The Key to Predicting Emulsion Stability: Solid Content
- Michael K. Poindexter (Nalco Energy Services) | Shaokun Chuai (Sloan-Kettering Memorial Cancer Center) | Robert A. Marble (Nalco Energy Services) | Samuel Marsh (Nalco Co.)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Operations
- Publication Date
- August 2006
- Document Type
- Journal Paper
- 357 - 364
- 2006. Society of Petroleum Engineers
- 1.8 Formation Damage, 5.1 Reservoir Characterisation, 2.4.3 Sand/Solids Control, 5.8.5 Oil Sand, Oil Shale, Bitumen, 4.1.5 Processing Equipment, 5.3.2 Multiphase Flow, 4.3.3 Aspaltenes, 4.1.2 Separation and Treating, 4.3 Flow Assurance, 4.3.1 Hydrates, 4.1.3 Dehydration
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Chemical demulsifiers are routinely added in the oil field to effectively resolve water-in-crude-oil emulsions. As used in the common bottle test, demulsifiers, in effect, probe or interrogate emulsion stability strength. Emulsion stability, in turn, is defined by no fewer than three parameters: water drop, oil dryness, and interface quality. All three parameters are direct outputs of the bottle test, and, collectively, all three provide a more complete picture of emulsion stability, as opposed to the use of any singular parameter.
By selecting a wide variety of demulsifiers and by performing a standardized bottle test, emulsion stability from a variety of sites can be quantified and compared. By coupling bottle test results with corresponding crude oil analytical data, fundamental questions concerning factors governing emulsion stability can be quantified. The results show that solid content, not asphaltene content or any other crude oil parameter investigated, is by far the best single predictor for gauging emulsion stability. Furthermore, statistical analysis through partition trees shows that emulsion stability is most aptly described using several crude oil parameters, as opposed to one single factor.
Crude oil characterization remains a challenging proposition. Many crude oil characterizations are based on a separation scheme [e.g., distillation (Speight 1998), chromatography (ASTM D4124 2003; McLean and Kirkpatrick 1997c), and precipitation (Akbarzadeh et al. 2004)], a bulk property of the fluid [e.g., viscosity, American Petroleum Inst. (API) gravity, and surface tension), or a combination of properties. The intent of most characterizations is to relate some property or group of properties back to the fluid's behavior in production or refining. Establishing a valid cause-and-effect relationship can lead to greater confidence when assessing the economic and technical risks associated with new projects or modifications to existing systems.
As related by Hopf (2000), crude oil characterization played a strong role in the development of organic chemistry. For example, the cage hydrocarbon adamantine—a classic in skeletal construct—was first isolated in minute amounts (0.0004%) from petroleum in 1933, 8 years before a synthetic confirmation. The characterization of crude oil has thus developed, both one molecule at a time and by groups of molecules. Fractionation into saturates, aromatics, resins, and asphaltenes (SARA) remains the most common method for classifying crude oils by groups. A variety of techniques exist for classifying crude oils by SARA analysis. Two recent advances in SARA characterization center on the use of high-performance liquid chromatography (Fan et al. 2002) and infrared and near-infrared spectroscopy (Aske et al. 2001). The most studied petroleum group is the asphaltene fraction, which is an ensemble of molecules defined by both solubility and insolubility properties (Pfeiffer and Saal 1940) and certain general features regarding structure and atomic composition (Koots and Speight 1975). Recently, a process for quantifying the overwhelming molecular complexity of crude oil has been illustrated by high-resolution mass spectroscopy (Marshall and Rodgers 2004). Such quantifications are providing a fingerprint with which to compare and contrast crude oils. This technique is quite an advancement that holds unprecedented potential. While certain atomic arrangement information is still not possible with mass spectroscopy, the ability to rapidly amass and store crude oil information for any molecular parameter holds great promise.
Additionally, Buckley (1999) pointed out that the characterization of crude oil and asphaltenes in particular is on the basis of not just the output of laboratory methods, but also by process conditions that influence the solubility parameter and ultimate fate of the asphaltenes (Wang et al. 2004). Such an operational definition clarifies the need to couple crude oil properties (i.e., characterizations) with crude oil behavior in the field. The industrial practice of establishing and managing such critical relationships ultimately falls under the realm of flow assurance. Flow assurance can be divided into the deposition of solids (e.g., hydrates, waxes, asphaltenes, and scales) and disturbed fluid behavior (e.g., foaming and emulsification) (Fu 2000). The latter of these areas is the focus of this study.
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