Binfei Li

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.

Wall slipping behavior of foam with nanoparticle-armored bubbles and its flow resistance factor in cracks

In this work, wall slipping behavior of foam with nanoparticle-armored bubbles was first studied in a capillary tube and the novel multiphase foam was characterized by a slipping law. A crack model with a cuboid geometry was then used to compare with the foam slipping results from the capillary tube and also to evaluate the flow resistance factor of the foam. The results showed that the slipping friction force FFR in the capillary tube significantly increased by addition of modified SiO2 nanoparticles, and an appropriate power law exponents by fitting FFR vs. Capillary number, Ca, was 1/2. The modified nanoparticles at the surface were bridged together and formed a dense particle “armor” surrounding the bubble, and the interconnected structures of the “armor” with strong steric integrity made the surface solid-like, which was in agreement with the slip regime associated with rigid surface. Moreover, as confirmed by 3D microscopy, the roughness of the bubble surface increased with nanoparticle concentration, which in turn increased the slipping friction force. Compared with pure SDBS foam, SDBS/SiO2 foam shows excellent stability and high flow resistance in visual crack. The resistance factor of SiO2/SDBS foam increased as the wall surface roughness increased in core cracks.

Experimental Study on Rheological Properties of Thinkened Co2 in Liquid and Supercritical State

Abstract The rheology of CO2 fracturing fluid are complicated because of its phase change. In this work, pipeline rheology of CO2 in a range of 8–16 MPa and 10–60 °C were studied. The results showed that the thickened CO2 was characterized by a power-law fluid. With the thickener or pressure increased, the consistency coefficient K increased and the flow index n decreased. In the liquid or supercritical state, temperature increasing made the K decrease and the n increase. However, when CO2 transformed from the liquid to the supercritical state in 30–40 °C, and the K increased while the n decreased.

Experimental Study of the Effect of Permeability on Foam Diversion

Abstract Through single-core and dual-core experiments, relations of pressure, liquid flow rate of outlet, and gas-phase saturation to injection fluid volume were researched. Effect of permeability on foam diversion was analyzed. Experiments indicate that gas saturation increases and then decreases with core permeability at the same PV during subsequent liquid injection for single-core experiment. When the permeability ratio is less than 11, liquid flow rate ratio is less than 1. When permeability ratio lies in the range of 11 to 14.9, liquid flow rate ratio is greater than 1, and foam diversion is declining. The best diversion is observed at a permeability ratio of 4.0. The effect of permeability on foam diversion is that capillary pressure is greater in the low-permeability core, and bubbles in foam break easily, which causes cross flow of gas phase.