Hydrate Control on a Low-Rate Gathering Line: Methanol, MEG, or Heat?
A 6-inch, 8-mile gathering line carries 8 MMscf/d and 30 bbl/d of water from a wellhead at 800 psig to a compressor station at 250 psig. Winter arrival temperature is 48 F. At 250 psig the hydrate formation temperature for this gas is 62 F; at 150 psig it is 56 F. The compressor suction scrubber is already undersized and the slug catcher is running full. Options under consideration are (a) further pressure reduction to 150 psig, (b) MEG injection with an on-site regeneration skid, (c) methanol injection, and (d) insulation plus an inlet heater. MEG is $3.50/gal, methanol is $2.20/gal and is not recoverable, and the station has 300 kW of spare power.
1. Quantify the inhibitor requirement for option (b) and option (c) using a 10 F subcooling margin.
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Design basis. Hydrate temperature at 250 psig is 62 F and arrival is 48 F, so the line is 14 F inside the hydrate region before any margin. With a 10 F margin, the inhibited hydrate temperature must be at or below 38 F:
- Required depression dT = 62 - 38 = 24 F
Hammerschmidt: dT = K x W / (M x (100 - W)), with K = 2335, W = wt% inhibitor in the water phase, M = molecular weight.
MEG (M = 62, K/M = 37.7)
- 24 = 37.7 W / (100 - W) -> W = 38.9 wt%
- MEG:water mass ratio = 38.9/61.1 = 0.637
- Water is 30 bbl/d x 350 lb/bbl = 10,500 lb/d
- MEG mass = 0.637 x 10,500 = 6,690 lb/d; at 9.35 lb/gal = about 715 gal/d, roughly 17 bbl/d of MEG in circulation
- Rich solution returned to the regeneration skid is about 47 bbl/d. With a regeneration unit the make-up is only losses (say 1 bbl/d plus carryover) at $3.50/gal - a few hundred dollars a day, plus reboiler power and skid capex.
Methanol (M = 32, K/M = 73.0)
- 24 = 73.0 W / (100 - W) -> W = 24.8 wt%
- Methanol:water mass ratio = 24.8/75.2 = 0.330
- Methanol mass = 0.330 x 10,500 = 3,465 lb/d; at 6.6 lb/gal = about 525 gal/d, roughly 12.5 bbl/d
- At $2.20/gal this is about $1,150/d, over $400,000/yr, before allowing for the significant fraction that partitions into the gas phase and is lost - realistically 20-50% more.
The 38.9 wt% MEG requirement is high and should be checked against the vendor's freeze point and viscosity data; a richer solution raises the circulation rate and the regeneration duty.
2. Is reducing the line pressure to 150 psig sufficient on its own? What else does that change?
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No. At 150 psig the hydrate temperature falls to 56 F, but the winter arrival temperature is 48 F - the line is still 8 F inside the hydrate region, and with any safety margin it is not even close. Pressure reduction lowers the hydrate temperature, but it also raises the compression ratio, so the compressor does more work for the same throughput - the compressor is already constrained and the scrubber is already undersized.
What else changes at 150 psig
- Gas velocity in the 6-inch line rises by roughly a factor of 1.6, which improves liquid transport (helps the full slug catcher) but raises the frictional pressure drop per mile, so the wellhead pressure requirement goes up and the well's deliverability drops.
- Lower suction pressure means more gas volume for the same mass through the compressor, so the compression horsepower requirement increases.
- The lower pressure does reduce hydrate severity somewhat and can be a useful adjunct, but it is not a stand-alone solution here.
So option (a) can be part of a combined scheme but cannot be approved as the hydrate control strategy.
3. Make a recommendation among the four options and justify it against the operating realities in the setup.
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Recommendation: MEG with regeneration as the base scheme, methanol as the upset/backup chemical, and a study of insulation plus inlet heating as a possible long-term capex reduction.
Why MEG
- Continuous water production of 30 bbl/d and a 24 F depression requirement is a year-round, steady-duty problem. Methanol at $400,000+/yr and rising with vaporisation loss is the wrong tool for a continuous duty; it is the right tool for start-up, shutdown, and unplanned upsets.
- Regeneration keeps the operating cost to make-up losses, and the 300 kW spare power is plausibly enough for a reboiler serving a 47 bbl/d rich-MEG stream, so the utility constraint is likely satisfiable - confirm with the vendor before committing.
- MEG is recoverable and the storage/regeneration infrastructure is a one-time capex against a permanent opex.
Why not the others alone
- Methanol alone: cost per year is punishing, the scrubber is undersized and methanol carryover into the gas will make it worse, and it is not a steady-state solution.
- Pressure reduction alone: quantitatively insufficient, and it worsens the compressor and wellhead pressure picture.
- Insulation plus inlet heating: technically the most elegant (get arrival temperature above 62 F and no chemical is needed at all) but 8 miles of line is a large capex and the 300 kW of spare power must be checked against the heat loss; approve it as a study, not as this winter's answer.
Non-negotiable companions to any option
- Fix the undersized suction scrubber and the full slug catcher. A hydrate programme that ignores liquid carryover into the compressor will simply move the failure from the line to the machine.
- Install hydrate temperature and dew point monitoring at the arrival and an injection-rate control loop tied to gas rate and water rate, not a fixed chemical dose.
Judgement call: do not wait for the insulation study. Put MEG on the line before the first cold snap, with methanol on site for start-up and as the emergency backup.