ppm, to the artificial oil samples, and the interfacial tension between the two fluids was measured (Figure 6). This test was conducted in order to determine the magnitude of the drop in interfacial tension with the addition of commercial naphthenate inhibitors.

Both commercial inhibitors decreased the interfacial tension between the oil and water when added up to ca. 400 ppm concentration. At higher concentrations, this parameter became relatively stable. This was due to the fact that both products contained not only ingredients that inhibit naphthenate formation but also components that enhance demulsification properties. The demulsifier can be overdosed and create a stable emulsion [22], which is hard to break down. The nature of the emulsion is then changed from water-in-oil to oil-in-water. There is a huge possibility that the standard chemicals used for the demulsification of water from crude oil do not work in this environment. The interfacial tension between oil and water is thus increased. Nevertheless, by mixing crude oil at high speeds and with a low concentration of products, it is possible to break down this type of stable emulsion [23]. In this case, it is highly possible that the inclusion of high concentrations of products containing demulsifying agents will cause overdosing, thus resulting in stable or higher interfacial tension.

4. Discussion

We investigated the nature of naphthenate deposits, as well as specific solvents and inhibitors that could be used in production facilities to manage problems related to them. The experiments we performed included the standard naphthenate inhibitor tests (using acids to decrease the pH of water), solvent tests (dissolving as much material as possible), and standard bottle tests of commercial low-dosage naphthenate inhibitors (similar to the bottle test of demulsifiers, but here, the main indicators were taken into account during the test).

In the inhibition test (with acids), the highest level of inhibition was achieved using formic acid and ABS acid (99% efficiency achieved by both acids). It was found that formic acid could dissolve in water and decrease pH, which prevents the dissociation of naphthenic acids. When dissociation does not occur, naphthenic salts are not created. Although the formic and hydrochloric acids yielded positive results, acetic and citric acids showed considerable reductions in deposition (39% more deposit when using acetic acid and 35% more when using citric acid). This is related to the dissociation of acids and salt formation, as the deposit that remained after the test was not actually naphthenate salt, and it could thus precipitate in an industrial installation. The utilization of water-soluble acids could lead to corrosion, so approaches that use different solutions are more suitable for field operations.

ABS acid was collected along the oil/water interface and interacted with carboxylic salts to produce unorganized, stable agglomerates. This approach did not cause problems related to corrosion because of the poor solubility of ABS acid in water (unlike other tested acids, such as formic, acetic, and hydrochloric acids).

Therefore, in general, this type of naphthenate inhibition works, but it can cause corrosion or scale problems in other parts of the installation.

Additionally, various naphthenate solvents were tested. It was found that certain acids (formic and citric acids) dissolved naphthenates effectively and that other solvents showed comparable results (EGMBE and isopropyl alcohol). The efficiency values were 100% for formic acid, 97% for citric acid, and 95% and 94%, for isopropyl alcohol and EGMBE, respectively. The main advantage of using mutual solvents relates to the removal of the corrosive environment; however, since such installations are not frequently cleaned, such an approach is not very advantageous. Formic acid dissolved the entire naphthenic deposit, while in other cases, some deposits remained dispersed in the solution. This is still an acceptable result from a technological point of view, according to which the main objective is to remove deposits.

In the standard bottle tests, the two commercial products containing hydrotropes acted similarly to ABS acid and prevented the creation of stable aggregates. The main indicators used in the naphthenate inhibitor bottle tests were water clarity, type of interfacial surface (smooth, rough, raggy, baggy, etc.), and the number of particles flowing below the surface. A smooth interfacial surface is the most desirable. Fewer oil particles below the interfacial surface, together with a high purity of water, are indicators of an effective naphthenate inhibitor.

The bottle test was used to determine the most appropriate inhibitor for use at an installation. In general, field tests were conducted after the bottle tests to confirm the product’s efficiency throughout the entire process. An ideal naphthenate inhibitor will reduce the interfacial tension between the oil and water phases. As shown in Figure 6, the interfacial tension decreased with increasing dosage, but remained almost stable beyond 400 ppm, at which point the product reached CMC (critical micelle concentration). Reaching a product’s CMC means that the lowest possible level of interfacial tension has been achieved, and this cannot be reversed when more chemicals are added. Values of 100–200 ppm are the most suitable for most industrial applications. Using higher dosages does not increase the performance of a demulsifier. It is even possible that, at dosages that are too high, the product can be overdosed and an oil-in-water emulsion can be produced, which is hard to reverse.

5. Conclusions

• Problems with naphthenate salts are common around the world. Hence, the prevention of the precipitation of such deposits is a key issue of concern at many oilfields.
• The main objective of this paper was to resolve the problem of naphthenate deposition, review the data in the existing literature, present laboratory procedures for testing inhibitors and solvents, and examine potential solutions that can be used in industrial applications.
• Naphthenate inhibitors and solvents are important in oil exploration. They can be specifically selected via bottle tests for use against a precise problem, wherein factors such as clarity of water, type of interfacial surface, and the number of particles flowing below this surface are crucial.
• The assessed naphthenate inhibitors decreased the interfacial tension between synthetic oil and tap water by more than 30% at dosages of 400 ppm. Above this dosage, the interfacial tension measurements remained similar, suggesting that CMC occurred.
• The utilization of acetic and citric acids reduces pH (carboxylic acid dissociation is prevented at high pH values, which hinders salt deposition), but some salts produced by these acids can precipitate in other parts of the installation. This issue was not observed with formic acid or ABS acid.
• ABS acid amassed along the interface and acted as a carboxylate salt, increasing solubilization in water and eliminating naphthenic salts. Corrosion problems were minimalized in comparison with the use of standard acids.
• Formic and citric acids can be considered efficient naphthenate solvents. Nevertheless, due to potential corrosion issues, mutual solvents may be a better choice, as they resolve deposition and encourage the stable dispersion of what remains. This is acceptable in standard oil exploitation.
• In the future, the efficiency of mutual solvents should be improved, such as by using surfactants. Surfactants can help to destabilize the structure of the deposit, as a result of which the efficiency can be improved.
• Solvents and inhibitors can be used in oilfields where the problem of naphthenic deposits occurs. Prevention is the most effective approach—solvents should be added only when the deposit has precipitated and may cause pipeline blockage.