Corrosion Control of Gas-Lift Well Tubulars By Continuous Inhibitor Injection Into the Gas-Left Gas Stream
- D.H. Mutti (Exxon Co. U.S.A.) | J.E. Atwood (Exxon Co. U.S.A.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- June 1976
- Document Type
- Journal Paper
- 624 - 628
- 1976. Society of Petroleum Engineers
- 1.8 Formation Damage, 6.3.6 Chemical Storage and Use, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 4.2.3 Materials and Corrosion, 4.2 Pipelines, Flowlines and Risers, 4.1.2 Separation and Treating, 3.1.6 Gas Lift, 4.6 Natural Gas, 5.6.5 Tracers, 4.1.9 Tanks and storage systems
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Two treating systems have been developed to provide corrosion control of gas-lift well tubulars by continuously injecting corrosion inhibitor into the gas-lift gas stream. The amount of inhibitor injected is controlled by either a system of proportional divider valves or by an auto mated time-shared proportional divider valves or by an auto mated time-shared system using an electronic scanner and an adjustable time to control solenoid valves.
Internal corrosion of tubulars in gas-lifted oil wells along the Texas Gulf Coast is widespread and often quite severe. The corrosion attack is caused by production of large volumes of salt water, particularly from the predominantly water drive reservoirs in this area, predominantly water drive reservoirs in this area, coupled with the presence of carbon dioxide in the produced gas. Carbon dioxide dioxide dissolved in salt produced gas. Carbon dioxide dioxide dissolved in salt water forms an acidic brine solution that causes a general corrosion attack on steel tubulars. This form of corrosion often results in heavy localized pitting, with the greatest metal loss in gas-lifted wells usually occurring in the portion of the tubing string above the operating gas-lift portion of the tubing string above the operating gas-lift valve. Corrosion severity is often such that tubing strings require replacement as frequently as every 6 months. Plastic-coated tubing has solved, to an extent some of our severest tubing corrosion problems; but it cannot be economically justified in many instances. During the past several years, corrosion has become an increasing problem as a result of the need for capacity production. Corrosive high-water-cut wells are being production. Corrosive high-water-cut wells are being produced; and additional turbulence in the tubing from produced; and additional turbulence in the tubing from higher producing rates accelerates the corrosion-erosion attack. This paper describes systems developed to replace conventional down-hole corrosion-inhibitor batch treatments with continuous inhibitor injection into the gas-lift stream. The systems allow control of treatment for individual wells.
Conventional Corrosion Control Methods
Corrosion of steel tubulars in gas-lift wells can be controlled by application of properly selected corrosion inhibitors. Corrosion control programs for gas-lift wells commonly use one of the following batch treating techniques: Tubing displacement Corrosion inhibitor in displaced to the bottom of the tubing string with the inhibitor forming a protective film on the tubing. Weighted inhibitor weighted corrosive inhibitor is pumped into a well where it falls to bottom then slowly comes back in the produced fluid, forming and replenishing a protective film on the tubing. Formation squeeze Inhibitor is squeezed (pumped) into the producing formation; inhibitor is adsorbed on the formation and subsequently desorbs into the produced fluids, forming and replenishing a protective film on the tubing. Successful corrosion control programs using these treating methods are expensive, since they usually require a truck-mounted pump and operator in addition to the inhibitor. Schedules for such programs are frequently difficult to maintain, resulting in treatment inconsistency. It is also difficult to optimize treatment size vs frequency to avoid periods of under-or over-treatment. Operating problems often associated with programs using batch treating techniques are the following (1) Wells must be shut in to treat, resulting in lost production.
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