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.

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

Demulsification (dehydration) is one of the most important problems in the oil industry. The peculiarity of heavy oil emulsions is their high stability since heavy crude contains a significant quantity of resins and asphaltenes. This paper provides an overview of the issue of heavy oil emulsion dehydration, emphasizing the importance of understanding their properties to develop appropriate demulsification methods. The use of environmentally friendly demulsifiers was an object of special attention. The analysis of ongoing research in this area would be useful for researches and engineers. 

pdf/demulsification-methods-for-heavy-crude-oil-emulsions-a-57xew1rbdf.pdf

Demulsification Methods for Heavy Crude Oil Emulsions. A Review

Undesirable water-in-crude oil emulsions in the oil and gas industry can lead to several issues, including equipment corrosion, high-pressure drops in pipelines, high pumping costs, and increased total production costs. These emulsions are commonly treated with surface-active chemicals called demulsifiers, which can break an oil–water interface and enhance phase separation. This study introduces a novel approach based on neural networks to estimate demulsification efficiency and to aid in the selection of demulsifiers under field conditions. The influence of various types of demulsifiers, demulsifier concentration, time required for demulsification, temperature and asphaltene content on the demulsification efficiency is analyzed. To improve model accuracy, a modified full-scale factorial design of experiments and the comparison of response surface method with multilayer perception neural networks were conducted. The results demonstrated the advantages of using neural networks over the response surface methodology such as a reduced settling time in separators, an improved crude oil dehydration and processing capacity, and a lower consumption of energy and utilities. The findings may enhance processing conditions and identify regions of higher demulsification efficiency. The neural network approach provided a more accurate prediction of maximum of demulsification efficiency compared to the response surface methodology. The automated multilayer perceptron neural network, with an architecture consisting of 3 input layers, 14 hidden layers, and 1 output layer, demonstrated the highest validation performance R2 of 0.991932 by utilizing a logistic output activation function and a hyperbolic tangent activation function for the hidden layers. The identification of shifted optimal values of time required from demulsification, demulsifier concentration, and asphaltene content along with sensitivity analysis confirmed advantages of automated neural networks over conventional methods. 

A Novel Approach for the Estimation of the Efficiency of Demulsification of Water-In-Crude Oil Emulsions

The Second Oil Production Plant of Xinjiang Oilfield produces a large amount of highly emulsified crude oil, which has a serious impact on the subsequent oil–water separation. At present, the concentration of demulsifier has increased to 2000 mg/L, but the demulsification effect is still poor. In this paper, the source and physical properties of highly emulsified crude oil are investigated firstly. The results show that highly emulsified crude oil is composed of three kinds of liquid: (1) conventional water flooding (WF); (2) chemical flooding (CF); (3) fracturing backflow fluid (FB). Among them, high zeta potential, low density difference, high viscosity, and small emulsion particles are responsible for the difficulty in the demulsification of the WF emulsion, while the high pH value is the reason why the CF emulsion is difficult to demulsify. Therefore, systematic experiments were implemented to investigate the optimal demulsification approach towards the three liquids above. As for the WF emulsion, it was necessary to raise the temperature to 70 °C and the concentration of the demulsifier to 200 mg/L. Moreover, it was only necessary to add 200 mg/L of demulsifier to break the CF emulsion after adjusting the pH value to 7, while no extra treatments were needed to break the FB emulsion. We hope this study can provide a new insight for the treatment of emulsions in the later stage of oilfield development.

/pdf/study-on-wastewater-demulsification-technology-of-crude-oil-2qai28n2.pdf

Study on Wastewater Demulsification Technology of Crude Oil in Xinjiang Oilfield

Industrial transformation has brought about huge changes to the human society in many different aspects [...] 

Special Issue on “Resource Recovery and Harmless Treatment Processes for Industrial Organic Pollutants”

HYW (Hong Yi Wu line) heavy oil emulsion in Xinjiang Oilfield (Karamay, China) is a kind of heavy oil with high viscosity and high emulsification. Its viscosity reaches 120,000 mPa·s at 40 °C. The emulsion has no demulsification. Even if the demulsification temperature reaches 90 degrees, the concentration of demulsifier reaches 260 mg/L. In this paper, a new process of thermochemical demulsification of heavy oil after blending is studied. First, SE low-viscosity oil with viscosity of 640 mPa·s and water cut of 90% was selected as blended oil. Study the viscosity of SE line and HYW line at different temperatures after fully blended. The results show that the heavy oil blended model conforms to Bingham model. When the temperature is 40 °C and the content of SE line is 30%, the viscosity is less than 10,000 mPa·s. With the increase of temperature, the viscosity continues to decline. When the temperature exceeds 80 °C, the viscosity is less than 1000 mPa·s. The final design SE line content is 30%, the demulsification temperature is 70 °C, and the demulsifier concentration is 160 mg/L as the best demulsification parameter. The field results show that the demulsification rate of heavy oil in this process reaches more than 90%. This experiment lays a foundation for demulsification of high emulsified crude oil developed by heavy oil in Xinjiang oilfield.

/pdf/study-on-demulsification-technology-of-heavy-oil-blended-in-1y8t7w4x.pdf

Study on Demulsification Technology of Heavy Oil Blended in Xinjiang Oilfield

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Study on Demulsification Technology of Heavy Oil Blended in Xinjiang Oilfield