Abstract

Corrosion of injection equipment is a common problem in CO2 miscible injection operations. The two basic mechanisms by which this corrosion occurs are from internal corrosion caused by holidays in the injection tubing coating as well as from external corrosion caused by CO2 invading the tubing-casing annulus through minute seepages in the downhole injection equipment. Unfortunately. these problems are both common and costly.

In one West Texas CO2 injection project, Unocal Corporation, using state of the art connection and testing procedures has developed a method of installing downhole CO2 injection equipment which virtually eliminates this tubing-casing communication. In addition, the internal plastic coating of the tubulars remains intact and holiday free during field handling procedures. The system involves the use of a helium connection test combined with meticulous attention to detail in the field handling and connection of the tubulars.

The following is a discussion of the development of these procedures.

Introduction

CO2 injection was initiated into four wells in the Dollarhide Unit, located in Andrews County, Texas, in June, 1985. Injection into the Devonian formation (average depth—7800 ft- (2380 m)) commenced through casing perforations below a packer at a surface injection pressure of 1350 psig (9300 kPa). The first fourteen installations all utilized 2-3/8" (60.32 m) internally plastic coated tubing and eight round threaded couplings. Various types of eight round couplings and thread lubricants including modified seal ring couplings, premium nose seal couplings, API modified thread lubricant, high Teflon thread lubricant, and Teflon tape were installed. All system developed tubing-casing communication of varying degrees in a relatively short time after injection commenced. Attempts to accommodate the situation by using high concentrations of corrosion inhibitor in the packer fluids were abandoned when the first injection tubing string failed due to external corrosion after only eighteen months of service. Close examination of the failed tubing showed nothing to indicate that the corrosion seen on the tubing was not affecting the casing as well.

In light of these severe conditions, each component of the injection well system that could possibly contribute to the problem was analyzed with the aim of maximizing performance from each component. Once this was accomplished the procedures could be economized to produce the optimum injection well equipment installation program.

The final program of an opposing slip packer, modified eight round couplings, high graphite thread lubricant, and closely monitored field installation procedures has been performed on six CO2 injectors to date. Five of these six wells currently inject with no communication between tubing and casing. The remaining attempt failed for reasons which are still undetermined.

DISCUSSION:
Injection Packer Selection

Injection packer selection was predicated on the ability of the packer to form an adequate seal between the packer and tubing, between the packer mandrel and the packer body, as well as between the on-off tool and packer body.

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