Feasibility of Acid Gas Injection into an Aqueous Carbonate Formation

Feasibility of Acid Gas Injection into an Aqueous Carbonate Formation


Acid gas is a greenhouse gas (GHG) composed of (CO2/H2S). It is produced during oil, gas, and petrochemical operations. During the last several years, there has been an increasing pressure within the oil industry to reduce GHG emissions. Another environmental problem within the oil industry comes from the elemental Sulphur, which is converted from the H2S and is accumulated on the surface.  Currently, there exist two technological solutions to deal with this challenge. The first one is the use of it for EOR operations in conventional oil reservoirs. The second one is acid gas injection (AGI) into geological formations for sequestration purposes.

Farzad-B sour gas reservoir is a common share reservoir which is located in Persian Gulf. With reference to basic engineering design, the produced gas with high H2S content (about 40,000 ppm) must be sweetened and non-economic gas (H2S, CO2 and CH4) must be disposed in a proper way. To follow this, the idea of acid gas injection into an aqueous formation proposed.


Acid gas injection is a broad topic covering:

1. The injection of streams rich in hydrogen sulfide and carbon dioxide for disposal purposes.

2. The injection of carbon dioxide (and possibly acid gas) for enhanced oil recovery (EOR).

3. Carbon capture and storage from plants producing flue gas which would otherwise be emitted to the Atmosphere.

The most obvious form of acid gas injection is the injection of a stream composed mostly of H2S and CO2, which is compressed, transported via pipeline to an injection well where it travels downward to a subsurface formation usually for disposal.

To take an example, a typical high sulfur content acid gas composition in tabulated below.

Table 1: Gas composition of acid gas


Mole %








Respective phase diagram and relevant injection path is depicted in following figure. It is worth mentioning that the fluid at wellhead is in liquid phase with an estimated liquid density of 890 kg/m3 while its density at reservoir condition is about 560 kg/m3 which is highly impressive in such a way that at both conditions the fluid remains in liquid phase but the liquid density varies high.


Figure 1: Injection path and phase envelope of acid gas

Trapping by capillary pinning will occur whenever rock types have a difference in their constitutive relations, such as a difference in Pc, Kr, and Swi. These differences are expected in natural rock, and thus we expect capillary pinning. To simulate this in a simulation, two modes are simulated considering homogenous and heterogenous rock properties.


Figure 2: defining different relative permeabilities for heterogenous model in the simulation

As evident in the following figures, capillary trapping plays an important role in gas plume distribution in the reservoir and accurate reservoir rock typing is the essential part of the study.


Figure 3: Vertical cross section of reservoirs showing gas saturation in homogenous model


Figure 4: Vertical cross section of reservoirs showing gas saturation in heterogenous model

As a case study in Surmeh formation, geomechanical model was used in order to estimate pore and fracture pressures. Drilling data was used to estimate pore pressure in Surmeh formation. Drilling data shows that lower part of this formation is more permeable due to the mud loss data but its porosity is very low which may be a remark that this zone is highly fractured. Based on GEM (Geomechaincal Erath Modelling), estimated pore and fracture pressure are 3800 and 6100 psi, respectively.


Figure 5: . Estimated pore and fracture pressures Surmeh formation

Static model of Surmeh formation which is totally water content was provided by G&G team and the relevant simulation input data was imported into the model. 3 different cases was defined: two black oil models with/out gas solubility function and one E-300 model with capability of acid gas function.

Table 2: Static properties of Surmeh formation



Water salinity (ppm)


Temperature (oC)


Pore pressure (psi)


Fracture pressure (psi)


Estimated acid gas density at Surmeh reservoir condition by EoS models is about 780 kg/m3.


Figure 6: Acid gas density as a function of pressure at 140 F

Referring to the simulation results, E-300 model with the capability of supercritical fluid modelling has lowest injection duration ( most promising results). For black oil models with gas solubility capability, following solubility function is defined in the simulation.


Figure 7: Acid gas solubility in water (T = 80oC)

Table 3: Simulation results of 3 cases



Time of BHP limit

Black Oil

gas solubility was considered.

24 years

Black Oil

gas solubility ignored.

23 years



17 years


Figure 8: BHP for 3 cases (Red: Compositional, Green: Black oil without gas Solubility, Brown: Black oil with gas solubility).


  1. Feasibility of acid gas injection into aqueous Surmeh formation is studied and 3 different scenarios simulated.
  2. Because of specifics PVT characterization of acid gas composition, the injected fluid is always at supercritical condition.
  3. Although the injected fluid remains at liquid phase, but the fluid density changes a lot.
  4. Capillary trapping is the main controlling parameter in acid gas plume distribution.
  5. Compositional model of acid gas injection which uses PVT module of supercritical fluid is the most promising results and has the lowest injection duration estimation.


  1. I would like to thank Oveis Farzay for his support and providing respective geomechanical information.
  2. I am also grateful to our colleagues who reviewed the paper and made useful recommendations.




Y. (. Wu, Acid Gas Injection and Related Technologies, Scrivener Publishing, 1970.


S. Morad, "Impact of diagenesis on the spatial and temporal distribution of reservoir quality in the Jurassic Arab D and C members, offshore Abu Dhabi oilfield, United Arab Emirates," 2012.


PPL, MDP Report of Farzad B, 2017.


N. I. Gershenzon, "Influence of small scale heterogeneity on CO2 trapping processes in deep saline aquifers".


E. B. Äulker, investigation of the co2 storage capacity of aquifer structures: co2 storage in a buntsandstein prototype aquifer, clausthal university of technology, 2009, p. 2009.


S. Bachu, "overview of acid-gas injection operations in western canada," 2003.


G. T. Eigestad, "geological modeling and simulation of co2," 2009.


N. Rahimi, "potential for acid gas injection at kharg island".

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