Abstract

Results of laboratory and field investigations are presented which illustrate corrosion identification and control in several types of EOR projects. Primary emphasis is given to producing wells in CO2 floods, in polymer or mice]]-polymer floods, and insitu combustion wells. Injection wells in these projects are considered briefly.

Based on corrosion measurements and measurements of sulfide, bicarbonate, and dissolved CO2 in produced fluids, effective corrosion inhibitors can be selected for corrosion control in all of the above conditions.

Introduction

Primary petroleum recovery followed by water-flood recovery commonly leaves at least one half of the original oil still in the producing formation. This unrecovered oil potentially represents a producing formation. This unrecovered oil potentially represents a large reserve. In the last 15 years, a combination of factors involving oil price, tax structure, and desire for increased production has led to increased investigation of enhanced oil recovery techniques, especially in the United States. Of the many techniques investigated, a few seem to be emerging as the most desirable in terms of application and economics.

The general categories of methods are thermal processes, chemical processes, and miscible gas displacement processes. Steam soaking and processes, and miscible gas displacement processes. Steam soaking and steam injection are the thermal EOR methods responsible for the greatest incremental oil recovery to date. Another popular thermal process is insitu combustion - often referred to as fire flooding. The most popular chemical processes are micell solution injection pushed by polymer and polymer augmented water flooding. pushed by polymer and polymer augmented water flooding. Hydrocarbon gas and carbon dioxide injection are the two common miscible displacement techniques. Carbon dioxide injection represents the fastest growing of these methods in terms of new projects. All of these methods may be expected to have some influence projects. All of these methods may be expected to have some influence on the corrosivity of brines associated with the oil. This paper discusses laboratory and field investigations of these influences and of corrosion inhibitor effects.

Previous work concerning steel corrosion in petroleum-associated brines has pointed out the importance of petroleum-associated brines has pointed out the importance of bicarbonate, carbon dioxide, sulfide, and oxygen contents on corrosivity and on selection of effective inhibitor types. Therefore, the study of the influence of EOR processes on these parameters was of first priority. parameters was of first priority.

EXPERIMENTAL

Corrosion rates in both laboratory and field investigations were measured using linear polarization and potentiodynamic polarization techniques confirmed with weight loss coupons. polarization techniques confirmed with weight loss coupons. Determination of bicarbonate was by sulfuric acid titration, dissolved carbon dioxide by sodium hydroxide titration, and sulfide with methyl blue or iodine titrations. Oxygen influence on corrosion reactions was measured using wide scan polarization since in systems containing hydrogen sulfide, free oxygen may not be present because an oxidizing intermediate can he formed. In laboratory tests, analytical grade salts and gases were used, and in the case of micell and polymer investigations commercially available materials were used. Field determinations of polymer concentrations were made by the. chlorox-turbidity technique.

Carbon Dioxide Injection Projects

Both laboratory and field experiments dealing with CO2 flooding have been reported previously but will be summarized here. Two sets of laboratory experiments were conducted, one with 3.5% NaCl and the other a 5.3% mixed salt solution representative of geological brines. Varying amounts of HCl, NaOH, and NaHCO were added to these solutions along with argon or CO2 sparging to obtain a range of pH's, HCO3- concentration and dissolved CO2 concentration.

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