This paper covers the execution of a series of field tests at gas well locations in the Netherlands. The objectives were to determine to what flow velocity the gas production can be increased without jeopardizing the integrity of the surface facilities and to establish the optimum corrosion inhibitor injection rate. In one of the field tests, a 4-inch (0.l-m) test flow loop was constructed in a bypass downstream of a test manifold. The loop was equipped with a number of monitoring techniques including FSM (Field Signature Monitoring), ER (Electrical Resistance) probes, Electrochemical Noise, LPR (Linear Polarization Resistance), and AC impedance. The field tests demonstrated that CO2 corrosion can be mitigated by ensuring enough corrosion inhibitor is being injected, even at gas velocities as high as 50 m/s, which is well above a previously established rule of thumb indicating a velocity limit of 20 m/s.


The ability of corrosion inhibitors providing protection at high flow velocities in gas production facilities in gas field of NAM (Nederlandse Aardolie Maatschappij) in the North East of The Netherlands has been an issue with a long history. Quickly after the Groningen gas field came into production, it was realized that corrosion inhibition was needed to protect wells and surface facilities. For many years the maximum production velocity for inhibited flowlines was set at 20 m/s and used as a rule of thumb. This limit was established from early-days field information, which showed that inhibitor was working up to this velocity.

In the nineties, improvement of this rule of thumb was pursued through laboratory experiments. A special Jet-And-Wheel (JAW) lab facility was built to investigate the performance of corrosion inhibitors at droplet impact conditions 1'2. At high flow, annular dispersed flow is the prevailing flow pattern, which justified the use of droplet impact conditions. Using the JAW facility, curves for the maximum gas velocity versus corrosion inhibitor concentration were established. Curves by Van Hunnik and Hendriksen 3 for the performance of an oil-soluble inhibitor (A) are shown in Figure 1. The graph shows the effects of inhibitor concentration, temperature and watercut. At an inhibitor concentration of 150 ppm (on total liquids) the onset velocity for inhibitor failure is about 20 m/s. Increasing the inhibitor concentration to 300 ppm boosts the critical velocity to about 30 m/s. The critical flow velocity increases when temperature increases or watercut decreases.

In recent years, the issue of high flow velocities became more pressing. The need to maintain gas production at reducing reservoir pressure had already resulted in much higher gas velocities in the field than allowed by the rule of thumb or the JAW curves. The business need to increase production capacity without jeopardizing technical integrity in the short and long run therefore prompted two field trials to investigate the behavior of corrosion inhibitor at very high flow velocity. The decision to go for field tests rather than lab tests was taken for a number of reasons. Re-erection and running of the JAW facility would have been at least as expensive as field tests. Field tests would address the real field situation without compromises. Finally, the tests were seen as an opportunity to test a number of corrosion monitoring techniques in the field.


The first field trial was carried out at a 4-inch (0. l-m) carbon-steel flowline with a length of about 140 m. The flowline is directly connected to sweet gas well COV-56 at location COV-31. The CO2 content of the gas is 2.1 mole%. Other conditions are given in Table 1. The corrosion inhibito

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