Songyan Li

Properties of multi-phase foam and its flow behavior in porous media

Aqueous foams were produced with partially hydrophobic SiO2 nanoparticles and sodium dodecyl sulfate (SDS) dispersions. The injection behavior of SiO2 stabilized foam (SiO2/SDS foam) was analyzed and compared with SDS stabilized foam (SDS foam). The experimental results showed that the SiO2 nanoparticles and SDS surfactants had a synergistic effect on foam stability at proper SDS concentration. And the effect was accompanied with a slight decrease in foam volume. The adsorption of nanoparticles on the bubble surface was confirmed by laser-induced confocal fluorescence microscopy. And the effect of absorbed nanoparticles on bubble surface viscoelasticity was also verified by the interfacial dilational rheological measurement. The dilational viscoelasticity increased with increasing SiO2 concentration, corresponding to foam stability. The plugging flow experiment demonstrated that the maximum differential pressure in SiO2/SDS foam flooding was 1.9 MPa, much higher than that in SDS foam flooding. The SiO2/SDS foam had better diversion properties and resistance to water flushing than SDS foam. In the oil displacement experiments, SiO2/SDS foam could reduce the residual oil saturation noticeably. The enhanced oil recovery and the final oil recovery could reach to 41.2% and 75.7%, respectively. It was deduced that the enhanced foam stability and dilational viscoelasticity were the main reasons for the effective performance in porous media.

Modeling of Sand Cleanout With Foam Fluid for Vertical Well

SummaryFoam has proved to be effective and economical in underbalanced operations and is gaining wider applications in many areas. Foam fluid has low density and high blocking ability. It can effectively reduce leaking of fluid into formation in low-pressure wells, protect-ing the oil formation and improving sand-cleanout efficiency. Accord-ing to energy-conservation equations, mass-conservation equations, and momentum-conservation equations, a mathematical model for sand cleanout with foam fluid was established that considers the heat transfer between foam in the annulus and foam in the tubing. The model was solved by numerical method. Distributions of foam temperature, foam density, foam quality, pressure, and foam velocity in the wellbore were obtained. Calculation results show that tempera-ture distribution is affected greatly by thermal gradient. As the well depth increases, foam pressure and foam density increase and foam quality and velocity decrease. Foam velocity at the well bottomhole is the minimum. Friction pressure loss of foam is less than that of water at the same volume flow rate. Site applications show that sand cleanout with foam fluid can prevent fluid leakage effectively. It can avoid damage of sealing agents and reduce pollution. The average relative error and standard deviation between model and field data on injection pressure are −0.43 and 2.55%, respectively, which proves the validation of the mathematical model.IntroductionCuttings, sands, or fines left in the wellbore can have a nega-tive effect on well completion and production because of flow restriction to the produced gas and oil. Hence, sand cleanout has been a standard practice in oilfield operations. Several techniques (Heinrichs and Dedora 1995), such as dual string system, pump to surface bailing, and coiled tubing with jetting, have been developed over the past decades. One of the most common cleanout opera-tions is running in with coiled tubing and circulating out the fills with carrying fluids. Because produced fluid usually is more than injected fluid, the bottomhole pressure (BHP) of many oil wells is very low. Therefore, sand cleanout using water or brine has only limited application because of leaking. Stable foams have been used as circulating fluids in drilling and workover operations since the late 1960s. Successful applications have been well documented in foam drilling operations (Hall and Roberts 1984; Fraser and Moore 1987; Falk and McDonald 1995; Lage et al. 1996). Research has been done on the behavior of stable foams (Doane et al. 1996; Meng et al. 1996; Negrao and Lage 1997; Nakagawa et al. 1999). Recently, stable foams have been used for underbalanced drilling both in vertical and in inclined holes. In many cases, drilling with foam has shown to provide significant benefits, including increased productivity (by reducing formation damage), increased drilling rate, reduced operational difficulties associated with drilling in low-pressure reservoirs (e.g., lost circulation and differentially stuck pipe), and improved formation evaluation while drilling.Foam generally is formed by mixing a gas phase with a liquid phase, which is either water (stable foam) or aqueous polymer solution (stiff foam) containing from 0.5 to 1% by volume foam-ing agent. The foaming agent usually is surfactant that can reduce surface tension between gas and liquid. The major advantage of foam is its flexibility in controlling the density in wellbore, which influences the BHP strongly. Characteristically, the foam viscosity is much greater than that of the liquid and gas phases. High viscos-ity can improve cuttings transport and sand-carrying ability. Usu-ally, foam flow in the wellbore keeps laminar flow, which results in lower pressure losses. Foam also has the ability to temporarily block a high-permeability layer, which can reduce fluid leaking into the oil formation.Because foam is a compressible fluid, special care needs to be taken in hydraulics calculations. This is mainly because of (1) inadequate foam rheology models and (2) influence of frictional and hydrostatic pressure components through the pressure-depend-ent fluid density. A number of rheology models have been developed for foam hydraulics calculations in the past 3 decades. These models include those by Beyer et al. (1972), Blauer et al. (1974), Sanghani (1982), and Phillips et al. (1987). Ozbayoglu et al. (2000) conducted a com-parative study of these models. They also measured foam pressure drops across a 90-ft horizontal pipe. On the basis of the comparison of experimental data and the results of the models, they concluded that there is no best model for predicting the pressure losses during foam flow in pipes under the experimental conditions. Models that may predict pressure losses closer to actual values in one case may not be suitable for another condition. Their experimental data indi-cate that foam rheology can be characterized better by the power-law model for 0.70 and 0.80 foam qualities, whereas the Bingham plastic model gives a better fit for 0.90 foam quality. Guo et al. (1995) presented a trial-and-error method to couple the frictional and hydrostatic pressure components through the pressure-dependent fluid density. Their technique gives results similar to that given by the computer models of Anderson (1984) and Okpobiri and Ikoku (1986). Both steady-state-flow and tran-sient-flow simulators are available in the drilling industry for foam drilling hydraulics calculations. During sand-cleanout operations using foam fluid, predicting such parameters as BHP, foam flow velocity, foam density, and foam quality in wellbore is a major challenge. Unlike incompress-ible fluids, foam is a compressible, high-viscosity, non-Newtonian fluid. Temperature, pressure, foam quality, foam density, flow velocity, and rheological parameters vary along the wellbore; in addition, frictional pressure gradient, hydrostatic pressure gradi-ent, and acceleration pressure gradient are coupled. This becomes more complex when polymer is added to the liquid phase (Chen et al. 2009). Unfortunately, the results from these simulators are frequently conflicting (Griffin and Lyons 1999; Nakagawa et al. 1999) because of assumptions that were made in mathematical formula-tions and rheological modeling. Many factors, such as operation conditions (flow rate, flow regime penetration rate), well configu-ration (deviation angle, hole size, pipe size, structure), foam fluid properties (rheology, friction, density, fluid loss), and the proper-ties of carried particles (shape, size and size distribution, density) can affect wellbore-cleanout efficiency.In order to improve the accuracy of pressure predictions in foam cleanout, we have developed a closed mathematical model to fully couple the temperature, frictional, and hydrostatic pressure compo-nents in this study. The newly developed model, together with the rheological model, was validated to design proper volumetric flow rates of gas and liquid phases, injection pressure of the wellhead, and foam temperature and density in the wellbore.

Exploring the effects of four important factors on oil–CO2 interfacial properties and miscibility in nanopores

In this paper, a modified Peng–Robinson equation of state (PR-EOS) coupled with the parachor model and a newly-developed diminishing interface method (DIM) are applied to predict the interfacial properties and minimum miscibility pressures (MMPs) of light oil–CO2 systems in nanopores. First, the modified PR-EOS is used to calculate the vapour–liquid equilibrium by considering the effects of capillary pressure and shifts of critical temperature and pressure. Second, a thermodynamic formula of the interfacial thickness (IT) between two mutually soluble phases is derived, based on which the novel DIM is developed. The MMP is determined by extrapolating the derivative of the IT with respect to the pressure (∂δ/∂P)T to zero. It is found that at the pore radius of 10 nm, all three quantities, the interfacial tensions (IFTs), ITs, and MMPs, show obvious increases with temperature. The effects of the initial oil composition on the three quantities are measurable but marginal and the MMP is more sensitive to the initial oil composition at a higher temperature. Moreover, the IFTs and ITs are weakly dependent but the determined MMPs are strongly dependent on the injection gas composition. The presence of CH4 in the injection gas results in a substantial MMP increase in nanopores. At a constant temperature, the effects of the feed ratio of injection gas to oil on the IFTs, ITs, and MMPs are negligible with pure CO2 injection, especially at low feed gas–oil ratios (less than 0.50 : 0.50 in mole fraction), whereas they become much stronger and cause the MMPs with impure CO2 (0.65CO2 + 0.35CH4) injection to be considerably increased from 26.3 to 40.0 MPa by reducing the feed gas–oil ratio from 0.90 : 0.10 to 0.10 : 0.90 in mole fraction.

Surface wettability of oxygen plasma treated porous silicon

Oxygen plasma treatment on porous silicon (p-Si) surfaces was studied as a practical and effective means to modify wetting properties of as-fabricated p-Si surfaces, that is, contact angles of the p-Si materials. P-Si samples spanning a wide range of surface nanostructures have been fabricated which were subjected to a series of oxygen plasma treatments. Reduction of the p-Si surface contact angles has been systematically observed, and the surface activation rate constant as a function of different pore geometries has been analyzed to achieve an empirical equation. The underlying diffusion mechanisms have been discussed by taking into account of different pore diameters of p-Si samples. It is envisaged that such an approach as well as the corresponding empirical equation may be used to provide relevant process guidance in order to achieve precise control of p-Si contact angles, which is essential for many p-Si applications especially in biosensor areas.

Behaviors of Foamy Oil Flow in Solution Gas Drive at Different Temperatures

The role of foamy oil flow in the cold production of heavy oil in a solution gas drive has been extensively studied in recent years. In this study, solution gas drive tests were performed in micromodels and sandpacks to investigate not only the behaviors of foamy oil flow at different temperatures but also the effect of temperature on displacement efficiency. The micromodel tests indicated that three flow states existed with the solution gas drives at 54.0 and

Factors Affecting the Productivity of a Multifractured Horizontal Well

100.0\,^{\circ }\hbox {C}

Transportation technology with pour point depressant and wax deposition in a crude oil pipeline

100.0∘C, which were an oil phase flow, a foamy oil flow and an oil–gas two-phase flow. The micromodel test at