Abstract

Nelson is a platform development in the Central North Sea approximately 180km east of Aberdeen, producing 38° API oil from a Forties type reservoir with seawater injection pressure support. The high-salinity formation water contains up to 370 mgl-1 of barium, creating a significant scaling risk to the wells upon sea-water breakthrough. The majority of current wells are highly deviated but several horizontal wells with variable permeability exist, which pose a considerable challenge in terms of scale-squeeze placement. N19z is a horizontal well in the North Central region of the reservoir with a 500m cased/perforated producing interval in which breakthrough of sea-water has been confirmed. The well has previously been squeezed, both non-diverted and diverted with wax beads, each with varying success. Earlier reports have examined the effect of applying lightly viscosified fluids on placement of treatment fluids across long intervals to overcome friction and crossflow effects with the potential to assist in treating zones with permeability contrasts1. This approach was pursued to improve the effectiveness of squeeze treatments in long-reach horizontal wells in Nelson, culminating in the successful squeeze of well N19z with a precipitating inhibitor in which all squeeze stages were viscosified. The paper reviews the advantages of the viscosified approach, reports laboratory testing, compares the performance of the squeeze relative with non-diverted and wax-bead-diverted treatments, and highlights some of the pitfalls in applying fully viscosified treatments in both Nelson and other field horizontal or high permeability contrast wells.

Introduction

Scale control in horizontal wells is recognised as a particular technical and economic challenge, especially if effective chemical placement cannot be guaranteed through conventional bullhead squeeze treatments. With longproducing intervals wellbore friction can make uniform treatment difficult even where no significant contrasts in permeability exist; permeability contrasts can exacerbate this still further, in particular, where highest permeability is found near the "heel" of a horizontal well. Moreover, production from zones of different pressures, can generate wellbore crossflow, which can seriously compromise effective adsorption/precipitation of inhibitor during shut-in. Under some of the aforementioned circumstances even placement using coiled-tubing operations cannot guarantee effective chemical placement. The cost associated with use of coiled tubing is very much greater than that associated with conventional bullhead operations, as have been discussed in a number of recent publications.[1–8]

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