Gas Lift Gas at a Hard Compressor Limit: Where Does the Next Mcf Go?
Your field gas-lift compressor is rated at 5.5 MMscf/d and is running at its limit. Two wells are on continuous gas lift. Well A-3 is injecting 2.0 MMscf/d and making 1,100 BOPD; a recent step-rate test gave 1,000 BOPD at 1.5 MMscf/d and 1,180 BOPD at 2.5 MMscf/d. Well B-7 is injecting 3.0 MMscf/d and making 700 BOPD; its step-rate test gave 680 BOPD at 2.5 MMscf/d and 640 BOPD at 3.5 MMscf/d. Well C-1, a new well, is ready to be put on lift and needs about 1.0 MMscf/d continuously to stay unloaded; it is expected to make 400 BOPD. Sales gas is worth $2.50/Mscf and oil is $65/bbl. There is no capital available for a compressor upgrade this year.
1. Allocate the available gas. Show the marginal analysis and the resulting production.
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Marginal oil per Mcf
| Well | Interval | Δ oil | Δ gas | bbl/MMscf |
|---|---|---|---|---|
| A-3 | 1.5 to 2.0 | +100 | 0.5 | 200 |
| A-3 | 2.0 to 2.5 | +80 | 0.5 | 160 |
| B-7 | 2.5 to 3.0 | +20 | 0.5 | 40 |
| B-7 | 3.0 to 3.5 | -40 | 0.5 | negative |
B-7 is past its economic limit: the last 0.5 MMscf/d buys 20 BOPD and the next 0.5 MMscf/d loses 40 BOPD. Its optimum is around 2.5 MMscf/d.
Step 1 - fund C-1. C-1 needs 1.0 MMscf/d and returns 400 BOPD, i.e. 400 bbl/MMscf at the margin, which beats every other option. Take 0.5 MMscf/d from B-7 (cost: 20 BOPD) and 0.5 MMscf/d from A-3 (cost: 100 BOPD). Net gain = 400 - 120 = +280 BOPD with the same total gas.
Step 2 - place the spare 0.5 MMscf/d. After that move the compressor is at 5.0 MMscf/d. Options are A-3 back up to 2.0 (+100 BOPD, 200 bbl/MMscf) or B-7 back to 3.0 (+20 BOPD, 40 bbl/MMscf). Give it to A-3.
Final allocation (5.5 MMscf/d): A-3 = 2.0, B-7 = 2.5, C-1 = 1.0.
Production: 1,100 + 680 + 400 = 2,180 BOPD, versus 1,800 BOPD for the same compressor today.
Gas value check. 0.5 MMscf sold is worth $1,250/d. A-3's marginal 100 BOPD is worth $6,500/d - clearly worth the gas. B-7's marginal 20 BOPD is worth $1,300/d against $1,250/d of sales gas - effectively a wash, which confirms B-7 should sit at 2.5.
2. C-1 needs 1.0 MMscf/d 'continuously'. What has to be checked before you start it, and what can go wrong during unloading?
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Unloading is not continuous injection. Bringing a new well onto gas lift requires an intermittent, high-rate unloading sequence to displace the kill/completion fluid and open the unloading valves in order. That peak rate is typically 1.5 to 2 times the continuous requirement. Here that means 1.5-2.0 MMscf/d for the duration of the unloading - which does not fit in the 5.5 MMscf/d limit unless gas is temporarily diverted from A-3 or B-7. Plan the unloading window, do not discover it at the moment of start-up.
Checks before start-up
- Gas-lift valve design: are the unloading valve depths and set pressures correct for current reservoir pressure and the available injection pressure? A well that has been sitting may need different valve spacing than the design basis.
- Compressor suction and discharge pressure versus the lift-gas header pressure required at 1.5-2.0 MMscf/d - the off-take must not disturb the separator/compressor suction pressure for the rest of the field.
- Whether C-1 will actually unload at the design rate; if it needs more gas than planned, it ties up compressor capacity and the whole allocation is wrong.
- Casing pressure integrity and the well's ability to sustain the unloading drawdown.
What can go wrong
- Stuck at a deep unloading valve, consuming gas without making oil - the classic way a new gas-lift well quietly eats the compressor.
- Unstable heading and slugging into the separator, upsetting the compressor suction.
- If C-1 does not clean up, you have given up 120 BOPD from A-3 and B-7 for nothing. Hold a defined test window and a return-to-previous-allocation trigger.
3. The allocation is fixed for now. What surveillance and decision rules keep it right over the next year?
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Surveillance
- Repeat the step-rate test on each lifted well quarterly, or immediately after any change in reservoir pressure, water cut or wellhead pressure. The curves move; the allocation is only valid for today's curves.
- Track injection gas rate and casing/tubing pressure per well. A drifting spread between injection pressure and casing pressure is an early sign of a leaking or fouled valve, which shows up as gas going downhole without a rate response.
- Recompute the marginal bbl/MMscf every time a well is tested, not every year.
Decision rules
- Any well whose marginal return falls below gas value (bbl/MMscf x oil price < gas price per MMscf) comes off the marginal increment. At $65/bbl and $2.50/Mscf, the cutoff is about 38 bbl/MMscf - B-7 sits right on it.
- Any well that needs more gas to hold the same rate is suspect for valve failure or rising water cut, and should be investigated before it takes more gas.
- Keep C-1 on a probationary allocation until it demonstrates a stable continuous requirement for at least a month.
Longer term
- B-7 is a poor gas-lift candidate - it makes 700 BOPD at 3.0 MMscf/d, which is 4.3 Mscf per barrel, and its curve is flat or falling. Once the well is worked over, evaluate a different lift (ESP or plunger) so its gas can be permanently released to wells that respond.
- If compressor capacity remains the binding constraint at these gas prices, the compressor upgrade pays for itself quickly; quantify it for next year's budget rather than accepting the constraint indefinitely.