ESPs Successfully Meet Challenges of CO2 Use in Tertiary Oil Recovery
- Lawrence H. Burleigh (Baker Hughes)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- September 2010
- Document Type
- Journal Paper
- 24 - 27
- 2010. Copyright is retained by the author. This document is distributed by SPE with the permission of the author. Contact the author for permission to use material from this document.
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Numerous operators are using CO2 injection as a means of significantly extending the oil life of a reservoir. Most oil fields initially produce without artificial lift (AL). Then as the reservoir pressure depletes some form of AL is employed. In many cases, secondary-recovery techniques, such as drilling horizontal producers or initiating water injection, are employed. Tertiary-recovery methods, which include thermal recovery and gas injection, can further expand recoverable reserves and extend field life. Each of these new tactics has presented learning curves for the operator and electrical submersible pump (ESP) provider.
The CO2 learning curves are shrinking as the knowledge base grows. Success stories are growing as well. A major producer in Saskatchewan, Canada, has applied and refined miscible CO2 injection within a program of water-alternating-gas (WAG) injection that has added 155 million bbl of oil reserves and 25 years of life to the field. This operator has also implemented a program of CO2 sequestration. At the Rangely field in northwestern Colorado, CO2 injection has been incorporated into the WAG process. The injection program has added 114 million bbl of oil to recoverable reserves.
Because of the high produced-fluid volumes resulting from enhanced-recovery methods involving water and gas injection, AL by means of electrical submersible pumps (ESPs) is often applied.
ESP-System Challenges Posed By CO2 Injection
Several potential problems affecting pump run life and performance can occur when an ESP is installed in a producing well where CO2 is present (Fig. 1).
- Carbonic acid attacks
- Asphaltene buildup
- Aromatic attacks on elastomers
- Gas impedance of pump performance
- Carbonate scaling
Carbonic acid. The injected CO2 when mixed with water can form carbonic acid. This acid will attack the iron present in carbon-steel materials in the pump, tubing, and casing. If the fluid speed is low enough, the newly formed iron carbonate (siderite) will remain, creating a protective layer. The mechanical integrity of the component will not be degraded. If the fluid speed is great enough, the iron carbonate layer will be removed. This uncovers a new layer containing iron for the carbonic acid to attack. This mechanism will degrade the mechanical integrity of a carbon-steel component. CO2 corrosion exhibits itself uniquely from H2S, dissolved oxygen, chloride, or galvanic corrosion. Aggressive CO2 corrosion will create deep pits. These pits generally have sharp edges and rounded bottoms. As these pits deepen they will expose internal components to the well fluid. The corrosion pits commonly occur on the outside diameter of the housing material, but occasionally occur on the inside diameter of the pump housings (Fig. 2).
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