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Summary It has been long believed that the viscoelasticity of polymer solution improves the displacement efficiency in polymer flood operations, but the individual effect of elasticity has not been clearly distilled for a single viscoelastic polymer. In this study, the effect of elasticity of polymer-based fluids on the microscopic sweep efficiency is investigated by injecting two polymer solutions with similar shear viscosity, but significantly different elastic characteristics. Blends of various grades of polyethylene oxide (PEO) with similar average molecular weight and different molecular weight distribution (MWD) were prepared by dissolving in deionized water. The polymer solutions exhibited identical shear viscosity, but different elasticity. A series of experiments were performed by injecting the polymer solutions through a sandpack saturated with mineral oil. The experiments were performed using a special core holder designed to simulate radial flow. Injection was done through a perforated injection line located at the centre of the cell and fluids were produced through two production lines located at the periphery. The experiments were conducted within a shear rate range of field applications. Because both polymer solutions had similar shear viscosity behaviour, but different elastic properties, it was possible to see the effect of elasticity on the sweep efficiency alone. Results of the polymer flooding experiments indicated that the sweep efficiency of a polymeric fluid could be effectively improved by adjusting the MWD of the solution at constant shear viscosity and polymer concentration. The polymer solution with higher elasticity exhibited considerably higher resistance to flow through porous media than the one with lower elasticity, resulting in higher sweep efficiency and lower residual oil saturation.

Fracture fluid flow back has been identified as one of the major challenges of hydraulic fracturing operations conducted in shale reservoirs. Factors causing the very low fracture fluid recovery need to be well understood and properly addressed, in order to get full benefits from costly hydraulic fracture jobs conducted in unconventional reservoirs. Despite the recent surge of investigations of the problem, one major question still remains: what happens to the fracture fluid that is not recovered? Does it stay in the fracture or does it go into the matrix? In case of both mechanisms are responsible for fracture fluid retainment, what fraction of fracture fluid stays in the propped fracture and what fraction is transferred from fracture to matrix. The focus of the current study is to understand if the transfer of fracture fluid from fracture to matrix through imbibition is of significant importance. We systematically measure the imbibition rate of water, brine, and oil into the actual core samples from the three shale sections of Horn River basin (i.e., Fort Simpson, Muskwa and Otter Park). We characterize the shale samples by measuring, porosity, wettability, mineral composition through XRD analysis, and interpreting the well log data. The results show that imbibition could be a viable mechanism for fluid transfer from fracture to matrix in Horn River shales. The comparative study shows the imbibition rate in the direction parallel to the bedding plane is higher than that in the direction perpendicular to the bedding. The study also suggests that the imbibition rate of the aqueous phases is significantly higher than that of the oleic phases.

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The viscoelasticity of polymers is known to contribute significantly toward improved displacement efficiency in polymer flood operations. But the contribution of elasticity of viscoelastic polymers in enhanced oil recovery (EOR) still remains largely unexplored. The majority of literature available on polymer-aided EOR, in general, talks about the role played by viscoelasticity of polymers on improved oil recovery with little or no mention of the individual contribution of the elasticity of polymers on EOR. In this work, partially hydrolyzed polyacrylamide (HPAM) solutions, having identical shear viscosity but different elasticity, were flooded to investigate the individual effect of elasticity on improved oil recovery. A transparent, sand packed visual cell, initially saturated with mineral oil, was used for flooding with four different HPAM solutions. Because these polymer solutions differed only in terms of elasticity, a comparative study of the effect of elasticity on sweep efficiency was done. Images taken at regular intervals during the course of flooding were analyzed to study the frontal displacement patterns changing with the elasticity of different HPAM solutions. The mechanism of viscous fingering in immiscible two-phase flow in porous media at different polymer elasticity values was studied. Results from flooding experiments indicate that polymer solutions with higher elasticity not only yield higher oil recovery, but also require less polymer to produce a given amount of oil. These results were further bolstered by the visual analysis. HPAM solutions with lower elasticity showed a high degree of fingering, whereas solutions with higher elasticity produced more stable displacement fronts. Improved microscopic sweep efficiency, due to the greater flow resistance offered by polymer solution with higher elasticity, was visually confirmed.

Colloidal gas aphrons (CGA) have the unique ability to form a bridge in the pores of reservoirs, which stops fluid invasion. Sizing microbubbles in accordance with the rock pore size distribution is imperative for effective sealing during drilling. The effects of time, temperature and pressure on the stability and size of the microbubbles needs to be better understood in order to design a fluid that will sufficiently block the pores of the formation for extended periods. In this study, the effects of time, pressure and temperature on the size of microbubbles and the stability of microbubble (CGA)-based drilling fluids were investigated. The change in the CGA diameter with time was determined by using a microscopic imaging technique. Effects of base fluid viscosity and surfactant concentration on the size and stability of the microbubbles were also investigated. Introduction CGA-based drilling fluids have been successfully used in high-angle and horizontal well drilling in highly depleted reservoirs(1). Microbubbles in CGA-based drilling fluids form a bridge in front of the pores of the rock. This bridge is believed to stabilize the rock while sustaining minimal damage to the formation. Stability of the microbubbles and how bubble size changes as a function of downhole conditions (i.e. temperature and pressure) are some of the major concerns associated with the application of CGA-based drilling fluids. A stable CGA structure requires maintaining an ideal film wall thickness of 4 to 10 microns(2). Another factor affecting CGA stability is the rate of transfer of the surfactant molecules between the viscous water shell and the bulk phase due to gravity drainage or temperature gradients. This leads to a surface tension gradient at the surface of the shell. As a result, the Marangoni Effect will counteract this deformation(3–4). Increasing the viscosity of the shell can help to minimize the transfer of surfactant molecules. Usually a biopolymer is added to adjust the shell viscosity(3). The third property that the CGA structure must have is low diffusivity, which is the ability of the air that is in the core to transfer to the aqueous shell. CGA bubble size and stability have been the subject of earlier studies(5–12). Longe(6) analyzed the bubble size distribution of CGAs for soil and groundwater decontamination applications. Longe's analyses included effects of surfactant concentration, surfactant type and electrolytes on the stability of the CGAs over the time. Jauregi et al.(7) also investigated the stability of CGAs as a function of surfactant concentration. Results from both studies indicated that the stability of CGAs increase with increasing surfactant concentration. Chaphalkar et al.(8) measured the size distribution of CGAs using a particle size analyzer. The CGAs were virtually non-existent after 20 minutes for three different types of surfactant. Roy et al.(9) reported similar results. Amiri and Woodburn(10) studied the rate of drainage, as well as the CGA bubble size, by recording the images of the CGAs over time. They reported that after 10 minutes, the bubble shape had changed from spheres to polyhedral structures.

Colloidal gas aphron-based drilling fluids are designed to minimize formation damage by blocking the pores of the rock with microbubbles, which can later be removed easily when the well is open for production. Sizing colloidal gas aphron (CGA) bubbles in accordance with the rock pore size distribution is essential for effective sealing of the pores during drilling. The physical properties (i.e. viscosity, density, fluid loss, etc.) of the CGA-based drilling fluids also need to be understood in order to use these fluids more effectively. In this study, the physical properties of colloidal gas aphron-based drilling fluids are investigated. The results of rheology, API filtration loss and density measurement tests using various CGA-based drilling fluid formulations are presented. The effects of polymer and surfactant concentration, surfactant type, shear rate, mixing time and water quality on the CGA bubble size have been studied. Results of CGA bubble size characterization experiments are also reported. Introduction Colloidal gas aphron-based drilling fluids have recently been used for drilling at-balance in an attempt to eliminate the problems associated with overbalanced and underbalanced drilling. In order to achieve an at-balance drilling situation, the fluid pressure must be maintained at a level greater than the formation pressure, but the difference should be kept at a minimum level to avoid invasion of the fluid into the formation(1). Colloidal gas aphron drilling fluid simulates such a situation by building a bridge in front of the pores of the rock. It is believed that this bridge stabilizes the rock while allowing minimal damage to the formation. This system has been successfully implemented in high-angle and horizontal well drilling in highly depleted reservoirs(2), as well as with vertical wells. Simply put, aphrons are bubbles, approximately 10 to 100 microns in diameter. The term colloidal gas aphrons was first used by Sebba(3). Like regular foams, aphrons are typically composed of a gaseous (colloidal gas aphrons) or liquid (polyaphron) core. Unlike foams, however, aphrons have a thin aqueous protective shell. Aphron stability is determined by the rate of mass transfer between the viscous water shell and the bulk phase. This transfer is known as the Marangoni effect(3–5). If the mass transfer rate is high, aphrons will be unstable. Therefore, the shell fluid is designed to have certain viscosity to minimize the Marangoni effect. The shell is composed of an inner layer and an outer layer. Figure 1 illustrates a typical aphron. The inner layer consists of surfactant molecules which supports and separates the air core from the viscous layer. The outer layer, which also supports the viscous layer, is hydrophobic outwards and hydrophilic inwards. Since this bubble is in contact with the bulk water, it is believed that there is another layer in which the surfactant molecules are hydrophobic inwards and hydrophilic outwards. This indicates that there is a region in between the aphron outer shell and the bulk phase layer where a hydrophobic globule will be comfortable and, therefore, oil can adhere to the gas aphron(3).

It has been long believed that the viscoelasticity of polymer solution improves the displacement efficiency in polymer flood operations, but the individual effect of elasticity has not been distilled for a single viscoelastic polymer. In this study, the effect of elasticity of polymer-based fluids on the sweep efficiency is investigated by injecting two polymer solutions with similar shear viscosity but significantly different elastic characteristics. Blends of various grades of polyethylene oxide (PEO) with similar average molecular weight and different molecular weight distribution (MWD) were prepared by dissolving in deionized water. The polymer solutions exhibited identical shear viscosity but different elasticity. A series of experiments were performed by injecting the polymer solutions in a special core holder designed to simulate radial flow through a sandpack, which was saturated with mineral oil. Injection was done through a perforated injection line located at the center of the cell and fluids were produced through two production lines located at the periphery. The experiments were conducted within a shear rate range of field applications. Since both polymer solutions had similar viscosity behavior but different elastic properties, it was possible to see the effect of elasticity on the displacement efficiency alone. Results of the polymer flooding experiments indicated that the sweep efficiency of a polymeric fluid could be effectively improved by adjusting the MWD of polymer solution at constant shear viscosity and concentration of the polymer. The polymer solution with higher elasticity exhibited considerably higher resistance to flow through porous media than the solution with lower elasticity resulting into higher displacement efficiency and lower residual oil saturation.