Abstract

Several different scenario of injected and reservoir water mixing have been proposed: mixing at high velocity near to injectors, mixing at low velocity inside reservoirs, mixing by diffusion via boundaries of layers with different permeabilities, mixing of injected, connate and aquifer waters at high velocity near to producers. Just the latter mechanism results in the accumulation of formation damage, while other mechanisms cause precipitation near to moving concentration front. In the current paper a new mechanism of oilfield scaling by diffusion of Barium from impermeable layer into the reservoir is proposed. The mechanism results in accumulation of precipitant and of formation damage.

Viscous dominant regime of waterflooding takes place in the majority of oil fields. The Welge s method allows calculating the permeability distribution from water cut history. The proposed extension to Welge s method determines the partition of permeable layers in a reservoir from tracer concentration in production wells. Knowledge of this partition is important for modelling of oilfield scaling accounting for Barium supply from impermeable layers.

Introduction

Scaling is a chronicle disaster for waterflooding - it happens in the majority of reservoirs where an injected water is incompatible with the "reservoir" water, and the necessary precautions have not been taken1,2. Scaling results in injection and production well impairment, in plugging the tubing, etc.

The reason for damage is precipitation of salts in a solid state after mixing the injection and reservoir waters1,3,4. Solids can easily plug flow channels and significantly reduce the permeability.

The solid precipitation and consequent formation damage has been the subject of numerous studies over the past three decades. Kinetics of chemical reactions with formation of Barium and Strontium sulphites and of calcite have been studied in details for different baro-thermal reservoir conditions under different chemical ambients of the system ‘water-rock-oil’5–7.

The prediction of well behaviour under the scaling can be done by a mathematical modelling of flow in porous media with chemical reactions8–10. The modelling of flow with chemical reactions which cause scaling have been studied by numerous authors1,11. Many of these works assume local thermodynamic equilibrium, while others assume partial equilibrium12,13. The non-equilibrium scaling processes have been modelled using kinetics of chemical reactions5,6, and the equations have been solved using finite-difference methods1,11.

Am important advance have been done in the recent work12, where the semi-analytic model for flow with scaling chemical reactions have been developed. In this work, the radial flow near to injection wells is considered.

The reservoir scaling can follow different scenario. The salt precipitation happen near to injection wells, in situ in the reservoir and near to production wells1. A sea water, produced water or water from a natural sources can be injected and interact with an aquifer water or connate water1.

The above-mentioned mechanisms, with the exception of the near-producer-scaling, do not cause the formation damage accumulation. The chemical reaction happens in the mixture zone near to the concentration front, so the precipitation zone moves along with the concentration front.

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