Summary This paper describes a simple method to screen crude oils for their tendency to precipitate asphalt, which may cause problems during production. The method is based on a thermodynamic model of asphalt solubility, derived earlier by Flory and Huggins. The most important parameters in this model are the Hildebrand solubility parameters for oil and asphaltene, and their molar volumes. The oil parameters can all be correlated with the in-situ density of the crude. The relative change in asphalt solubility in the crude per unit pressure drop is shown to be highest for light crudes that are undersaturated with gas, which usually contain only a small amount of asphaltenes. Hence, the chance that asphalt will precipitate will be greatest for these light crudes. For pressures below the bubblepoint, depressurising of the crude will cause a rapid increase in asphalt solubility, due to changes in liquid composition. It is shown that heavy crudes usually will give fewer problems with asphalt precipitation, despite their higher asphaltene content, certainly if the reservoir pressure is close to bubblepoint pressure. Consequently, the tendency for asphalt precipitation is mainly determined by three parameters: the extent to which the crude is undersaturated with gas, the density of the crude at reservoir conditions, and its saturation with asphalt at downhole conditions. Apart from the simple screening method, more elaborate methods are described to assess the potential for asphalt precipitation more accurately; asphaltene analysis on produced reservoir fluid and tank oil; n-heptane titration of the tank oil; visual inspection of a bottomhole sample in a high-pressure cell during pressure reduction; and dynamic flow tests on tank oil after n-heptane addition. An ultrasonic back scattering technique is described for monitoring the influence of different asphalt precipitation inhibitors. Using above techniques asphalt precipitation inhibitors have been identified that can be applied in the field. Introduction Asphalt is a heavy, highly viscous phase mainly consisting of asphaltenes: the high-molecular weight fraction of a crude that is insoluble in n-heptane. Asphalt precipitation in reservoirs, in wells and facilities has a severe detrimental impact on the oil production economics due to a reduction of well productivity and/or a clogging of the production facilities. Problems with asphalt precipitation during production are difficult to correlate with the asphalt content of the crude. A compilation by Leontaris & Mansoorishowed as extremes the Venezuelan Boscan crude with 17% asphalt that was produced nearly trouble free while the Algerian Hassi-Messaoud with only 0.062% asphalt met with difficulties during production.
Reservoir conditions core flood tests have been carried out to examine the damage arising from overbalanced drilling-in operations. Gannet field cores were exposed to a number of water- and oil-based field muds currently in use by Shell Expro. Results showed that the initial permeabilities to crude oil were dramatically reduced after exposure to overbalanced mud and subsequent back production of crude oil. Thin section petrography and SEM/XRD analysis of the cores clearly showed the source of impairment in all cases to be a thin layer of mud solids plugging pores and throats exposed to the wellbore face, forming an effective permeability barrier that was not dislodged by crude drawdown under realistic drawdown. The results were confirmed by trimming of 1 cm from the wellbore face of the core that led to a restoration of initial permeability. Introduction The issue of formation damage has returned to prominence with the exponential growth of horizontal wells in recent years. The increase in productivity offered by the increased contact between reservoir and wellbore is a two-edged sword. The increased contact also allows an increased area of damage to form. The relative effects of that damage on production remain unclear. Near wellbore damage impairs the formation 1s ability to conduct hydrocarbons to the wellbore Formation damage lowers well productivity, defers production revenues and is difficult to repair. A large number of formation damage mechanisms arising from the interaction of drilling mud solids and fluids with the reservoir solids and fluids can occur. Current field evaluation techniques to measure in-situ formation damage may lack the resolution to provide meaningful data on the extent of the problem. Reservoir conditions core flood tests provide a means to simulate the interactions that take place between the invading drilling mud and the formation. This allows measurement of the extent of the impairment and visualisation of the mechanism. The technique attempts to simulate, as closely as possible, the conditions occurring in the reservoir during drilling-in through the use of:–Real, used field muds sampled from previous drilling campaigns–Fresh, well-preserved core material from the target reservoir, and if possible, original native pore fluids, i.e., both pore water and hydrocarbons–Realistic, long-duration core exposure to the drilling fluid under reservoir conditions, with mud flow past the core face at realistic borehole velocities–Measurement of formation damage by crude oil return permeability determination after simulated back production under drawdown P. 101
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