Abstract

A good understanding of in situ brine mixing is important for offshore deep water fields under water injection. Incompatibility between the injection and formation waters may result in inorganic scale precipitation in the reservoir, in the well tubing and gravel pack, in flow lines and in surface equipment.In this work, we have used reservoir simulation to model injection brine/formation brine mixing and its effect on reservoir scaling. The objective of this work is to predict in situ brine mixing and its consequences using a simulator that models the kinetics of the scaling reactions. A semi-compositional simulator was used to model the barite deposition reaction which may occur in the reservoir and in the well. In this approach, we take into account the kinetics of the reactions, rather than assuming the traditional (equilibrium) thermodynamic model. Detailed near-well modelling using local grid refinement (LGR) was carried out to forecast of the level of barite precipitation which occurred in the gravel-pack and the consequent production losses.We have also modeled scale inhibitor treatments of the scaling well and a simplified "scale removal" treatment, again including additional preventive scale inhibitor squeeze treatments.

Introduction

The fields in the deep waters of the Campos Basin (Brazil) are produced by waterflooding. These sandstone turbidite reservoirs have high permeabilities (k), high porosities (F) and contain unconsolidated sands which require the deployment of gravel packs in the producer wells. The development of these fields has been accomplished using floating platforms, wells with wet Christmas trees, long flow lines and high production and injection rates. This set up makes all workover operations both complex and expensive.

High quality injection brine is required for these reservoirs to avoid formation damage while also avoiding problems of scale deposition, due to the mixing of incompatible waters, in the reservoir, the producing wells, in the flow lines and in surface equipments. The type of decline in production due to scale related problems is shown in Figure 1 for a typical well in this region. Figure 1(a) shows the rise in watercut (%BS&W) and Figure1(b) shows the associated decline in total fluid production rate (drop in PI). Various protective measures can be taken against scale formation, for example by desulphation of the injected sea water (SW), by the application of chemical scale inhibitors either by downhole squeezing or by injection at various points in the system, using inhibitor impregnated solids in the gravel pack etc.

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