Abstract

Scale inhibitor "squeeze" treatments are used extensively to control problems with downhole carbonate and sulphate scale formation. The return curve from an adsorption/desorption squeeze is governed by the inhibitor/rock interaction which, in turn, is described by the adsorption isotherm. Several factors, such as pH, [Ca2+], temperature, rock mineralogy etc., affect the adsorption level and the shape of the adsorption isotherm. However, these same factors may also lead to deleterious effects in terms of both formation damage and inhibitor solution effectiveness; the latter effect is referred to in this work as "fluid damage".

In this paper, results and discussion are presented on the potential for formation damage and inhibitor fluid damage when acid phosphonates are applied in clastic reservoir formations. Results are presented from an extensive series of phosphonate (DETPMP) scale inhibitor core flooding experiments using Brent Group (North Sea) sandstone cores as the adsorbing substrate. Careful effluent analysis along with detailed petrography and permeability measurement before and after core flooding are shown to be invaluable in assessing the degree of formation damage (and "fluid damage") arising due to several factors. Most of the points raised here are quite general and they are illustrated by the specific field results. This work therefore contributes to the development of safer field applications of scale inhibitor squeeze treatments in the light of individual reservoir petrography.

Introduction

Scale inhibitor "squeeze" treatments provide one of the most common and efficient methods for preventing the formation of sulphate and carbonate scales in producer wells.1–6 A number of acid phosphonate inhibitors are commonly used for downhole application in many oil reservoirs around the world.

The procedure for applying such a chemical treatment normally involves the following six stages;

  • a "spearhead" package (a demulsifier and/or a surfactant) is injected which is thought to increase the water wetness of the formation;

  • a dilute inhibitor preflush is often applied to psh the spearhead into the formation and to cool the near wellbore region;

  • the main treatment is injected which contains the inhibitor chemical, normally in the concentration range 2.5% to 20%;

  • the brine overflush is applied which is designed to push the main treatment to the desired depth in the formation away from the wellbore;

  • a shut in or soak period (usually - 6–24 hours) is allowed which is the time when the pumping of the overflush stops and the inhibitor adsorbs on to the rock substrate;

  • finally, the well is brought back on production. Several chemical and physical processes in these steps in a scale inhibitor squeeze treatment may affect the inhibitor adsorptio characteristics. In addition, these same factors may be responsible for various types of damage in the reservoir formation.

Adsorption of scale inhibitors is thought to occur through electrostatic and Van der Waals interactions between the inhibitor and formation minerals. For phosphonates, it is known that adsorption is a function of pH, temperature, mineral substrate, and involves cations such as Ca2+.2-5,7-12 the precise form of the isotherm describing this adsorption process determines the squeeze lifetime, as is described in detail elsewhere.13–18 In a number of previous papers, we have discussed and explained how these various factors affect inhibitor retention in porous media. In this work, our objective is to review and illustrate how these same factors may adversely affect aspects of both formation and "fluid" damage. For example, the effect of pH on phosphonate inhibitor adsorption has been demonstrated.9,10 However, the low pH phosphonate inhibitors may cause a number of other effects some of which are deleterious (e.g., carbonate cement dissolution leading to sand production) or benign (e.g., minor mineral pitting say on kaolinite and feldspar).

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