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Collaborating Authors
Results
Aspects of Modeling Asphaltene Deposition in a Compositional Coupled Wellbore/Reservoir Simulator
Darabi, Hamed (The University of Texas at Austin) | Shirdel, Mahdy (The University of Texas at Austin) | Kalaei, M. Hosein (The University of Texas at Austin) | Sepehrnoori, Kamy (The University of Texas at Austin)
Abstract Asphaltene precipitation, flocculation, and deposition in the reservoir and producing wells cause serious damages to the production equipment and possible failure to develop the reservoirs. From the field production prospective, predicting asphaltene precipitation, flocculation, and deposition in the reservoir and wellbore essentially avoids high expenditures associated with the reservoir remediation, well intervention techniques, and field production interruption. Since asphaltene precipitation and deposition strongly depend on the pressure, temperature, and composition variations (e.g. phase instability due to CO2 injection), it is important to have a model that can track the fluid behavior during the entire production process from the injection well to the production well, which is absent in the literature. In this paper, a comprehensive thermal compositional coupled wellbore/reservoir simulator with a capability of modeling asphaltene phase behavior in the reservoir and the wellbores is presented to address the wellbore/reservoir interaction, the effect of asphaltene deposition on the flow prediction and long-term reservoir performance. Indeed, the simulator models multiphase fluid flow in the reservoir and the wellbore to enable comprehensive production system analysis. In addition, wettability alteration due to the asphaltene deposition on the rock surface is considered in our models. We present primary production and CO2 flood simulation cases to investigate the effect of asphaltene deposition on oil recovery. The results show that injection of the light components into the reservoir significantly increases the instability of asphaltene components in the reservoir where they can precipitate further around the wellbore and in the wellbore. The precipitated asphaltene in the reservoir can be carried into the wellbore and be combined with excess asphaltene formation and deposit in the wellbore. In addition, our simulation shows that well productivity decreases significantly in case of asphaltene precipitation and deposition during the production life of a reservoir.
- Europe (0.67)
- Asia (0.67)
- North America > United States > Texas (0.47)
- North America > United States > Oklahoma (0.28)
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
Abstract Wettability modification of solid rocks by using surfactants is an important process that is used in practical applications such as oil recovery from reservoirs. When wettability is altered, both capillary pressure and phase relative permeability change wherever the porous rock is contacted by surfactant. Due to the complexity of reservoir rock, alteration of the wettability is not uniform throughout the swept area. Although there are several numerical studies in the literature to simulate the effect of wettability alteration on oil recovery from oil-wet rock systems, these wettability alteration models permit alteration of the rock wettability uniformly and independently from time. Properties such as capillary pressure, oil and water relative permeability, and interfacial tension are calculated by the use of an interpolation scaling factor between two wettability extremes: oil-wet and water-wet. In the present study, a novel time-dependent wettability alteration model is proposed in which the contact angle is correlated to the surfactant concentration through an empirical correlation developed by using experimental data. The model allows the rock wettability to be altered in a heterogeneous manner with time. The proposed model was tested against a number of experimental and simulation results. Very good quantitative agreements between the simulation outcomes and experimental data from the literature were shown. The simulation of surfactant solution imbibition in laboratory scale cores using the proposed new model showed that the wettability alteration should be considered as a dynamic process, which plays a significant role in history matching and prediction of oil recovery from oil-wet porous media. Also, we found that gravity force is the primary cause of surfactant solution getting into the core and changing the rock wettability toward a less oil-wet state.
- North America > United States > Texas (0.93)
- Asia (0.68)
- North America > United States > Texas > Permian Basin > Delaware Basin > Yates Field > Whitehorse Group > Word Group > San Andreas Formation (0.99)
- North America > United States > Texas > Permian Basin > Delaware Basin > Yates Field > Whitehorse Group > Grayburg Formation > San Andreas Formation (0.99)