Aliyu A. Sulaimon

The Roles of Polar Compounds in the Stability and Flow Behavior of Water-in-Oil Emulsions

This paper summarizes an investigation of the roles of asphaltenes and other polar compounds in forming and stabilizing water-in-oil emulsions. Two crude oils with entirely different starting properties from Canada and Malaysia were used for the study. Asphaltenes and polar compounds were isolated from the crude oils using silica columns, and emulsions were prepared with the asphaltenes-free crude oils. These investigations have confirmed that water-in-oil emulsions formed by amphiphiles with the highest molecular weight play the most important roles in stabilizing W/O emulsions. Rheological as well as stability studies were conducted for emulsions formed by the crude oils with and without asphaltenes. The study shows that the viscosity of emulsions formed by the crude oils with asphaltene at a shear rate of one reciprocal second is about three orders of magnitude greater than that of the starting oil. An unstable emulsion is formed with the asphaltene-free crude oils, and thus, the viscosity of the emulsion is not more than about 20 times greater than that of the starting oil. A stable emulsion has a significant elasticity, whereas an unstable emulsion does not. A mesostable emulsion has properties between stable and unstable, but breaks down within a few days of standing. The usual situation is that emulsions are either obviously stable, mesostable, or unstable. The type of emulsion produced is determined primarily by the properties of the starting oil. The most important of these properties are the asphaltene and resin content and the viscosity of the oil. The composition and property ranges of the starting oil that would be required to form each of the water-in-oil states are discussed in this paper.

Rheological and stability study of water-in-crude oil emulsions

The formation of crude oil emulsion is a prevalent oilfield problem that can cause significant flow assurance issues during oil production, treatment and transportation. When they occur, emulsion problems are very difficult to solve and can lead to numerous operational problems like; creating high pressure drops in pipes and/or flowlines, production of off-specification crude oil and tripping of separation equipment. These emulsions can be very stable as a result of the presence of polar compounds, such as asphaltenes and resins, that play the role of natural surfactants and also because of the occurrence of many types of fine solids that can form resistant films at the crude oil/water interface. Solid particles also play significant roles in stabilizing emulsions. The water produced during oil production is either produced as free water, and so it will settle out fairly quickly, or the water may be combined with oil in the form of emulsions. This is more prevalent when producing oil from mature oilfields, where water production is relatively large. Under standard oilfield conditions the most common form of emulsion is a water-in-oil emulsion; a dispersion of water droplets in oil. In this work, the authors studied the consequence of different water-cuts and the presence of an emulsifier on the stability of water-in-oil emulsions. The rheological properties of W/O emulsions with different water cuts (10-50 v/v %) at different temperatures (25°C – 60°C) were studied. Rotational rheology and stability of the emulsions were studied on emulsions aged for 30 days. Generally, the results revealed that the presence of an emulsifying agent, difference in water content, shear rate and temperature significantly affect emulsion stability and rheological properties

Investigating the Influence of Water Cut on Naphthenate Precipitation in Oil Production Facilities

Naphthenic acids occur naturally in crude oils and can under certain conditions react with metal ions from produced water to form naphthenates. Precipitation of naphthenates can lead to serious problems in oil production facilities. Prediction of naphthenate precipitation is an important step toward early detection and resolution of their associated problems. Developing a method that will accurately predict precipitation of naphthenates in surface facilities and separators is of great value to the industry. In this paper, the principle of metal naphthenate formation is discussed. Experiments were conducted to investigate the effects of synthetic brine on naphthenic crude oil. The results were used to establish the relationship between produced water and the amount of naphthenate deposits. The experiments used a crude oil that has been classified as containing naphthenic acid and a laboratory-prepared synthetic brine. The pH of the brine was adjusted to suit the condition required for the experiment. Results show that increased water cut greatly influences the amount of precipitates. pH of subsequent mixtures increases as the volume of the brine is increased for each successive experiment. Precipitation of naphthenates occurs due to chemical reactions between the ions in both the brine and the naphthenic acid. It is established that as the produced water from reservoir increases, the amount of precipitates formed also increases since there are more ions made available for the chemical reaction. Maximum deposition of naphthenate precipitates occurred at 67 % water cut. The mass of precipitate measured at this water cut was 88 mg from 10 ml of crude oil and 136 mg from 20 ml of the same oil.

Wax and Asphaltene Deposition Tendency of Malaysian Crude Oils

Flow assurance is a term generally used to describe the processes that may lead to fluid flow restriction in production, processing and transportation systems, and also the comprehensive management of the processes and operations to ensure effective and efficient production and delivery of oil and gas from the reservoir to the refinery. Often, the flow assurance issues are largely associated with hydrates, organic waxes and asphaltenes deposition due to changes in fluid composition, pressure and temperature conditions. Organic wax starts to precipitate from oil when temperature falls below the cloud point. The focus of this research is to characterize Malaysian crude oils from Dulang, Tapis, Miri, Dubai, and Arab fields to evaluate their tendency to precipitate wax and/or asphaltene. The oils were characterized by conducting SARA analysis with high-performance liquid chromatography (HPLC), while carbon distribution of the oils was determined by gas chromatography mass spectrometry (GC-MS). Differential scanning calorimetry (DSC) and density meter were used to measure the WAT of waxy oils and the colloidal instability index (CII) was calculated to evaluate asphaltene deposition potential. The effect of continuous carbon dioxide (CO2) injection on WAT was also investigated. Results show that crude oils with higher paraffinic content exhibit higher WAT and precipitated wax. Continuous gas injection was found to lower the WAT, thus reducing the risk of wax precipitation. Tapis oil with highest CII (5.05) is the most susceptible to asphaltenes deposition, while Arab oil with CII of 1.21 has the least tendency to cause asphaltenes deposition problems.