Modeling Polymer Flooding with Crossflow in Layered Reservoirs Considering Viscous Fingering

Abstract

Polymer flooding has been commercially applied to a number of viscous oil fields in the past decade and gradually gained more popularity. Due to limited injectivity in viscous-oil reservoirs, a relatively low polymer viscosity is usually used to avoid excessive injection pressure. In such a case, mobility ratio of polymer solution to oil is much greater than one, which implies unstable flow and strong viscous fingering. Existing reservoir simulators lack the capability of modeling such a physical phenomenon. Since many viscous-oil reservoirs have high permeability contrast between layers, we are motivated to study, for the first time, the impact of crossflow between different layers considering the presence of viscous fingering. Numerical modeling polymer floods with crossflow in a layered viscous-oil reservoir is difficult due to two major challenges: first is how to correctly allocate flow rates from the wellbore to multiple layers; and second is how to capture the viscous fingering effect without using excessively fine grids. To address the first issue, we developed an implicit well-rate-allocation model based on the potential method, which fully couples all the wellbore segments of each well with reservoir gridblocks to ensure a physical wellbore pressure. To deal with the second challenge, we implemented the effective fingering model, which is an upscaling model that lumps all the viscous fingers in a coarse grid block into one fictitious finger to allow for accurate estimation of fingering strength and growth during unstable flows. Both models were validated individually against the analytical solution or experimental data. The integrative module including the two new capabilities was used to simulate a polymer flood following a waterflood in a layer-cake reservoir in North America with moderate oil viscosity. We observed the fast propagation of water fronts and small fingering fraction in high permeability layers during the waterflooding phase, indicating active channeling and viscous fingering. The subsequent polymer flooding minimized both factors of oil bypassing and led to stable flow and high sweep efficiency. Without the implicit well-rate-allocation model, crossflow was overestimated and wellbore pressures of different well blocks were not consistent. Without the effective-fingering model, oil recovery was overestimated due to the lack of accounting for viscous fingering. The simulation results indicated that polymer flooding improved both displacement and sweep efficiencies. The model has shown comprehensive capabilities in reservoir simulations of polymer floods including unstable floods and crossflows between layers. This is a major significance to optimization of non-thermal viscous-oil EOR projects and also making more informed operational decisions for field developments.

Semi-Analytical Solution of Chemical Flooding in Heterogeneous Non-Communicating Layers with a Focus on Low Salinity Water Flooding

“…While the other authors considered adsorption as a potential retarding process, dispersion has different effects which are harder to account for. This work shows clearly the effect of interaction of factors that affect fluid movement, such as heterogeneity, fluid mobility, retardation effects that induced by adsorption, desorption, dispersion and diffusion hence predicting sweeping performance and invaded zone in each layer, where the need of such work is observed (Lake et al 2014;Luo et al 2017).…”

An Injectivity Evaluation Model of Polymer Flooding in Offshore Multilayer Reservoir

“…q(t) is the injection rate, m 3 /s; k is the absolute permeability,10 −3 µm 2 ; h is the net pay thickness, m; f w is the second derivative of the water-oil fractional flow curve, dimensionless; µ w is the water viscosity, mPa•s; µ o is the oil viscosity, mPa•s; k rw is the water-phase relative permeability, dimensionless; k rw is the oil-phase relative permeability, dimensionless; S wf is the frontal saturation of the oil-water two-phase flow region, dimensionless; S wm is the maximum water saturation at the injection well bottom, dimensionless; S wc is the irreducible water saturation, dimensionless; r w is the bottom hole radius, m; r w 1 is the distance between the injection well bottom and the water zone front, m; r w 2 is the distance between the injection well bottom and the water-oil two-phase zone front, m; r d is the distance between the injector and producer, m; and m is the ratio of producers to injectors in the well pattern. By combining Equations (22), (23), (24), and (25), the total pressure difference between injector and producer before water breakthrough is:…”

“…He also pointed out that in a layered reservoir, injecting polymer solutions enforced cross flow between layers with different properties, which accelerated the oil displacement in low-permeability layers. Luo [24] developed an implicit well-rate allocation model to accurately allocate the injection rate into different layers with contrasting permeabilities. Lu [25] defined several flow regions with unique saturation profiles during polymer flooding, and then established a semi-analytical model for predicting multilayer injection capacity.…”

CFD study of the water production in mature heavy oil fields with horizontal wells

“…On the contrary, several studies have overcome this issue by implementing new mathematical models to scale up and consider the influence of VF. For example, Luo et al [ 25 – 27 ] implemented the Effective Fingering Model, capable of considering VF effects in heavy oil displacements driven by water flooding and polymer flooding. The model developed by Luo et al showed that these simulators could consider the effects of VF, having quantitative fair agreement compared to experimental and field data.…”