Polymer flooding in very viscous oil has been gaining interest since its efficiency has been field proven. Multiple laboratory investigations have evidenced that the incremental oil recovered by the tertiary process increases considerably the recovery reached thanks to water flooding. However, such tertiary injection is made all the more complex that it is preceded by unstable displacement of oil by water. Therefore a better understanding of the physics is needed, in order to better predict and optimize the viscous oil reserves associated with tertiary polymer flooding. This work presents the interpretation of three similar tertiary polymer flood experiments carried out at the Centre for Integrated Petroleum Research (CIPR, Norway). Each experiment consisted in a water flood followed by a polymer flood. They involved the same Bentheimer outcrop sandstone, 2000 cP oil, 70 cP polymer solution, 2D slab geometry, but different slab lengths (2 slabs are 30cmx30cm, 1 slab is 30cmx90cm). Saturation evolution was monitored by X-ray. On the one hand, provided simple simulation assumptions, the three water floods under study could be history matched (production, pressure). Similar ratios between water and oil relative permeabilities were found, although the water flood relative permeabilities, matched with non Corey-type curves, reflected an important variability. On the other hand, the tertiary polymer floods were found challenging to match consistently. In particular, using classic history matching approaches, the history matching of the long slab experiment could not be reconciled with that of short slab experiments. Simulations were initialized with saturation maps obtained at the end of the water floods. None of the tested approaches enabled us to match consistently the short and long slab experiments together, unless a hysteresis model was implemented. Indeed, a memory effect was observed experimentally from the quantitative analysis of X-ray saturation maps and interpreted as a hysteresis phenomenon. This simple model, with two additional matching parameters, is then further validated by the comparison of 2D simulations with measured in situ saturations.

No abstract

Summary This study presents the mathematical background which justifies a new use of Laplace space in well test analysis. It enables us to perform the whole parameter identification (CD, Skin, k, h, …) in Laplace space, or at least gives us a powerful tool to treat the pressure data in order to recognize powerful tool to treat the pressure data in order to recognize the model to use for the parameter identification in real space. It shows a manner in which the Laplace transform of pressure can be plotted, showing exactly the same behavior as the real pressure function so the plots keep their familiar shape. The pressure function so the plots keep their familiar shape. The coefficients of the dimensionless parameters remain the same too. This enables us to display a new set of characteristic and easily understandable type curves in Laplace space. The mathematical background also sheds light on the use of the Laplace transform to achieve flowrate deconvolution, using modifications of earlier techniques which had been found to be extremely sensitive to noise in the data. Field applictions are presented. The treatments displayed are numerically stable, and it is explained why numerical instability can occur in flowrate deconvolution. The effectiveness of the treatments is explained whenever possible. The Laplace space approach provides an entirely new way of examining and understanding well test results. It has been successfully applied to noisy, simulated data as well as real field data, where a conventional interpretation could not illuminate ambiguities. Introduction Many techniques are available for solving the problem of transient flow of slightly compressible fluids in problem of transient flow of slightly compressible fluids in porous media. One of them is the use of the Laplace transform, porous media. One of them is the use of the Laplace transform, which has many convenient properties (van Everdingen and Hurst, Ref [1]). Since the diffusivity equation is usually simpler in Laplace space than in real space, solutions may be deter. mined for most well configurations, which correspond to different boundary conditions. Recent investigations, particularly those of Ozkan and Raghavan (Ref. [2, 3]), provide extensive libraries of computable solutions to a great variety of well test problems. The analytical solutions are therefore usually better problems. The analytical solutions are therefore usually better known in Laplace space than in real space. In addition to this, evaluating the solution in Laplace space makes it very easy to take into account the double porosity behaviour of a fissured reservoir. Despite all these advantages, the Laplace transform often remains abstruse and somewhat "user-unfriendly", because methods of direct interpretation still rely on the visualization of the solution in real space, in order to recognize the reservoir model. This study investigates a way of presenting the Laplace transform of the transient wellbore pressure which makes it directly interpretable. It allows us to create characteristic type curves, and therefore to perform model recognition in Laplace space. Eventually, the whole parameter identification will be possible in Laplace space, which will reduce the need for possible in Laplace space, which will reduce the need for numerical inverters. This is interesting when the data are not monotonic, when the time consuming algorithm developed by Crump has to be used instead of Stehfest's algorithm.

In the challenging context of heavy to extra heavy oil production, polymer flood technology appears to be a promising solution to enhance ultimate recovery of reservoirs. Several field applications have already shown the efficiency of such technologies, although the final incremental recovery and mechanisms involved are still poorly understood. Indeed, the characteristics of the viscous fingering effects that certainly play a role are rarely captured at the field scale or at the core scale. This work aims at comparing the results of two core experiments with polymer flood in secondary and tertiary mode, in reservoir conditions, in term of recovery as well as in terms of relative permeabilities. In both cases, experiments were carried out on reconstituted reservoir cores, with restored wettability, initially saturated with live oil partially degassed in a PVT cell to the expected pressure and viscosity at the start of the field test. Saturation profiles were measured with X-Ray scans; effluents were collected in test-tubes and analyzed by UV measurements. Additional follow-up with tracers was tested in order to better assess the breakthrough of different fluids as well as the polymer adsorption during the experiment. Although the viscosity ratio was still highly unfavorable, with a polymer bulk viscosity around 70 cP at 10s-1 and an oil viscosity estimated at 5500 cP, polymer floods exhibit an excellent recovery factor.

In a channelized environment, the overbank facies (levees, crevasse-splays) have poorer reservoir qualities than the channel itself. In this type of environment, the geometry of this two-feature complex, together with its permeability contrast, influences the pressure transient response. The pressure behavior of this kind of reservoir has been computed for well-test analysis purposes.Our geometric model comprises a main channel bounded laterally with finite or infinite width levees. It is conceptualized as a composite linear strip reservoir with different mobilities and diffusivities. The length of the whole system also can be either finite or infinite. The solution uses a time-space Laplace transform and a spatial Fourier transform already used by Ambastha, 1 Butler, 2 and Kuchuk. 3 Moreover, our model adds lateral limits by no-flux boundary conditions and longitudinal limits by superposition of image wells or by using a finite Fourier transform.This paper exhibits specific features of the type curves generated for the model. The influence of the levees and of the permeability ratio between channel and levees on the derivative signature is discussed. Hints are given for diagnostic purposes and parameter estimation. Fieldcase buildup analyses show the applicability of the approach.