No abstract

Asphaltene deposition during oil production may partially or totally plug the wellbore, and results in significant reduction in well production and frequent asphaltene remediation jobs. It is well-known that injection of lighter hydrocarbons into an asphaltic oil (e.g. during gas lift) may decrease the stability of asphaltene particles in the solution and increase the risk of asphaltene precipitation and deposition. Although a great deal of research has investigated the effect of gas injection on the phase behavior and mechanism of asphaltene deposition in the wellbore, we lack a comprehensive dynamic model that can track the behavior of asphaltene during gas lift process. Therefore, a comprehensive model is required for evaluating the risk of gas lift on asphaltene deposition in production wells. This paper presents a comprehensive thermal compositional wellbore model with the capability to model asphaltene phase behavior during gas lift and determine the effect of the injected gas on asphaltene deposition in the wellbore. In the developed wellbore simulator, various numerical approaches are used to model multiphase flow in the wellbore. An equation of state was used to calculate the thermodynamic equilibrium conditions of the phases. In addition, several deposition mechanisms were incorporated to study the transportation, entrainment, and deposition of solid particles in the wellbore. Various case studies investigated the effect of gas lift on asphaltene deposition. To predict where and when the most severe damage would occur in the wellbore, we used field data of a Middle East crude oil and an injection gas. The results showed that the injection of light gas composition can negatively affect the production facilities by intensifying asphaltene precipitation in the well, which eventually results in significant reduction in the wellbore production. We believe that this comprehensive thermal compositional wellbore model can facilitate the design of work-over operation plans for asphaltic wells operating under gas lift.

Selecting an appropriate Equation of State to model asphaltene precipitation in compositional wellbore/reservoir simulators is still unclear in the literature. Recent studies have shown that PC-SAFT is a more appropriate model for asphaltene precipitation compared to the commonly used solid model. The main objective of this paper is to compare the solid model and PC-SAFT in both static and dynamic asphaltene modeling. Through fluid characterization, the capabilities of both models are compared to reproduce precipitation experimental data. The results show that both solid model and PC-SAFT are capable of accurate modeling of asphaltene precipitation. Although matching process using PC-SAFT is much easier, solid model is also able to reproduce the experimental data with the same quality as PC-SAFT, if it is tuned properly. The simulations showed that PC-SAFT is superior to solid model in terms of accuracy for extrapolation when the experimental data are not available for the simulation conditions (i.e. variation in temperature, pressure, and fluid composition in the reservoir/wellbore). However, both models are applicable for interpolation when the experimental data covers the range of simulation condition. The wellbore simulations show that although the trend of asphaltene deposition is similar for both models, solid model overestimates the amount of asphaltene precipitation and deposition in the wellbore compared to the PCSAFT model. On the other hand, since PC-SAFT uses an iterative procedure for finding the density roots, phase equilibrium calculation, and consequently, the simulation procedure takes much more computational time when PC-SAFT is used.

Summary Scale deposition in surface and subsurface production equipment is one of the common problems during oil production, resulting in equipment corrosion, wellbore plugging, decrease in production rate, and frequent remediations. In this work, a detailed procedure is presented through which a compositional wellbore simulator is developed with the capability of modeling comprehensive geochemical reactions. The compositional wellbore simulator (UTWELL) is developed by applying different numerical approaches and flow-regime-detection methods to accurately model multiphase flow in the wellbore. In addition, several deposition mechanisms are incorporated for the transportation, entrainment, and deposition of solid particles in the wellbore. Subsequently, a geochemical module, IPhreeqc, is integrated into the wellbore model to handle homogeneous and heterogeneous, reversible and irreversible, and ion-exchange reactions under either local-equilibrium or kinetic conditions. This package provides a robust, flexible, and accurate integrated tool for mechanistic modeling of scale deposition in the wellbore. Through our integrated simulator, deposition profiles of carbonate and sulfate scales in the wellbore are predicted for several case studies. Significant effects of physiochemical properties (such as pressure, temperature, salinity, and pH value) on the scale deposition in the wellbore are discussed. In addition, comparing simulation results with experimental data reveals that hydrocarbon-phase dissolution has a significant effect on geochemical calculations compared with the temperature/pressure variation effects. To the best of our knowledge, there is no comprehensive simulator available in the industry through which scale deposition in the wellbore can be predicted accurately. In this paper, scale deposition profile in the wellbore is estimated by including the interaction of the hydrocarbon and aqueous phases and its effect on the aqueous-scale geochemistry (by use of a compositional wellbore simulator); effects of parameters that vary greatly in the wellbore (pressure, temperature, and pH value); and comprehensive geochemistry simulation (provided through coupling of the wellbore simulator with IPhreeqc). The outcome of this study yields a comprehensive tool for scale deposition prediction in the wellbore and will help scale deposition risk-management and mitigation plans.

Scale deposition is a common problem during oil production resulting in equipment corrosion, wellbore plugging, and production rate reduction. In unconventional reservoirs, the negative effect of scale formation and deposition becomes more pronounced as it severely damages the conductivity of hydraulic fractures. However, how and to what extent the scaling changes the gas production is unclear. In this work, a robust and integrated tool is developed to model scale deposition under dynamic flow conditions in unconventional reservoirs considering the damages to fracture and shale matrix. In doing so, a comprehensive compositional reservoir simulator (UTCOMP) coupled with IPhreeqc is utilized to predict carbonate and sulfate scales formation in the Marcellus shale formations. This integrated approach allows to adequately resolve the multiphase flow in the fracture network and near-wellbore region and to determine the associated geochemical behavior. Our results show that scale formation mainly results from changes in the physicochemical properties of brine (pH, temperature, and pressure) and/or mixing with incompatible brine compositions (e.g. mixing of fracturing fluid and formation brine). Precipitations of barite and calcite due to the incompatibility of fracturing fluid with formation water was identified to be the main cause of hydraulic fracture plugging, which resulted in fracture conductivity reduction. Based on the fracturing fluid composition and its invasion depth, fracture conductivity can decrease up to 10%. Due to the complex flowback of the fracturing fluid, we observed a time-dependent fracture plugging. Specifically, a moderate plugging of the fracture face occurs early in Marcellus formation causing a reduction in production peak rate while the fracture tip is severely plugged at later times and further reduces the gas production rate.