Wet-Gas Line: Iron Count Rise After Dew Point Shift

The most probable mechanism is condensed-water CO2 corrosion in the cooler, lower-elevation sections, aggravated by a new, wetter, higher-CO2 gas source.

Reasoning chain:

• Dew point margin: bulk gas dew point 88 F vs. line temperature 95 F gives only ~7 F margin. The new well delivers gas at 110 F; as it cools toward line temperature, water condenses. A 4.0 mol% CO2 stream also raises the partial pressure of CO2, increasing carbonic acid strength where water drops out.
• Coupon gradient: inlet coupon 0.4 mpy (likely dry or protected by inhibitor carried from the inlet), midpoint coupon 2.1 mpy. A five-fold gradient along the line points to a location-specific water-wetting problem, not a bulk chemistry change.
• Iron counts: rising soluble iron with a coincident holdup increase is consistent with active wall-loss in wetted low spots. Iron counts lag coupon response and integrate the whole line, so a rise from 3 to 14-18 ppm is a credible early indicator of localized attack.
• No pigging for 14 months means deposits and held liquids are not being removed, so under-deposit and water-accumulation cells can persist.

A competing hypothesis (microbially influenced corrosion) cannot be excluded without sessile bacteria data, but the CO2/dew-point/holdup story fits the timing and the coupon gradient better. The answer should not stop at 'CO2 corrosion' - it must tie the mechanism to the specific location and the new tie-in.

1. Run a caliper or MFL inline inspection (or at minimum a geometry plus UT grid survey at the known low spots). This converts an indirect indicator (iron counts) into direct wall-loss measurement and localizes the damage. It confirms whether the midpoint coupon signal corresponds to real metal loss and whether attack is pitting or general.

2. Install a coupon or ER probe at the midpoint and at a downstream low point, plus collect water chemistry from a separator or knockout. Measure dissolved iron, pH, bicarbonate, and CO2 partial pressure at the actual liquid. This tests the condensed-water CO2 hypothesis and lets you compute a corrosion rate from first principles rather than inferring it.

3. Collect sessile bacteria samples (or at least planktonic) and deposit samples from a pig run. This refutes or supports MIC as a co-mechanism. A pig run also removes the deposits that are sustaining the cells and gives a baseline for future monitoring.

Priority logic: the first action addresses the largest uncertainty (is metal actually being lost, and where?), the second tests the leading mechanism, and the third closes the main alternative explanation. All three are needed before selecting a mitigation strategy; a mitigation decision made on iron counts alone would be premature.

Mitigation should combine dehydration/operational control, chemical inhibition, and mechanical cleaning, because the problem is water accumulation plus CO2, not a single cause.

• Dehydration and dew point control: tighten inlet dehydration so the water dew point is at least 10-15 F below the minimum line temperature, and review the new tie-in's gas temperature and water content. If dehydration cannot be improved, consider a glycol or methanol injection point upstream of the cooling section.
• Chemical inhibition: continuous injection of a film-forming CO2 corrosion inhibitor with a batch slugging program, dosed to the actual liquid volume and with residual monitoring at the midpoint and downstream. Confirm the inhibitor is compatible with the produced fluids and will partition to the water phase.
• Mechanical cleaning: establish a pigging program (at minimum monthly, adjusted to deposit rate) to remove holdup and deposits, which also improves inhibitor contact.
• Monitoring: ER probes and coupons at inlet, midpoint, and low point; iron counts continued weekly; periodic water chemistry; and a follow-up ILI within 12-18 months to confirm wall-loss rate has dropped. Set a response trigger (e.g., midpoint coupon above 1 mpy or iron counts above 10 ppm) that escalates to a review of the program.

The answer should note that inhibitor selection and dose rate must be verified by a field trial, not assumed, and that the program needs a defined review interval because the new tie-in changed the operating envelope.