Interfacial assemblies of nanoparticles can stabilize liquid−liquid interfaces. Due to the interactions between functional groups on nanoparticles dispersed in one liquid and polymers having complementary end-functionality dissolved in a second immiscible fluid, the anchoring of a well-defined number of polymer chains onto the nanoparticles leads to the formation of NP−surfactants that assemble at the interface and reduce the interfacial energy. We have developed droplet interfaces covered with elastic, responsive monolayers of NP−surfactants. Due to the presence of an elastic layer at the interface, the droplets offer a greater resistance to coalescence and can prevent the exchange of materials across interfaces. Our results show the successful encapsulation of nanoparticles, dyes, and proteins with diameters in the 2.4−30 nm range. Further, we show that stable water-in-oil droplets can be generated for various combinations of polymer ligands and nanoparticles bearing complementary functionalities. These NP−surfactant-stabilized microfluidic emulsions would enable applications requiring liquid−liquid interfaces that can adapt and respond to external stimuli and whose mechanical properties can be easily tailored.

Accurate determination of polymer properties in porous media Is an Important Input requirement of the reservoir simulation of polymer EaR. Data pertaining to In-situ viscosity and polymer retention are essential parameters which will govern the performance and economics of the application. At reservoir conditions, the acqUisition of relevant and precise data Is not a straight forward process, but one where extremely careful and reproducible corefloodlng experiments are required. We address the question of coreflood procedures best suited to evaluate polysaccharide polymers for field application.

Summary This paper addresses polymer-solution injectivity and what physico-chemicalenvironments result in formation damage. The roles physico-chemicalenvironments result in formation damage. The roles of Fe(III) and filtrationare shown to be particularly important. The effects in the field are predicted, with special reference to wellbores likely to suffer from thermal fracturing. It is shown that fractured wellbores are unlikely to suffer from injectivityproblems Introduction Aqueous polymer solutions can be used in waterflood operations to assist inconformance control. If the oil phase is viscous, the viscosity of the aqueousphase can be increased by the addition of polymer. In this mobility-controlapplication, the viscosity polymer. In this mobility-control application, theviscosity matching decreases the tendency of the aqueous phase to fingerthrough and to bypass the oil phase within the porous matrix. If the reservoiris layered with high-permeability streaks, polymer injection can assist inprofile control. The polymer solution preferentially enters thehigh-permeability layers. Subsequent water injection will be diverted aroundthe slow-moving polymer slug into the lowerpermeability layers, resulting ingreater sweep efficiency. One perceived problem associated with large-scale polymer applications inthe field is a potential decrease in injectivity cause by formation damage bythe polymer solution. Injectivity impairment can be caused by problemsassociated with polymer-solution properties, reservoir matrix properties, andsurface mixing and properties, reservoir matrix properties, and surface mixingand wellbore properties. The properties essential for good injectivity havebeen reasonably well documented. The polymer solution must be stable with notendency to form separate phases in the reservoir brine at reservoirconditions, and the hydrodynamic size of the polymer molecule must not exceedthe pore-throat size associated with polymer molecule must not exceed thepore-throat size associated with the porous medium. Injectivity is a function of permeability and adsorption, particularlyadsorption onto clay material. Thus, low-permeability particularly adsorptiononto clay material. Thus, low-permeability (less than 0. 1 um) andhigh-clay-content reservoirs require careful laboratory screening. Surfacemixing techniques must thoroughly dissolve/disperse polymers into the injectionbrine without degrading the molecules. No solid or gel material should remainafter mixing, and FE(III) contamination should be avoided. Quantitative evaluation of the formation damage likely to be caused bypolymer-solution injection over the lifetime of a polymer EOR project isdesirable. One study to characterize wellbore polymer EOR project is desirable. One study to characterize wellbore plugging I obtained important results. Thefive factors found to plugging I obtained important results. The five factorsfound to influence polymer plugging were volume injected per cross section ofarea (cumulative flux), core permeability, hydrodynamic size of the polymer, core mineralogy, and surface state. Of crucial importance for reservoir simulation studies is the role ofcumulative flux of polymer injected-i.e., the volume of polymer solutioninjected per unit area of face. Ref. 1 focused on the polymer solution injectedper unit area of face. Ref. 1 focused on the polyacrylamide polymer Cyanatrol950. In our study, we polyacrylamide polymer Cyanatrol 950. In our study, weinvestigate the role of the cumulative flux of polymer injection further in aseries of physics-chemical environments with the biopolymer Flocon 4800MXC(Pfizer). The effects of polymer filtration and brine salinity/hardness on bothcore-plug face and in-depth blocking were investigated with experiments at highcumulative flux. The effect of trace FE(III) concentrations on injectivity alsowas investigated, and blocking effects were found to be different from effectsassociated with nonfiltration of the polymer. A nonmetallic, multiportpressure-measurement coreflood rig was constructed to control FE(IU) levelsprecisely. The presence of gel material, such as that formed by trivalent ioncrosslinkers, is known to influence the injectivity of polymer solutions in thefield. To enable quantitative prediction of polymer injectivity in the field, thelaboratory results must function as input data for a reservoir simulator. Inthis study, a simulation model relevant to deep reservoirs was used mconjunction with the obtained laboratory data. It has now become widelyaccepted that most water-injection wells in deep reservoirs are fractured as aresult of cooling by the injected water. Fracturing can occur when thebottomhole fluid pressure exceeds the compressive stress in the surroundingrock. pressure exceeds the compressive stress in the surrounding rock. Injectors are operated at pressures below the initial rock stress, but coolingcauses the rock to contract and reduces the stress around the well by up to 0.2MPa for each 1 deg. C change in temperature. In deep reservoirs (below 2000 m), where the formation temperature exceeds the surface temperature by more than 50deg. C, the thermal stress reduction wig almost always lead to fracturing. Atthese depths, the fracture will occur in a vertical plane parallel to thedirection of maximum principal horizontal stress, as shown in Fig.1. It iscommon for fractures to have heights that are less than the formationthickness; fracture length may vary from a few to hundreds of meters, dependingon reservoir conditions. Where thermal fractures exist, they are the dominant -influence oninjectivity. They may be detected, for example, by distinctive behaviorpatterns during well testing. Fracturing significantly increases injectivity, and the effect of fracturing is particularly important when the injected waterhas a high solids content. When water containing solids is injected, a nonfractured wellbore rapidlybecomes plugged and its injectivity is impaired. A fracture, by contrast, has amuch larger surface area, which causes the plugging solids to spread morethinly. Also, the fracture tends to plugging solids to spread more thinly. Also, the fracture tends to grow in response to any rise in injection pressurecaused by plugging. This exposes fresh surface and compensates for the skinplugging. This exposes fresh surface and compensates for the skin damage. Historically, it has proved possible to inject very large volumes of dirtywater successfully into fractured wells. The fracture also will control the injectivity when polymer is injected intoa fractured well. The fracture will respond both to the polymer-solutionviscosity and to any face plugging by polymer polymer-solution viscosity and toany face plugging by polymer that may occur. In this paper, we investigate howa fractured injector would be affected by polymer face plugging both at thelevels measured in our own corefloods and at levels reported by others. Experimental Coreflood Rig Construction. A coreflood rig was constructed that enabledseveral continuous differential-pressure measurements to be taken along thelength of a 2-m core. All wetted parts of the rig were nonmetallic. The corewas inserted into a nitrile rubber sleeve with taps at various positions. Nylonfittings were used to connect the differential-pressure transducers to thetaps. @ end pieces were butted against the core ends and the core was placedpieces were butted against the core ends and the core was placed in apermeameter so that an overburden pressure could be applied. The permeameterwas placed in a controlled water bath to mamtain a constant temperature of 20deg. C. The inlet was connected to a titanium piston displacement vessel containingthe polymer by a Pharmacia P500 pump, and the outlet was run to a backpressurevalve. All valves used on the rig had PTFE wetted parts. PTFE wetted parts. SPERE P. 237

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