11 research outputs found
Effectiveness of Colloidal Gas Aphron Fluids Formulated with a Biosurfactant Enhanced by Silica Nanoparticles
At-balance drilling technology applications demand the use of
special drilling fluids, For example, colloidal-gas-aphron fluids (CGA) are being deployed to good effect in drilling
applications. GCA-based drilling fluids have physico-chemical
attributes that enable them to usefully influence and control downhole
conditions. Furthermore, the involvement of nanoparticles and surfactants in
their formulations enhances the performance and stability of CGA suspensions. This
study describes the stability analysis, rheological characterization and
filtration properties of CGA suspensions for the novel eco-friendly
biosurfactant, Olea europaea (common olive), in presence of
nanoparticles. Filtration and stability analysis was performed using API
filtration tests and the static drain-rate technique, respectively. Several
rheological models are developed to quantify the shear-flow characteristics of Olea-nano-based
CGA suspensions. The Herschel-Bulkley and the Mizhari-Berk models provided the
best shear-flow prediction accuracy with very small error values in terms of root
mean squared error. Results reveal that the introduction of the biosurfactant
improves the CGA-based fluid properties. Moreover, the observed improvements
are further enhanced by including silica and fumed silica nanoparticles in the
formulations. The Olea-nano-CGA-based fluids exhibit non-Newtonian behavior. The
rheology of CGA-based fluids depends upon base-fluid viscosity, as it does in
aqueous polymeric foams. The optimum concentrations of nanoparticles in Olea-nano-based
CGA fluids is identified to provide them with fluid-flow indices ranging
between 0.15 and 0.30. </p
Multiphase flow modeling of asphaltene precipitation and deposition
Asphaltene precipitation in reservoirs during production and Enhanced Oil Recovery (EOR) can cause serious problems that lead to reduction of reservoir fluid production. In order to study asphaltene tendency to precipitate and change in flow rate as a function of distance from wellbore, an equation of state (Peng-Robinson) based model namely Nghiem et al.’s model has been employed in this study. The heaviest components of crude oil are separated into two parts: The first portion is considered as non-precipitating component (C31A+) and the second one is considered as precipitating component (C31B+) and the precipitated asphaltene is considered as pure solid. For determination of the acentric factor and critical properties, Lee-Kesler and Twu correlations are employed, respectively. In this study, a multiphase flow (oil, gas and asphaltene) model for an asphaltenic crude oil for which asphaltene is considered as solid particles (precipitated, flocculated and deposited particles), has been developed. Furthermore, effect of asphaltene precipitation on porosity and permeability reduction has been studied. Results of this study indicate that asphaltene tendency to precipitate increases and permeability of porous medium decreases by increasing oil flow rate in under-saturated oil reservoirs and dropping reservoir pressure under bubble point pressure. On the other hand, asphaltene tendency to precipitate decreases with pressure reduction to a level lower than bubble point pressure where asphaltene starts to dissolve back into oil phase. Moreover, it is observed that precipitation zone around the wellbore develops with time as pressure declines to bubble point pressure (production rate increases up). Also, there is an equilibrium area near wellbore region at which reservoir fluid properties such as UAOP (Upper Asphaltene Onset Pressure) and LAOP (Lower Asphaltene Onset Pressure) are constant and independent of the distance from wellbore
Multiphase flow modeling of asphaltene precipitation and deposition
Asphaltene precipitation in reservoirs during production and Enhanced Oil Recovery (EOR) can cause serious problems that lead to reduction of reservoir fluid production. In order to study asphaltene tendency to precipitate and change in flow rate as a function of distance from wellbore, an equation of state (Peng-Robinson) based model namely Nghiem et al.’s model has been employed in this study. The heaviest components of crude oil are separated into two parts: The first portion is considered as non-precipitating component (C31A+) and the second one is considered as precipitating component (C31B+) and the precipitated asphaltene is considered as pure solid. For determination of the acentric factor and critical properties, Lee-Kesler and Twu correlations are employed, respectively. In this study, a multiphase flow (oil, gas and asphaltene) model for an asphaltenic crude oil for which asphaltene is considered as solid particles (precipitated, flocculated and deposited particles), has been developed. Furthermore, effect of asphaltene precipitation on porosity and permeability reduction has been studied. Results of this study indicate that asphaltene tendency to precipitate increases and permeability of porous medium decreases by increasing oil flow rate in under-saturated oil reservoirs and dropping reservoir pressure under bubble point pressure. On the other hand, asphaltene tendency to precipitate decreases with pressure reduction to a level lower than bubble point pressure where asphaltene starts to dissolve back into oil phase. Moreover, it is observed that precipitation zone around the wellbore develops with time as pressure declines to bubble point pressure (production rate increases up). Also, there is an equilibrium area near wellbore region at which reservoir fluid properties such as UAOP (Upper Asphaltene Onset Pressure) and LAOP (Lower Asphaltene Onset Pressure) are constant and independent of the distance from wellbore
Numerical modeling and simulation of drilling cutting transport in horizontal wells
Abstract Cutting transport is an important goal in drilling operation especially in horizontal and deviated wells since it can cause problems such as stuck pipe, circulation loss and high torque and drag. To this end, this article focused on the affecting parameters on the cutting transport by computational fluid dynamic (CFD) modeling and real operational data. The effect of drilling fluid and cutting density on the pressure drop, deposit ratio and string stress on the cutting transport has been investigated. A systematic validation study is presented by comparing the simulation results against published experimental database. The results showed that by increasing two times of drilling fluid density/operational density, cutting precipitation ratio decreased 32.9% and stress applied on the drilling string and pressure drop increased 4.59 and 5.97%, respectively. By increasing two times of drilling cutting density/operational density, cutting precipitation ratio increased 200%. Also, there is an optimum point for drilling cutting density at 8.5 in which stress applied on the drilling string will be minimum