A General Study of Asphaltene Flocculation Prediction at Field Conditions
- Samir G Gharfeh (ConocoPhillips Co.) | Probjot Singh (ConocoPhillips) | Kriangkrai Kraiwattanawong (ConocoPhillips) | David J. Blumer (ConocoPhillips)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Operations
- Publication Date
- August 2007
- Document Type
- Journal Paper
- 277 - 284
- 2007. Society of Petroleum Engineers
- 4.1.2 Separation and Treating, 5.2 Reservoir Fluid Dynamics, 4.6 Natural Gas, 4.3 Flow Assurance, 5.2.1 Phase Behavior and PVT Measurements, 4.2 Pipelines, Flowlines and Risers, 4.1.5 Processing Equipment, 1.11 Drilling Fluids and Materials, 4.3.1 Hydrates, 1.6 Drilling Operations, 5.3.2 Multiphase Flow, 4.2.3 Materials and Corrosion, 4.3.3 Aspaltenes, 1.8 Formation Damage, 4.5 Offshore Facilities and Subsea Systems
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A large set of field data have been collected during the last decade related to various facets of asphaltene instability problems at our production facilities. These problems include compatibility of heavy oil with hydrocarbon diluents in a Venezuelan operation, commingling of live oil and condensate in a North Sea production facility, compatibility of drilling mud-base oil, and miscible injectants with reservoir fluids in Alaskan operations. In each of the field cases, significant lab data were generated by titrating the neat dead crude oil, and oil-solvent blends with n-alkanes. The solvents used to study the asphaltene issue were toluene, condensate, and base-oil. We have applied available asphaltene prediction techniques (Heithaus 1960, 1962; Wiehe and Kennedy 2000a, b; Wiehe et al. 2001; Andersen 1999; Wang and Buckley 2001; Wang et al. 2003, 2004; Leontaritis 1998) to explain the field data. None of the models has been found comprehensive enough to explain flocculation at all the conditions, including the flocculation that occurs at ambient conditions in the presence of paraffinic diluents, stability enhancement that occurs upon addition of aromatic solvents, and the instability that occurs in a live fluid because of changes in composition, pressure, and temperature. To handle a complex crude oil system, these models made some simplifying assumptions that enabled them to make the problem manageable. In doing so, they lose some predictive capability. We found there are two forces that need to be accurately captured—dynamics of the alteration of solubility parameter of the hydrocarbon matrix, and change in entropy of mixing—to model the asphaltene behavior. The latter has been either empirically estimated by extrapolating the ambient titration data or neglected in many of the previous models. The basic parameters for our model can be calculated from lab data generated by titrating the dead crude oil, or oil solvent blends with n-alkanes, at different temperatures. So far, this model has been applied to various field conditions in production facilities and has been found successful in matching the field data.
Asphaltenes are generally defined as the fraction that is soluble in aromatic solvents such as benzene or toluene; and insoluble in normal alkanes, such as n-pentane or n-heptane (Speight 1999). Asphaltenes are typically stable in a live fluid at reservoir condition. Once the drilling and production starts, the change in pressure, composition, and temperature can cause asphaltenes to destabilize. Asphaltene precipitation and deposition in production and operation are undesirable situations that are quite expensive to remediate.
The solubility parameter concept first described by J.H. Hildebrand and R.L. Scott (1964) was used as a compatibility indicator, such that if the solubility parameter of any mixture was greater than the solubility parameter at the onset point of precipitation, that mixture was stable—otherwise asphaltene would flocculate..
This paper focuses on the development of a comprehensive asphaltene precipitation model based on the solubility parameter concept. A successful model should be able to predict onset of asphaltene flocculation under any field condition. Several field projects are also included in this paper to show the wide application of the asphaltene precipitation predictor in several different circumstances. For example, asphaltenes can precipitate if an incompatible blend of two or more hydrocarbon liquids are mixed in sales pipeline or in a refinery. Asphaltenes can cause sludge formation and emulsion issues in surface facilities (flow line or separators). Asphaltenes can drop out during depressurization of live oil near wellbore during production or commingling with miscible injectant (MI) in the reservoir during enhanced oil recovery.
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