Modelling of Asphaltene Precipitation and Deposition during WAG Application

Abstract

Abstract Asphaltene precipitation and deposition from reservoir fluids during oil production life is a serious problem that can cause plugging in the formation, wellbore and production facilities. Precipitation and deposition may occur during primary production, during the displacement of reservoir oil by Co2, hydrocarbon gas or WAG application. This paper describes the modelling of asphaltene precipitation and deposition in the reservoir porous media. This model is based on fluid properties of typical reservoir oil that includes asphaltene precipitation data. The pure solid model is used to model asphaltene precipitation. The fluid model part is based on the representation of the precipitated asphaltene as a pure dense phase and division of the heaviest components of oil sample into non-precipitating and precipitating components. The fluid properties data are validated and matched with equations of state. Then, it is tried to tune the equations of state based model that represent the asphaltene as pure component solid. This paper also, mentions the concept of asphaltene modeling and its related parameters by using a compositional simulation model. After tuning the equation of state (EOS) by analyzing the oil properties data and setting the asphaltene control parameters, the simulation model was built by incorporation of the equation of state for asphaltic oil properties and the other asphaltene parameters into the compositional simulation model. The model enables the simulation of asphaltene precipitation, flocculation, and deposition including adsorption, plugging, and entrainment under natural depletion and WAG application recovery processes. The model is used to investigate the effects of asphaltene on reservoir performance parameters, including wells oil production, wells bottomhole pressure, reservoir recovery factor and average reservoir pressure, also it can be used to study formation damage including reduction in porosity and permeability in each block and changes in oil viscosity and rock wettability during different recovery scenarios. Introduction Heavy organic components such as asphaltenes, resins, and waxes exist in crude oils in various quantities and forms [1–3]. Such compounds could separate out of the crude oil solution due to various mechanisms and deposit, causing fouling in reservoir, wells, pipelines and oil production and processing facilities [3]. Depositions of the heavy organics present in crude oil happen due to various causes depending on their molecular nature. Paraffin wax can deposit and form solid crystals due, mostly, to lowering of temperature. Resins are not known to deposit on their own, but they deposit together with asphaltenes [3]. Asphaltenes are arbitrarily defined as a solubility class of petroleum that is insoluble in light alkanes such as n-heptane or n-pentane but soluble in toluene or dichloromethane [4, 5]. The reasons for the asphaltenes deposition can be many factors including variations of temperature, pressure, pH, composition, flow regime, wall effect and electro kinetic phenomena [3, 6]. There are many papers that have addressed asphaltene problems during primary recovery or CO2 injection as secondary recovery stage [7–10]. Formation damage due to asphaltene deposition in the oil industry is an issue for many fields that cause reduction in production and shutting of some of the wells and a severe detrimental effect on the economics of oil recovery [1–3]. Once the asphaltene deposition occurs, it causes severe permeability and porosity reduction and wettability alteration, changing relative permeability in the reservoir and, in the severe cases plugging the wellbore and surface facilities [11–14]. It is clear that the approach taken by most operators is a remedial solution rather than preventive. The remedial measures such as chemical treatment and workover operations are disruptive and expensive [15]. Thus, the probability asphaltene precipitation and deposition occurring during any EOR techniques, its effects on reservoir performance, and preventive measures should be anticipated at earliest stages of each project. This anticipation can be reached through better understanding of the mechanisms up front that initiate such problems [10].