Salym Petroleum Development (SPD) has embarked on an ambitious Oil Field Management Improvement Program with as key objectives to:• Optimise Production (2.5% additional production through reduction of Locked-in-Potential and better reservoir pressure maintenance; unscheduled deferment less than 1% through reduction of ESP trips).• Increase Ultimate Recovery (Increase RF by 1%; platform for future EOR project; robust basis for infill drilling).• Reduce OPEX (increase ESP mean time between failure; contain chemical consumption costs; in field staff journies reduced by 10% /annum; less than 3 non-critical loss of integrity incidents per year).

Salym Petroleum Development (SPD) has embarked on an ambitious Oil Field Management Improvement Program with as key objectives to:• Optimise Production (2.5% additional production through reduction of Locked-in-Potential and better reservoir pressure maintenance; unscheduled deferment less than 1% through reduction of ESP trips).• Increase Ultimate Recovery (Increase RF by 1%; platform for future EOR project; robust basis for infill drilling).• Reduce OPEX (increase ESP mean time between failure; contain chemical consumption costs; in field staff journies reduced by 10% /annum; less than 3 non-critical loss of integrity incidents per year).

IntroductionThe degree of success of small-volume, miscible nearwellbore treatments, such as chemical sandconsolidation systems, depends critically on the efficient placement of the chemicals. 1 In the case of sand consolidation, (1) failure to treat all the perforations, (2) contamination, or (3) dilution of the chemicals (which leads to a low-strength consolidation) will result in a continuation of sand production. 2 The final distribution of the injected fluids in the formation is a function of many complex processes occurring during placement: mixing in the injection tubing, stability of displacement, gravity-induced movement of the fluids, etc.In recent years significant effort has been directed to the study of fluid displacement (miscible and immiscible) in porous media. Stability criteria for the displacement of one fluid by another have been established,3-6 and the problem of viscous fingering-an unstable displacement resulting from a less viscous fluid displacing a more viscous fluid-has received much attention. 7-9 Thus the stability of the displacement process is controlled by fluid mobility ratio, fluid density differences, formation porosity and permeability, and the fluid injection rate. The theory and laboratory evidence is well-documented for the linear low-rate flow associated with reservoir engineering studies. However, less attention has been given to the same displacement phenomena that occur in the near-wellbore region during small-volume chemical treatments (sand consolidation, acidization, selective plugging, etc.). Attention has been drawn to the need for more consideration of placement profiles in these operations.1O Experimental and theoretical studies 10,11 have shown that gravity segregation between fluids of different densities in the well is an important factor affecting injection profiles. The experiments described in this paper examined the effect of fluid viscosity contrast and injection rates on the placement profile of the injected fluid in the near-wellbore region of the formation. These investigations were performed in both full-and reduced-scale models and although they were carried out mainly with sandconsolidation chemicals the results may be applied to other miscible, near-wellbore treatments.The work consisted of four distinct studies: (1) experiments at low injection rates to study the stability of the displacement and simulate the phenomena occurring in the near-wellbore region during injection, (2) a study of the rate of movement of fluids in the formation under

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