Acid Gas Injection (AGI) — Engineering Fundamentals

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 = y_CO2 + y_H2S, B = y_H2S. Then:

• T_pc' = T_pc − ε
• P_pc' = P_pc · T_pc' / (T_pc + B·(1−B)·ε)

Use the corrected criticals to compute T_pr, P_pr, then read or fit Standing-Katz. For 60% CO₂ / 35% H₂S, ε ≈ 13 °R — a substantial correction that, if ignored, can mis-predict tubing flow by several percent.

5. Water content & hydrates

The amine-regenerator overhead is water-saturated. Untreated, this water has two adverse effects:

1. Hydrate formation in the tubing during a depressurization or thermal transient — CO₂ hydrates form at temperatures up to ~50°F at 1,500 psia.
2. 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.