Acid Gas Injection (AGI) — Engineering Fundamentals
CO₂/H₂S phase behavior, dense-phase injection, Wichert-Aziz correction, sour-service materials, regulatory framework.
1. What is AGI?
Acid Gas Injection (AGI) is the disposal of CO₂ and/or H₂S from amine treating units (typically the regenerator overhead) by injecting them into a deep geological formation. It became attractive in the 1990s as a cost-effective alternative to Claus-plant sulfur recovery for small-to-medium sour gas plants where the acid-gas stream is too dilute to justify a Claus, or sulfur logistics are difficult.
Modern AGI is also a major pathway for Class VI permanent CO₂ sequestration under 45Q tax-credit and Class II Subpart RR reporting frameworks.
2. CO₂/H₂S phase behavior
Pure-component critical points:
| Species | Tc | Pc | Critical density |
|---|---|---|---|
| CO₂ | 87.9 °F (304.1 K) | 1,071 psia (7.38 MPa) | 29.2 lb/ft³ (468 kg/m³) |
| H₂S | 212.8 °F (373.5 K) | 1,306 psia (9.00 MPa) | 21.7 lb/ft³ (349 kg/m³) |
| CH₄ | −116.7 °F (190.6 K) | 667 psia (4.60 MPa) | 10.1 lb/ft³ (162 kg/m³) |
Mixture critical estimates by Kay's rule (linear molar averaging) are close enough for AGI screening. CO₂-dominated acid gases will be near or above critical at typical wellhead conditions (1,500–2,500 psig at 100–150°F).
3. Dense-phase injection — why it matters
"Dense phase" = above the critical pressure AND above the critical temperature. The fluid has gas-like viscosity (~0.04 cP) but liquid-like density (400–800 kg/m³). For an AGI well that means:
- Strong hydrostatic head. A 60% CO₂ / 35% H₂S mixture in dense phase weighs ~50 lb/ft³ — at 8,000 ft TVD that's ~2,800 psi of free hydrostatic, often enough to overcome reservoir pressure without surface compression at all.
- Low friction. Gas-like viscosity keeps tubing friction modest even at high mass flow.
- No two-phase complications. Single-phase flow throughout the tubing — no slug catcher, no foam, no gas-lock.
The compressor train is designed to deliver the acid gas just above the dense-phase boundary at the wellhead temperature, then hydrostatic compression in the wellbore does the rest. Properly engineered, this lets a single compressor stage replace what would otherwise be a 4-stage gas-injection train.
4. Wichert-Aziz sour-gas correction
The Standing-Katz Z-factor chart was developed for sweet hydrocarbon gases. CO₂ and H₂S have stronger intermolecular interactions and the chart over-predicts Z at the same reduced P/T. Wichert & Aziz (1972) developed a correction:
where A = yCO2 + yH2S, B = yH2S. Then:
- Tpc' = Tpc − ε
- Ppc' = Ppc · Tpc' / (Tpc + B·(1−B)·ε)
Use the corrected criticals to compute Tpr, Ppr, then read or fit Standing-Katz. For 60% CO₂ / 35% H₂S, ε ≈ 65 °R — a substantial correction that, if ignored, can mis-predict tubing flow by 15–25%.
5. Water content & hydrates
The amine-regenerator overhead is water-saturated. Untreated, this water has two adverse effects:
- Hydrate formation in the tubing during a depressurization or thermal transient — CO₂ hydrates form at temperatures up to ~50°F at 1,500 psia.
- Carbonic acid corrosion — CO₂ + H₂O → H₂CO₃, dropping local pH to ~3 and aggressively attacking carbon steel.
Standard practice: dehydrate the acid gas to ≤ 2 lb H₂O / MMscf via glycol contactor or molecular sieve before compression. With deep dehydration the corrosion problem reduces to manageable rates with L80 or 13Cr tubing.
6. Sour-service materials (NACE MR0175)
H₂S partial pressure governs cracking risk. NACE MR0175 / ISO 15156 thresholds:
| H₂S partial pressure | Service category | Typical tubing |
|---|---|---|
| < 0.05 psia | Sweet | L80 carbon steel |
| 0.05 – 15 psia | Sour Region 1 | L80 9Cr / L80 13Cr |
| 15 – 50 psia | Sour Region 2 | 13Cr / Super 13Cr |
| > 50 psia | Sour Region 3 | 22Cr / 25Cr duplex stainless or Ni-base alloy |
An AGI with 35% H₂S at 3,000 psig has H₂S partial pressure ≈ 1,000 psia — far into Region 3. Tubing is typically 22Cr or 25Cr DSS, and wellhead trim is solid 825 / G3.
7. Regulatory framework
AGI wells in the U.S. are permitted under:
- UIC Class II (40 CFR 144 Subpart C) for traditional oil-and-gas-related acid gas disposal — co-located with the source plant, limited geographic scope.
- UIC Class VI (40 CFR 146 Subpart H) for dedicated CO₂ geologic sequestration — long-term monitoring, larger area of review, financial assurance.
- EPA Subpart RR (40 CFR 98) for GHG reporting and 45Q tax-credit eligibility.
- State primacy: Texas RRC, Oklahoma OCC, North Dakota Industrial Commission (Class VI primacy 2018), Wyoming OGCC (Class VI primacy 2020).
8. References
- Wichert, E. & Aziz, K. (1972). "Calculate Z's for sour gases." Hydrocarbon Processing, May 1972, 119–122.
- Beggs, H. D. & Brill, J. P. (1973). "A study of two-phase flow in inclined pipes." JPT, May 1973.
- Carroll, J. J. (2002). "The water content of acid gas and sour gas from 100°F to 220°F and pressures to 10,000 psia." Gas Processors Assoc., Annual Conv.
- Maddocks, R. R., Wichert, E. (2014). "Acid gas injection — design and operation." GPA Europe.
- NACE MR0175 / ISO 15156 — Materials for use in H₂S-containing environments.
- 40 CFR 144 Subpart C — Class II UIC wells.
- 40 CFR 146 Subpart H — Class VI UIC wells for geologic sequestration.
- 40 CFR 98 Subpart RR / UU — GHG reporting for CO₂ injection.