This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 115195, "Squeezing Scale Inhibitors to Protect Electric Submersible Pumps in Highly Fractured, Calcium Carbonate Scaling Reservoirs," by Neil Poynton, SPE, Alan Miller, Dmitry Konyukhov, and Andre Leontieff, Baker Hughes, and Ilgiz Ganiev and Alexander Voloshin, SPE, Ufanipineft, prepared for the 2008 SPE Russian Oil & Gas Technical Conference and Exhibition, Moscow, 28-30 October. The paper has not been peer reviewed.

Electrical submersible pumps (ESPs) can increase production rates, but run time can be compromised by the formation of scale inside the pump. Eventually, the pumps fail (either mechanically or electrically) and must be replaced. Examination of failed pumps indicated the main failure mechanism was deposition of calcium carbonate scale inside the pump. Testing was performed to identify and develop scale-inhibitor squeeze chemistries suitable for appli-

Introduction

Yuganskneftegaz is Rosneft's largest oil-producing enterprise. It holds licenses to develop 26 oil fields in the Khanty Mansiysk Autonomous District of western Siberia.

Yuganskneftegaz's primary fields are Priobskoye, Prirazlomnoye, Mamontovskoye, and Malobalykskoye. The number of wells on production in 2006 was 7,707. The average production per well was 21.3 tonne/d in 2006.

Typical well completions in the Priobskoye field have the following characteristics.

  • Internal casing diameter of 131 or 157 mm (a few with 160 mm)

  • Outside diameter of the production string of 73 mm (a few have 80 mm)

  • Pump depth at 2300 to 2800 m

  • Depth to perforation of 2500 to 3000 m

  • Permeability from 3 to 20 md

Produced water has a calcium carbonate scale potential, which negatively affects ESP run time. Testing identified a suitable squeeze inhibitor, and a model of the application identified the squeeze-treatment sensitivities.

Scale-Prediction Modeling

Commercially available scale-prediction software was used to determine scaling tendencies at different pressures and temperatures for brine chemistries from several Priobskoye wells. An understanding of the scaling risk was developed, and suitable scaling brine was identified for use in the subsequent laboratory inhibitor-selection process. Simulations were performed at bottomhole flowing conditions, for estimated ESP internals, and at well-head conditions.

Scale-prediction results for the different wells followed a similar trend. Three scale species were predicted—iron carbonate, calcium carbonate, and barium sulfate. Of these species, barium sulfate was the least significant, and, where present, the tendency was very mild. Calcium carbonate tendencies ranged from moderate to severe. The pH value at standard temperature and pressure also was calculated with the model, and the results correlated very well with the pH measured in the field.

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