Anticipating Asphaltene Problems Offshore-A Practical Approach

Abstract Offshore developments require advance planning for many flow assurance problems including the possibility that asphaltenes may become unstable in the production operations at some point during the producing life of the reservoir. From some oils, asphaltenes can appear during depressurization. In other cases, addition of lift or injection gas can destabilize asphaltenes. In some production systems, destabilization of asphaltenes occurs upon mixing dissimilar oils. This paper presents an integrated approach to predicting all of these potential asphaltene problems using a methodology that relies on laboratory characterization of asphaltene stability in stock tank oil samples in combination with standard PVT and compositional data. Details of the characterization technique and prediction method are provided for problems of practical interest for offshore developments. Predictions of asphaltene stability using this approach are compared with live oil measurements and field experience, where available. Introduction It has long been recognized that asphaltenes can flocculate during depressurization of a reservoir1-3 and that asphaltene problems occur in a wide range of recovery and transportation scenarios (e.g., Ref. 4). Nevertheless, accurate predictions of asphaltene instability have been elusive. As long as remediation was less expensive than avoidance of asphaltene problems, there was little need for accurate prediction. The need has become much more acute in recent years, however, as offshore developments have enormously increased the costs associated with asphaltene remediation. Accurate prediction requires physically correct models. Many of the hypotheses on which early models were based were never grounded in scientific fact.5 Speculations that asphaltenes were coated with a peptizing layer of resins and that flocculation occurs during titration with n-alkanes because the resin are diluted, shed no light on flocculation during depressurization. Asphaltenes were quantified by addition of an excess of n-alkane (typically n-pentane or n-heptane) even though it is now recognized that oils with large amounts of asphaltenes are often among the most stable and that problems can arise in oils with very small asphaltene contents. Titration measurements, in which the same n-alkanes are added to oils to find the onset of asphaltene instability, were commonly made, but interpretation remained a problem. The first reasonable predictions of asphaltene stability from titration data came from thermodynamic models that treat asphaltenes as analogs of polymers.6-8,5 Key parameters of these models are solubility parameters of asphaltenes and maltenes (used here to refer to all of an oil except its asphaltenes) and the molar volumes of the same two fractions. One limitation of these models was the need to estimate solubility parameters. Buckley et al.9 showed that measurements of refractive index (RI) can provide accurate estimates of solubility parameters, eliminating the need for cumbersome approximations. An empirical approach that makes use of these key parameters10 is the basis of the predictions of asphaltene instability in a variety of offshore production activities presented in this paper. Techniques have recently been developed to measure asphaltene instability at reservoir conditions of temperature, pressure, and composition. A solids detection system (SDS), originally developed to observe wax crystal formation,11 was adapted to study asphaltene instability during depressurization;12 results compared well to several other methods.13