OVERVIEW OF ACID-GAS INJECTION OPERATIONS IN WESTERN CANADA 

Stefan Bachu1*

 and William D. Gunter2

1

Alberta Energy and Utilities Board, Edmonton, AB, T6B 2X3, Canada 2

Alberta Research Council, Edmonton, AB, Canada

ABSTRACT 

Over 2.5 Mt CO2 and 2.0 Mt H2S have been injected into deep saline aquifers and depleted hydrocarbon reservoirs

at 48 sites in western Canada by the end of 2003, driven by the need to dispose of H2S produced with natural gas 

from sour gas reservoirs. Injection of acid gas (CO2 and H2S) occurs over a wide range of aquifer and reservoir 

characteristics, acid gas compositions, and operating conditions. These acid-gas injection operations are a 

commercial scale analogue to CO2 geological storage and are representative of aquifers and reservoirs in continental

sedimentary basins that have undergone compaction and erosion, like those between the Rocky Mountains and the 

Appalachians in North America, where CO2 injection and geological storage on a large scale is most likely to be

implemented in Canada and the United States. 

INTRODUCTION 

Since 1990, faced with the challenge of reducing atmospheric emissions of hydrogen sulphide (H2S) produced

from “sour” hydrocarbon pools, oil and gas producers in the Alberta Basin in western Canada have been turning to

disposal of acid gas (H2S and CO2, with minor traces of hydrocarbons) by injection into deep geological formations. 

To date, 48 applications for injection of acid gas produced at 42 different gas plants have been approved in western 

Canada, of which 41 were active at the end of 2003 (Figure 1). Most operations inject acid gas at a single site

(single well), but a few inject or have injected at several sites, such that in total there are 48 injection sites for 42 

operations. One operation was not implemented and two were rescinded after a period of operation, either because

injection volumes reached the approved limit, or because the gas plant producing the acid gas was decommissioned. 

At a third operation the site was rescinded because the injection volume reached the limit of the injection reservoir,

and it was replaced with injection into a deeper saline formation. At another operation, three different sites have 

been successively suspended by the regulatory agency because of reservoir overpressuring, with injection currently 

occurring into a deep saline formation. 

Figure 1: Location and status at the end of 2003 of acid-gas injection operations in western Canada. 

 

*

 Corresponding author: E-mail: Stefan.Bachu@gov.ab.ca 
At three operations the acid gas is dissolved in water prior to injection, and the resulting weak acidic solution

(“sour water”) is injected. At seven other sites, of which three have been rescinded, wet acid gas (i.e. acid gas with

free water present) is injected. Dry acid gas (i.e. with no free water present) is injected at all other sites. Except for 

the cases of injection in solution, the acid gas is injected as a dense fluid (liquid or supercritical). The cumulative

injection rate for all acid gas injection sites in western Canada reached more than 1 Mt/yr in 2003, of which

approximately 480 kt is CO2 (Figure 2a). The cumulative volume of acid gas injected to the end of 2003 reached

more than 4.5 Mt, of which slightly more than half is CO2 (Figure 2b).

These acid-gas injection operations represent a commercial-scale analogue to geological storage of CO2. The 

technology and experience developed in the engineering aspects of acid-gas injection operations (i.e. design,

materials, leakage prevention and safety) can be adopted for large-scale operations for CO2 geological storage. The 

characteristics of these operations provide a wealth of information that can be used for the screening and 

identification of future sites for geological sequestration and storage of CO2. With the advent of emission trading, 

acid gas injection could become even more appealing to oil and gas producers [1].

Figure 2: Time evolution of cumulative (all operations) a) injection rate; and b) injected volumes, at the acid-gas 

injection operations in western Canada, showing also the fraction of injected H2S and CO2. 

LICENSING AND OPERATING PARAMETERS 

Applications for acid gas disposal need to conform to the specific requirements that deal with applications for

conventional oil and gas reservoirs [e.g. 2]. The selection of an acid-gas injection site needs to address various 

considerations that relate to: 1) proximity of the injection site to the sour oil or gas facility that is the source of acid

gas; 2) confinement of the injected gas; 3) effect of acid gas on the rock matrix; 4) protection of energy, mineral and

groundwater resources; 5) equity interests; and 6) wellbore integrity and public safety [3, 4]. The specific location is

based on a general assessment of the regional geology and hydrogeology, which is designed to evaluate the potential

for leakage. Knowledge of the geological setting and characteristics is critical to assess the integrity of the host

formation or reservoir, and the short- and long-term fate of the injected acid gas. Of particular importance are

potential migration pathways within the injection zone (the spread of the injected acid gas plumes in aquifers is

considered in detail in a companion paper [5]) and from the injection zone to other formations, shallow groundwater 

and/or the surface. To avoid leakage through the caprock or through induced fractures, the maximum bottomhole

injection pressure is set by regulatory agencies at 90% of the fracturing pressure in the injection zone. More

recently, regulatory agencies are limiting the bottom hole injection pressure in the case of injection into depleted

hydrocarbon reservoirs to the initial reservoir pressure or even less. 

Regulatory agencies license only the maximum H2S content of the injected acid gas, which varies between 5% 

and 97% mole fraction. The rest comprises mostly CO2, with a few percent C+ gases for the balance. The actual 

average composition of the injected acid gas varies from 83% H2S and 14% CO2 to 2%H2S and 95% CO2. The

maximum approved wellhead injection pressure varies between 3,750 and 19,000 kPa. Approved daily injection

rates vary between 2,000 and 900,000 m3/day. Maximum allowed injection volumes vary between 6x106 and 
1,876x106

 m3. Based on the estimated total injection volume and aquifer or reservoir capacity, the acid gas injection 

sites are planned to operate for periods of 10 to 25 years. For some specific case histories, see [6]. 

FACILITIES 

After separation of any gas liquids, the produced sour gas is passed through a contactor or absorber tower in a 

one- or two-stage process where the sour gas typically comes in contact with an amine or amine derivative solution. 

The water-saturated acid-gas stream leaves the regeneration unit at 35 to 70 kPa and must be cooled, then

compressed for deep injection. After the acid gas is separated, it is compressed, dehydrated, pipelined and injected

through a disposal well (Figure 3). These operations depend on the properties of the H2S and CO2 mixture, the two

gases having similar phase equilibria [7, 8, 9]. The critical points are T=31.1o

C and P=7,380 kPa for CO2 and 

T=100.2oC and P=8,963 kPa for H2S. The phase behaviour of the acid gas system is represented by a continuous

series of two-phase envelopes separating the liquid and gas phases (e.g. Figure 3). Both CO2 and H2S form hydrates 

at temperatures up to 10o

C for CO2 and more than 30oC for H2S, even if free water is not present [7, 9, 10], thus it is 

desirable to operate above the hydrate-forming temperature. Maintaining temperatures above 35o

C (Figure 3) 

prevents compressor breakdown and plugging, as well as plugging of the pipeline and injection well. Acid gas 

obtained after the removal of H2S and CO2 from the sour gas is usually saturated with water vapor in the range of 2 

to 6%. The solubility of water in both H2S and CO2, hence in acid gas, decreases as pressure increases up to 3-8

MPa, depending on temperature, after which it dramatically increases. The solubility minimum reflects the pressure 

at which the acid-gas mixture passes into the dense liquid phase, where the solubility of water increases substantially

with increasing pressure due to the molecular attraction between these polar compounds [11, 12]. This property is

used in naturally dewatering the acid gas by compressing the gas from about 100 kPa to around 8 to 10 MPa for

injection, thus reducing the water content to less than 0.5 mole% to avoid pipe and well corrosion [11, 12, 13]. 

Figure 3: Typical operating conditions for acid gas injection showing the compression and dehydration cycle, 

transportation from the gas plant to the injection well, and injection, in relation to the acid gas phase and 

hydrate forming conditions (after [14]). 

Most of the compressor drivers are electric motors in Alberta, and natural-gas fuelled engines in British Columbia. 

In Alberta, adding gas engines to an approved plant requires a thorough review of NOx emissions for the plant.

Also, the maintenance cost of electric motors is less than that of natural gas engines. Most installations require only 

four stages of compression. Maximum compressor discharge injection pressures range from 2.8 MPa to 8.9 MPa. 

Generally, the compressed acid gas is injected in a pressure-temperature range where the liquid phase is stable,

resulting in an appreciable head pressure being generated due to the height of column of this liquid in the wellbore, 

thus lowering the required compressor discharge pressure. To avoid cavitation, the acid gas must not enter the twophase region during compression. While sour gas or sweet gas that is injected in cycling (natural gas storage)
schemes requires dehydration, many acid gas disposal schemes do not need to dehydrate the acid gas. By the 4th

stage in a cycle (Figure 3), compression at pressures between 3 and 5 MPa will tend to dewater the acid gas if there 

are no hydrocarbon impurities present [10]. Further compressing the acid gas increases the solubility of water in the 

acid gas, such that residual excess water dissolves into the acid gas, and more than counteracts the decrease in 

solubility due to inter-stage cooling. In the majority of cases dehydration is supplied by the compression cycle and 

only in a few cases tri-ethylene glycol, refrigeration or a desiccant is used. 

Pipelines reflect the fact that most of the current acid gas disposal projects handle small rates, in that most of the 

lines have a diameter of 60 mm (2 inch nominal). The line lengths in many instances are short, reflecting the fact 

that operators have either drilled the disposal well near the plant, or are using a prior existing well adjacent to the 

plant. The design stress levels, and especially the actual operating stress levels, are low, again reflecting the low 

injection pressure levels. Most lines are made out of carbon steel, although many of the short lines are made out of 

stainless steel. Emergency shutdown valves are installed at both ends of the disposal pipeline. The pipelines 

connect the plant compressors to the injection wells, and range in length from 100 m to 20 km, with diameters 

ranging from 48 to 168 mm and wall thickness from 3.2 to 11 mm. 

The bottom hole pressure needed for injection is provided by the pressure at the wellhead and the hydrostatic 

weight of the acid gas in the well, minus friction losses down hole and across perforations. The wellhead is 

equipped with a pressure control valve that regulates pressure. Regulations require that all disposal wells be 

equipped with downhole packers, to protect the casing strings. Casing depths range from 856 to 3,335 metres. 

Casing diameter ranges from 114 to 244 mm, while the tubing diameter ranges from 60 to 244 mm. Many wells are 

equipped with L-80 grade tubing, which is considerably stronger than would be required for the experienced 

injection pressure levels. To protect the tubing against the possibility of internal corrosion, several operators have 

elected to use internally coated tubing. If the gas is undersaturated in water content, corrosion is minimal in any 

case. Subsurface safety valves have been installed in many tubing strings, as a safety measure in the unlikely case 

of backflow of acid gas from the formation. Many tubing strings are equipped with premium threads, to avoid 

potential tubing leaks. Overall, many precautions have been applied in well completions to ensure safe operations. 

SUBSURFACE CHARACTERISTICS 

Table 1 summarizes the characteristics of the geological media into which the acid gas is injected. In 29 cases 

injection takes place in carbonate rocks and in 19 cases in siliciclastics. In most cases shales and shaly siliciclastics 

constitute the overlying confining unit (top seal), but also tight limestones, evaporites and anhydrites are present. 

Reservoir containment of the acid gases by geological trapping is discussed in more detail in [15]. Other trapping 

types for acid gas are hydrodynamic traps formed by deep aquifers, discussed in [16], and mineral traps discussed by 

[17] and [18]. The initial formation pressure is generally subhydrostatic with respect to freshwater, except for one 

case, in the Foothills in northeastern British Columbia, where the injection reservoir was initially slightly overpressured. In the case of acid gas injection into depleted oil or gas reservoirs, the original reservoir pressure was 

drawn down as a result of production, such that formation pressure at the start of acid gas injection was less than the 

original formation pressure, sometimes significantly, reaching as low as 1170 kPa. In 10 cases the formation 

pressure at start-up was below the critical pressure of CO2. 

TABLE 1: CHARACTERISTICS OF THE AQUIFERS AND OIL OR GAS RESERVOIRS USED FOR ACID 

GAS INJECTION IN WESTERN CANADA. 

Characteristic Minimum Value Maximum Value 

Average injection depth (m) 824 3432 

Formation thickness (m) 4 276 

Net pay (m) 2 100 

Porosity (%) 4 30 

Permeability (mD) 1 4,250 

Formation pressure (kPa) 5,915 35,860 

Formation temperature ( ̊C) 26 110 

Water salinity (mg/l) 19,740 341,430 

Oil gravity ( ̊API) 16 68 

Gas specific gravity 0.573 1.121 
In-situ phase and thermodynamic properties of the formation brines and acid gases are discussed in more detail in 

[19]. For the case of acid gas being injected into depleted oil reservoirs, the oils are medium to very light (24 ̊ API 

to 68 ̊API), and in one case the oil is heavy (16 ̊API). Acid gases generally have a lower minimum miscibility 

pressure than conventional hydrocarbon gases, therefore, they can be used in enhanced oil recovery (EOR), as it was 

done at one site [20]. Reservoir gases are generally light (specific gravity less than 0.75). Because acid gas is 

generally heavier than these reservoir gases, it may also be considered for use in enhanced gas recovery. More 

details about the subsurface characteristics of the acid-gas injection in western Canada can be found in [21]. 

CONCLUSIONS 

By the end of 2003, approximately 2.5 Mt CO2 and 2.0 Mt H2S have been successfully injected into deep 

hydrocarbon reservoirs and saline aquifers in western Canada. This experience shows that CO2 storage in geological 

media is a technology that can successfully be expanded to and applied in large-scale operations that will reduce 

CO2 emissions into the atmosphere from large CO2 point sources. The size of the operations approved to date in 

western Canada is relatively small, with approved injection rates and volumes generally less than 0.1 million m3

/d 

and 1000 million m3

, respectively. The technology and experience developed in the engineering aspects of acid-gas 

injection operations (i.e. design, materials, leakage prevention and safety) can be easily adopted for large-scale 

operations for CO2 geological storage, since a CO2 stream with no H2S is less corrosive and less hazardous. No 

safety incidents have been reported in the 15 years since the first operation in the world started injecting acid gas 

into a depleted reservoir on the outskirts of the city of Edmonton, Alberta. Given that H2S is more toxic and 

corrosive than CO2, the success of these acid-gas injection operations indicate that the engineering technology for 

CO2 geological storage is in a mature stage. The major issues that need addressing in the near future are the longterm containment of the injected gases in the subsurface, and the safety of large-scale operations. 

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