ACID GAS INJECTION: A STUDY OF EXISTING 

OPERATIONS 

PHASE I: FINAL REPORT 

Report Number PH4/18 

April 2003 

This document has been prepared for the Executive Committee of the Programme. 

It is not a publication of the Operating Agent, International Energy Agency or its Secretariat. 
ACID GAS IN EXISTING OPERATIONS 

PHASE I: FINAL REPORT 

Background to the Study 

tions in global

s, such as fuel

al storage is not a new technology. 

However, it is acknowledged that all the technical issues related to geological storage have not yet been 

nology can be

fields as part of 

ad, Turkey and 

a, a CO2-EOR 

wan, which will 

f CO2 from the 

to a deep saline aquifer since 1996. To develop an understanding

r and Weyburn. 

n existing CO2-

ues and help to 

udied in an effort to obtain 

 Such activities 

pment of deep 

projects in the

g naturally existing accumulations of CO2 to determine what 

arlier, there are

operation since

ntribute to our

nown

lberta Research 

e first phase of that

study, which has compiled information on the geological setting of the acid gas injection sites and 

operating/engineering experiences from these projects. An interim report2 has already been published 

tion at the end of 2001. The

panded version of that one, covering all of the acid gas operations in both Alberta

and started in 2002. Phase II of the study 

involves a due diligence exercise on a selected site that will establish that such projects are technically

and economically sound and that the carbon balance is positive to allow such projects to be included in

carbon trading regimes in the future. The proposed Phase III would involve a monitoring project. 

 

JECTION: A STUDY OF

Geological storage of CO2 is considered to be an option that could achieve deep reduc

emissions of anthropogenic CO2, if used in conjunction with other mitigation measure

switching, energy efficiency and renewable energy. Geologic

fully resolved. Those issues outstanding will have to be addressed before the tech

accepted by the policy makers and the public for wide-scale implementation. 

Worldwide, there are currently some 74 projects in which CO2 has been injected into oil

CO2 enhanced oil recovery (CO2-EOR) operations, mostly in the USA, but also in Trinid

Canada. In the USA, some 33 Mt of CO2 is injected annually into oil fields. In Canad

project has been established by EnCana at the Weyburn oil field in southern Saskatche

inject a total of 19 Mt of CO2 over 25 years. In the North Sea, some 1 Mt per year o

Sleipner gas field has been injected in

of the fate of the injected CO2, detailed monitoring projects are underway at both Sleipne

In addition, some work is also underway in the USA to study the fate of injected CO2 i

EOR operations. Such information will assist in addressing the outstanding technical iss

develop public confidence in the technology. 

In addition, there are a number of other related activities that have been st

information that could assist in improving understanding of geological storage of CO2.

include the study of deep well injection of industrial wastes in the USA, the develo

repositories for nuclear waste disposal and natural gas storage1

. In addition, research

USA, Europe and Australia are studyin

information can be gained from these occurrences relevant to geological storage of CO2.

Whilst smaller in scale than the CO2-EOR and Sleipner injection operations mentioned e

some 42 acid gas injection projects operating in western Canada. Many have been in

the mid 1990s. These represent another repository of knowledge that could co

understanding of the geological storage of CO2. 

The IEA Greenhouse Gas R&D Programme has participated in a project to find out what is k

about the 42 acid gas injection projects in Canada. The study was undertaken by the A

Council (ARC) and the Alberta Geological Survey (AGS). This report covers th

on this, covering the 31 acid gas injection projects in Alberta in opera

current report is an ex

and British Columbia, including new operations approved

1

 This work was undertaken for the CO2 Capture Project by Lawrence Berkeley National Lab. A summary report

was published by Benson et al at the GHGT-6 Conference, whilst the full report can be found at

www.co2captureproject.com 2

 IEA Greenhouse Gas R&D Programme, Report No PH4/15, January 2003. 

i
Technical Background 

anada, contains

carbon dioxide 

domestic sale, 

990’s, sulphur

sulphur in the

as of the order 

t efforts have been made to reduce 

gas flaring. One alternative to flaring, sulphur recovery, is not considered to be economically viable in

y turned to acid 

re 42 approved

operations (35 in Alberta & 7 in British Columbia) for acid gas injection, of which 39 were active. The

growth in acid gas injection operations is shown in Figure 1. One operation, although approved, has 

never been implemented by the operator. Two other operations were stopped because the gas processing

plant closed. 

A significant proportion of the raw natural gas production in the Alberta basin, C

varying percentages of acid gas components, specifically hydrogen sulphide (H2S) and

(CO2). Therefore, to meet pipeline specifications, and specifications for industrial and

the gas must be treated to separate out the acid gas components. Until the early 1

recovery and gas flaring were considered the most economic ways of dealing with the

waste acid gases. In the early 1990s, the yearly emission from gas flaring in Alberta w

0.3 Mt SO2 and 6 Mt CO2. However, due to public concern, stringen

a depressed sulphur market. Gas processing plant operators, therefore, have increasingl

gas injection in deep subsurface formations as the preferred alternative to flaring. 

The first acid gas injection operation in Alberta was started in 1989. By 2002, there we

Figure 1: Growth of Active Acid Gas Injection Sites in Western Canad

 

a

The acid gas injection operations are mostly located close to the Rocky Mountain range, where the

5% inject into deep

servoirs. The composition of the injected acid gas varies 

from site to site, from 95% H S / 5% CO to 1% H S / 98% CO . 

In 2000, the actual injection rates for CO2 and H2S were 0.26 and 0.2 Mt/y respectively. Overall, close 

to 1.5 Mt CO2 and 1 Mt H2S have been injected to date into deep hydrocarbon reservoirs and saline

aquifers in western Canada from 1989 to 2000. 

Details of the plant locations, acid gas injection compositions and site geology are given in the main 

report and have only been summarised in this overview. 

 

produced gas in Canada tends to be “sour3

”. Of the acid gas injection operations, 5

saline aquifers and 45% into depleted oil/gas re

2 2 2 2

3

 Sour gas means that the natural gas contains acid gas species that can include CO2, H2S and SO2. 

ii
Results and Discussion 

e study are summarised with particular emphasis on what can be learnt from the acid

gas injection operations that is transferable to geological storage operations for CO2. The following 

a

ites,

•

• Operational safety and reservoir integrity 

and the British

perations must 

ith applications

led on those of

id gas injection

at the applicants submit detailed information

regarding surface facilities, injection well configurations, characteristics of the injection reservoir or

re reviewed by 

rces, minimize 

pproval is granted, a set of licensed operating parameters is established by the regulators. After 

that, the operators have to submit biannual progress reports to the regulatory agencies on their 

ions if they feel

e such case is

cheduled in the

ory process for

f operation of acid gas injection sites. In addition, there is a tried and tested surface

hich has allowed regulators to decide on enforcement of plant closures in the 

event of concerns regarding the operation of the injection well and its possible impact on the integrity

n those for CO2

tions provide a

ere no current 

Operational knowledge base 

After 14 years of operation, a considerable knowledge base has now been built up relating to the

operation of these acid gas injection facilities. This knowledge base relates principally to pipeline

transportation and operational experiences in surface and injection well operations, since no subsurface

rable to new CO2

geological storage projects. 

 

The results of th

reas are discussed: 

• Regulation of acid gas injection s

Operational experience, 

Regulation of acid gas injection sites in Canada 

The regulatory bodies concerned are: the Alberta Energy and Utilities Board (AEUB)

Columbia Ministry of Energy and Mines. In Alberta, applications for acid gas injection o

conform to a set of specific requirements given in Chapter 4.2 of Guide 65 that deals w

for conventional oil and gas reservoirs4

. Requirements in British Columbia are model

Alberta. Prospective operators are required to apply for and obtain approval before ac

operations can commence. The regulators require th

aquifer, and injection operations. Before approval of any operation, the applications a

the regulatory bodies to ensure that they maximize conservation of hydrocarbon resou

environmental impact and ensure public safety. 

When a

operations. The regulatory bodies concerned will exercise powers to close down operat

that safety procedures required by the approval schedule have been breached. On

mentioned in the main report where injection pressures were significantly higher than s

approval. 

It is clear that, in both Alberta and British Columbia, there is a well-developed regulat

the approval o

monitoring procedure w

of the reservoir. Regulations framed for acid gas injection should be more stringent tha

injection alone, because H2S is a highly toxic chemical species. However, these regula

useful benchmark for countries that are considering new CO2 storage projects wh

regulations exist. 

monitoring is undertaken. Such operational experience should be directly transfe

4

 Alberta Energy Utilities Board, Guide 65: Resources Applications for Conventional & Gas Reservoirs, 2000. 

This can be found at: http://www.eub.gov.ab/bbs/products/guides/g65.pdf 

iii
Operational safety. 

perational staff 

tional safety is

ease of the acid 

ral steel tubing 

asing, which is 

jection well to

ling a “packer” 

rage formation. 

This is pressure tested for integrity once a year. A down-hole safety valve or check valve is

id gas from the

ith valves.

blished around

tors are required to have a

ective ERP, the

alarm systems, 

ns.

s transporting the acid gases are usually short typically 100 to 200m5 and generally are 

sion, a common

dration also prevents

operational problems associated with hydrate formation that can cause compressor breakdown and 

to store CO2 in 

ical reservoirs, although the acute toxicity of H2S will warrant increased safety measures. 

Rese

T r hese measures

inclu

roval process requires that a detailed assessment of the regional geology and 

his process is

e geological setting and characteristics, another feature required in the

app st formation or reservoir, and the

e potential

ndwater and/or

• The setting of licensed operating limits is a key feature in the regulatory process that is 

designed to protect the integrity of the injection. The licensed operating parameters include the 

d maximum injection volumes. 

The bottom hole injection pressure is set no higher than 90% of the fracture pressure to ensure 

that fracturing of the cap rock does not occur, but in many cases it is much lower, even at 90% 

of the original reservoir pressure when injection takes place into a depleted oil or gas reservoir.

 

Since H2S is a highly toxic species, even small releases can constitute a serious risk to o

and the local environment. One of the key design features, therefore, in ensuring opera

that of the injection well. This has to be designed and operated to prevent accidental rel

gas. In acid gas injection operations, the injection well typically consists of a cent

“string” (i.e. series of connected tubes) with an outer annulus bounded by a steel c

cemented to the subsurface formations. Several safety features are incorporated in the in

prevent leakage. The casing is isolated from the tubing string and the acid gas by instal

in the annulus between the casing and the tubing string just above the subsurface sto

incorporated in the tubing string so that if something fails at the surface, the flow of ac

formation will be prevented. The well head of the injection well is similarly protected w

As part of the regulatory process, it is required that an Emergency Planning Zone is esta

the injection well in the case of an accidental release of acid gas. The opera

detailed emergency response plan (ERP) for use in the event of a leak. To have an eff

area surrounding the injection site should be equipped with H2S detection and

windsocks, self-contained breathing apparatus, and remote unit and plant shutdown statio

Pipeline

constructed of mild steel. Pipelines are designed to minimise the risk of leakage. Corro

cause of pipeline failure, is avoided by dehydrating 6 the acid gas. Dehy

plugging. 

Such operational safety principles and experience are transferable to projects proposing

geolog

rvoir integrity and protection of overlying water resources

he e are a number of measures employed to maintain the integrity of the reservoir. T

de:

• The app

hydrogeology, is undertaken to select the location of the injection well. T

designed to evaluate the potential for leakage before approval is granted. 

• Knowledge of th

roval process, is critical to assess the integrity of the ho

short-and long-term fate of the injected acid gas. Of particular importance ar

migration pathways from the injection zone to other formations, shallow grou

the surface. 

setting of the following:

o Maximum well head and bottom hole injection pressures 

o Maximum daily injection rates an

5

 There are cases of pipelines up to 5500m. 6

 Moisture contents of less than 0.5 mole % are maintained by removing the water condensed after each

compression stage rather than using a separate dehydration stage. 

iv
Typically, the fracture pressures are defined from pressure depth-correlation data for the

Alberta basin if site-specific tests have not been carried out. 

neral resources, 

he type of fluid

III wells under 

is noted that the

oil recovery in 

at less stringent

or Class Ia wells that are designated for the injection of oil field and industrial waste fluids9

. 

aring zones are 

ell. However,

odies to study

trast can be drawn with natural gas regulations in Europe which

s located above

gas spread is to 

ggested that an 

Underground

A, Class I wells

equire a permit.

, appears to be

Canada. One area where the regulations differ, however, is that

migration and 

ction. There are 

regulatory and 

nd insight into

integrity of the

th the cap rock

les) and second with the cements in the injection wells (both in existing and

old abandoned wells that are puncturing, or penetrating the reservoir). Of these possible failure modes, 

there is considerable concern with regard to the impact that CO2 alone could have on cements in 

abandoned well bores. Since many oil and gas fields in Canada are penetrated by significant numbers 

of existing and abandoned wells, the potential risk of a failure could be high, which could be enhanced 

ck and injection well 

sing the long-term 

gas.

A key feature of the regulations is protection of groundwater and other energy and mi

and of equity and mineral rights. The classification of the injection wells is based on t

they will hold. Injection wells on acid gas projects are typically considered as Class

AEUB guidelines7

, which covers wells injecting hydrocarbon, inert and sour gases8. It

same well classification for acid gas injection applies to CO2 injected for enhanced

Canada. Testing and cementing requirements for Class Ib, II and III wells are somewh

than f

However Class Ib, II and III wells have to be designed to ensure that useable water be

isolated. 

Possible migration pathways are also an issue in the choice of location of the injection w

it is noted that no subsequent subsurface monitoring is required by the regulatory b

whether migration is occurring. A con

call for the monitoring of vertical leakage by gas migration (if any) towards the aquifer

the reservoir to ensure that leakage remains minimal and acceptable. Also, any lateral

be monitored using a set of monitoring wells10. 

Also noteworthy, is a study undertaken by Battelle for the USDOE11 in which it was su

injection well for CO2 into an aquifer would be Class I under the provisions of the

Injection Control (UIC) programme of the Federal Safe Drinking Water Act. In the US

are wells that inject hazardous or non-hazardous wastes into geological formations and r

Much of the information required in the permit applications for Class I wells in the USA

similar to those for acid gas injection in

in the USA detailed groundwater modelling studies are required to study plume

monitoring will be required of surface water and overlying aquifer used for water abstra

a number of operational acid gas injection operations in the USA - comparison of the US

monitoring requirements with those in Canada might provide additional information a

practices that might be adopted for CO2 storage. 

Another issue could be the reactions of the acid gas and its consequent impact on the

reservoir. There are two possible modes of reaction that could occur, first reaction wi

(which in most cases are sha

by the presence of H2S. The degree of reaction of the acid gas with the cap ro

cements needs to be fully understood, otherwise there is a risk of compromi

containment of the injected

 7

 Alberta Energy Utilities Board, Guide 51, Injection and Disposal Wells – well classifications, completion, 

logging and testing, March 1994. 8

 It is noted in several operations the acid gas is dissolved in the produced water and hence, when injected, the 

well classification becomes IB or II 9

 Fluids to be injected in Class 1a wells include: phenolic waste waters, acid or caustic solutions, aqueous

solutions of halogenated organic compounds, solutions containing heavy metals. 10 IEA Greenhouse Gas R&D Programme File Note on Geological Storage of CO2 - Conflicts with and experience 

to be gained from natural gas storage, 4th January 2001. 11 Project No. DE-RAC26-98FT40418, Carbon Dioxide Sequestration in Saline Formations – Engineering and

Economic Assessment – Final Technical Report, July 9, 2001 

v
vi

Expert Group Comments 

The draft of this report was not sent out to expert review because the previous interim report had been 

reviewed in this way and the experts’ comments have been included in the final report. 

 reservoirs and 

ompared to the 

less there is a 

 that can be drawn upon for reference in connection with wide scale 

gulation of acid 

wells that are 

ation that will 

n, if it can be 

reservoirs, that 

cement integrity in the injection wells has not been compromised and there are no associated 

environmental problems, then this should build confidence that CO2 alone will be stored effectively as 

well. However, at present o demonstrate credible evidence for acid gas 

containment within a geological reservoir without a detailed monitoring programme being undertaken 

at an acid gas injection site. 

tion facility (or 

he development 

of the knowledge of injection of CO2 and other gaseous species. Such a project should consider both 

surface and sub–surface monitoring to provide confidence on containment of the injected gas in the 

reservoir, in particular examining the possibility of any surface migration. The monitoring programme 

should look at the interaction of the injected acid gases with the reservoir rocks, since the extent to 

which the injected H2S might be trapped by mineral fixation is an important question to be resolved. 

Also, the impact on reservoir integrity, in terms of reaction with the cap rock and with the cement of the 

well bore, need to be studied. 

Major Conclusions 

To date, close to 1.5 Mt CO2 and 1 Mt H2S have been injected into deep hydrocarbon

saline aquifers in western Canada. Whilst the quantities of gas injected are modest c

amount of CO2 injected in CO2-EOR operations in the USA and Canada, neverthe

considerable body of knowledge

implementation of CO2 storage in the future. Information and experience exists on the re

gas injection sites and the design and operation of compressors, pipelines and injection 

relevant to larger CO2 storage operations. 

Any operation where gases are injected into geological reservoirs will provide inform

help develop confidence in geological storage of CO2. In the case of acid gas injectio

demonstrated that the injected acid gases have been contained within the geological 

it might be difficult t

Recommendations 

Consideration should be given to developing a monitoring project at a new acid gas injec

at several facilities reflecting the range of reservoirs that are being utilized) to assist in t
Characteristics of Acid Gas Injection Operations 

in Western Canada 

Report to 

International Energy Agency – Greenhouse Gas R&D Programme 

Dr. Stefan Bachu Dr. William D. Gunter 

Alberta Geological Survey Alberta Research Council 

Alberta Energy and Utilities Board 

February 2003 
Contents 

Introduction............................................................................................4 

 Acid gas injection operations...............................................................5 

 Compilation project and report structure.................................................8 

Historical background..............................................................................10 

Site selection and operations.......................................................................13 

 Acid gas properties.........................................................................13 

 Surface operations..........................................................................19 

 Subsurface considerations.................................................................21 

Review of operations in Alberta..................................................................22 

 Subsurface characteristics.................................................................22 

 Licensed operations........................................................................24 

 Surface characteristics.....................................................................24 

Issues..................................................................................................25 

Conclusions..........................................................................................26 

References............................................................................................28 

Appendix.............................................................................................31 

Figures 

Figure 1. Location of the Alberta basin in Canada...............................................4 

Figure 2. Histogram of active acid gas injection operations in the Alberta basin............6 

Figure 3. Location and status of the acid gas injection operations in the Alberta basin, 

 Canada, at the end of 2002................................................................7 

. 

Figure 4. Cumulative amount (all sites) of acid gas approved to be injected, and actually- 

 injected into deep aquifers and reservoirs in the Alberta basin, Canada: 

 a) injection rate, and b) volume.......................................................14 

Figure 5. Cumulative amount (all sites) of approved CO2 and H2S to be injected into deep 

 aquifers and reservoirs in the Alberta basin, Canada: a) injection rate, and 

 b) mass....................................................................................15 

Figure 6. Cumulative amount (all sites) of CO2 and H2S actually-injected into deep 

aquifers and reservoirs in the Alberta basin, Canada, to the end of 2000: 

a) injection rate, and b) mass...........................................................16 

Figure 7. Solubility of water in acid gas as a function of pressure for: a) different acid gas 

 composition (CO2 and H2S) at 30oC, and b) different temperatures for an acid 

 gas with a composition of 49% CO2, 49% H2S and 2% CH4 (see also Lock, 

 1997; Wichert & Royan, 1996, 1997).................................................17 

2
Figure 8. Phase diagrams for methane (CH4), carbon dioxide (CO2), hydrogen sulphide 

(H2S) and a 50%-50% acid gas mixture; hydrate conditions for CO2 and H2S; 

and a 4-stage acid-gas compression cycle (after Wichert & Royan, 1996, 

1997).......................................................................................18 

Figure 9. Size of approved acid gas operations in western Canada: a) injection rate, and 

 b) injection volume.......................................................................27 

Tables 

Table 1. Summary of captured and missing subsurface information for the acid gas 

 injection operations in western Canada................................................9 

Abbreviations 

AEUB Alberta Energy and Utilities Board, the regulatory agency in Alberta, 

 Canada 

AGS Alberta Geological Survey, a Group within AEUB 

ARC Alberta Research Council, a research organization in Alberta, Canada 

B.C. British Columbia, a province in Canada 

EPR Emergency response plan 

EPZ Emergency protection zone 

3
INTRODUCTION 

Over the past decade, oil and gas producers in the Alberta basin in western Canada 

(Alberta and British Columbia) (Figure 1) have been faced with a growing challenge to 

reduce atmospheric emissions of hydrogen sulphide (H2S), which is produced from 

“sour” hydrocarbon pools. Sour oil and gas are hydrocarbons that contain H2S and CO2, 

which have to be removed before the produced oil or gas is sent to markets. Since surface 

desulphurization through the Claus process is costly and the surface storage of the 

produced sulphur constitutes a liability, increasingly more operators are turning to acid 

gas disposal by injection into deep geological formations. Acid gas is a mixture of 

hydrogen sulphide and carbon dioxide (H2S and CO2), with minor traces of 

hydrocarbons, that is the byproduct of “sweetening” sour hydrocarbons. In addition to 

providing a cost-effective alternative to sulphur recovery, the deep injection of acid gas 

reduces emissions of noxious substances into the atmosphere and alleviates the public 

concern resulting from sour gas production and flaring. 

4
Although the purpose of the acid gas injection operations is to dispose of H2S, significant 

quantities of CO2 are being injected at the same time because it is uneconomic to separate 

the two gases. Actually, more CO2 than H2S has been injected to date into deep 

geological formations in western Canada. In the context of current efforts to reduce 

anthropogenic emissions of CO2, the acid gas injection operations in western Canada 

represent a commercial-scale analogue to geological storage of CO2. The latter is an 

immediately-available and technologically-feasible means of reducing CO2 emissions 

into the atmosphere that is particularly suited for land-locked regions located on 

sedimentary basins, such as the North American mid-continent. Large-scale injection of 

CO2 into depleted oil and gas reservoirs and into deep saline aquifers is one of the most 

promising methods of geological storage of CO2, and in this respect it is no different from 

acid gas injection operations. However, before implementation of greenhouse gas 

geological storage, a series of questions need addressing, the most important ones relating 

to the short- and long-term fate of the injected CO2. Thus, the study of the acid gas 

injection operations in western Canada provides the opportunity to learn about the safety 

of these operations and about the fate of the injected gases, and represents a unique 

opportunity to investigate the feasibility of CO2 geological storage. In the 13 years since 

the first operation in the world started injecting acid gas into a depleted reservoir on the 

outskirts of the city of Edmonton in Alberta, no safety incidents have been reported 

except for a well blow-out in northern Alberta where the operator has significantly 

exceeded the permitted injection pressure. Given the H2S nature, which 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 and ready for 

large-scale deployment. The major issues that need addressing in the near future are the 

long-term containment of the injected gases in the subsurface, and the safety of largescale operations. This review of acid gas injection operations in western Canada may help 

in addressing these issues. 

Acid Gas Injection Operations in Western Canada 

In Alberta, the Oil and Gas Conservation Act requires that operators apply for and obtain 

approval from the Alberta Energy and Utilities Board (AEUB), a provincial regulatory 

agency, to dispose of acid gas. Similarly, in British Columbia (B.C.) operators have to 

apply to the B.C. Ministry of Energy and Mines for approval. Before approving any 

operation, the regulatory agencies review the application to maximize conservation of 

hydrocarbon resources, minimize environmental impact and ensure public safety. To 

adequately address these matters, the regulators require that the applicants submit 

information regarding surface facilities, injection well configurations, characteristics of 

the injection reservoir or aquifer, and operations. After approval for acid gas injection is 

granted, the operators have to submit to the regulatory agencies biannual progress reports 

on the operations. No application has been rejected to date; however, in some cases the 

operator had to provide additional information and/or had to make changes to satisfy 

requirements and requests from the regulatory agencies. In some cases the regulatory 

agencies, in granting approval, imposed operating conditions to ensure safety. 

5
The first acid gas injection operation in Alberta was started in 1989, and the next one in 

1994. To date, forty-seven applications for injection of acid gas produced at 42 different 

gas plants have been approved in western Canada (35 in Alberta and 7 in British 

Columbia). The seeming contradiction between the number of applications and number 

of injection operations stems from the fact that in several places injection took or takes 

place in different units, or the quality of the injected stream is different, in which case an 

application has to be submitted and approved for each case. For clarification, in the 

following the different acid gas sources at different gas plants and land locations are 

designated as acid gas operations, and the injection cases themselves are referred to as 

injection sites. The Appendix presents the captured information by injection site, and not 

by operation. 

Of the 42 approved operations, 39 were active as of December 2002. One operation, in 

the Pembina field west of Edmonton in Alberta, although approved, was never 

implemented by the operator. Two other operations, also in Alberta, have been rescinded 

after an active period, either because the injection volumes reached the approved limit, 

and the operator moved to another site or injection formation, or because the gas plant 

producing the acid gas has been decommissioned, with the sour gas being processed at 

another, nearby plant. At the Zama operation with multiple sites in northern Alberta, 

injection into two reefal carbonate reservoirs has been shut down in 1998 and 2000 by the 

regulatory agency because the operator greatly exceeded the approved injection volume 

or pressure. Figures 2 and 3 present, respectively, the histogram and location of acid gas 

injection operations in western Canada at the end of 2002. 

6
   

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7
Compilation Project and Report Structure 

In January 2002, the Alberta Geological Survey (AGS), a group in the Alberta Energy 

and Utilities Board, and the Alberta Research Council (ARC), jointly undertook a project 

funded by Canadian federal and provincial governments and agencies, and by the 

International Energy Agency (IEA) Greenhouse R&D Programme, to review the 

information submitted to the AEUB by operators in the process of obtaining approval for 

and running the acid gas injection operations active in Alberta prior to December 2001. 

The original deadline of the project was September 2002. In June 2002, the first industry 

participant joined the project, at which time the funding sponsors agreed to expand the 

scope of the project to include the 7 acid gas injection operations active in British 

Columbia and 4 additional acid gas operations approved in Alberta since December 2001. 

Concomitantly, the project deadline was extended to March 31, 2003. 

The Alberta Geological Survey compiled the subsurface characteristics and the Alberta 

Research Council compiled the surface facilities of the acid gas operations. Historical 

files with the respective regulatory agencies in Alberta and British Columbia were 

searched for applications for acid gas injection operations, for approvals and 

amendments, and for the subsequent progress reports submitted by operators. Relevant 

information from these hard copy documents was entered into a database specially 

designed and implemented at AGS for internal use and report generation. Several 

synthesis tables were generated that compile and present information from the acid gas 

injection sites. A series of self-explanatory graphs were produced on the basis of the 

synthesis tables, which are grouped into 3 categories: host rock, host fluids and injection 

operations. These reports and associated graphs are included in the Appendix. 

Because the suitability for and approval of acid gas injection operations are determined 

by the characteristics and containment properties of the injection aquifer or reservoir, 

which then affect operation and engineering characteristics, the review is summarized in 

Tables 1 to 6 in the Appendix in the following order. Table 1 shows the geology of the 

injection unit and of the underlying and overlying formations. Table 2 summarizes the 

characteristics of aquifer and reservoir rocks and fluids. Table 3 summarizes licensed 

operating parameters, such as injection pressure, rate and volumes, and the radius of the 

emergency protection zone (EPZ). The latter is established for the case of an atmospheric 

release of acid gas, either as a result of an escape to the surface from the injection zone, 

or as a result of failure in surface facilities. In Table 3, the licensed injection rate and 

volume for sites 4336 and 4343 of the same operation is the same, as explained in the 

footnote, although injection takes place through two different wells approximately 4.5 km 

apart, one for acid gas mixed with water and the other one for dry gas. Tables 4, 5 and 6 

summarize engineering characteristics of the acid gas injection operations, such as: 

injection wells, pipelines, and gas plant compressors, respectively. Tables 1-3 have only 

47 lines each, corresponding to the 47 injection sites, while Tables 4-6 have more lines 

because there are injection operations with multiple wells and pipelines and/or 

compressors. Common to each table is a site number or plant (operation) number. The 

two designations were necessary because one plant compressor train could serve several 

injection sites, and at each injection site there could be several injection wells. The plant 

8
designation number ends in “00”. The non-zero integers making up the plant number are 

the group indicator for the sites belonging to that particular plant. For example, plant 

number 1500 refers to site numbers 1510, 1522, and 1563 in the tables. Lack of data or 

information in the original applications is denoted in the Appendix tables by a blank (i.e., 

no data were submitted), and the absence of the data should definitely not be construed as 

a compilation omission. If a data category does not apply to a certain case, such as water 

salinity for an oil reservoir, or oil gravity for an aquifer, then NA (not applicable) is used. 

With regard to the reviewed documentation, this report contains all the information 

currently existing with the regulatory agencies in Alberta and British Columbia. 

Documentation is missing (does not exist) for two sites (sites 2469 and 3465 in the 

Appendix) because these initially did not require an acid-gas application since they were 

originally water disposal operations that changed later on to “sour-water”. 

Table 1. Summary of captured and missing subsurface information for the acid gas injection operations in 

western Canada. 

Information Type # Sites with # Sites w/o NA % Missing Information

Depth 46 2 5 

Thickness 44 4 8 

Lithology 47 1 2 

Porosity 42 6 13 

Permeability (DST) 4 44 92 

Flow capacity 27 21 44 

keff gas 7 41 85 

Permeability (est) 15 33 69 

Fracture gradient 41 7 15 

Net pay 43 5 10 

Caprock formation 44 4 8 

Caprock thickness 41 7 15 

Caprock lithology 43 5 10 

Underlying formation 38 10 21 

Thickness of und. Form. 29 19 40 

Lithology of und. Form. 38 10 21 

Temperature 41 7 15 

Pressure 46 2 4 

Volume 34 14 29 

Salinity 24 24 50 

Oil gravity 8 3 37 6 

Gas weight 17 31 

Initial pressure 38 10 21 

Startup pressure 21 5 22 10 

Table 1 above presents a summary of the captured information for the 47 acid gas 

injection operations in western Canada. It must be emphasized here that the information 

9
presented herein is “as submitted” by the operators, with no additional checking and 

interpretation by AGS and/or by staff in the regulatory agencies, except for evidently and 

blatantly wrong data. The data were adequately checked for data-entry accuracy, but were 

not checked for validity. Any data inconsistencies reflect the data and information as 

submitted by operators. Missing data for some sites are due to the lack of submissions by 

operators, or to unavailability within the regulatory agency. In cases that data and 

information were not submitted, no additional search was performed to fill in from other 

sources. Currently, on aggregate, approximately 25% of the required information is 

missing (Table 1). No analysis of the compiled information is included in the current 

report, whose objective, as stated, was only to compile the information currently existing 

with regulatory agencies. The verification of the submitted information, the collection of 

additional data and the analysis of the information form the objective of another project 

phase. 

HISTORICAL BACKGROUND 

A significant portion of raw natural gas production in the Alberta basin, Canada, contains 

varying percentages of acid gas components, specifically hydrogen sulphide (H2S) and 

carbon dioxide (CO2). To meet pipeline and sales gas specifications, this raw sour natural 

gas must pass through gas processing facilities to separate out the acid gas components. 

Furthermore, a number of sour oil pools produce solution gas that contains significant 

amounts of H2S and CO2 (e.g., 4% and 17% respectively at Wayne–Rosedale; Ho et al.,

1996). Prior to 1988, if sulphur-recovery technology could not economically remove the 

sulphur from the acid gas, the alternative was to burn the acid gas in flare stacks or 

incinerators. Each flaring source was permitted to emit up to 10 t/d of sulphur. To reduce 

the waste and pollution resulting from sour-gas flaring, regulatory agencies in Alberta 

and British Columbia require since 1989 that gas plants with a sulphur throughput of 

more than 1 t/d recover the sulphur from the gas stream (Longworth et al., 1996). The 

amount of recovered sulphur increases from 70% for plants producing 1 to 5 t/d, to 96% 

for plants producing more than 10 t/d. Nevertheless, even with sulphur recovery in place, 

significant volumes of tail, or acid gas, are generated, and this is often flared from stacks 

at the well sites. In the early 1990s, the yearly average emission from gas flaring in the 

Alberta basin was in the order of 0.3 Mt SO2 and 6 Mt CO2 (Longworth et al., 1996). 

Until the late 1980s and early 1990s, sulphur recovery and acid gas flaring were 

considered the most economic ways of dealing with the sulphur in sour and acid gases. 

As a result of public concern about flaring, including environment degradation, human 

and animal health, and waste, the regulatory agencies increasingly require that operators 

reduce emissions, particularly in regions where the public concern is high. Because the 

sulphur world supply is dominated by recovered sulphur and environmental pressure has 

driven desulphurization to the point that the supply has exceeded demand, large tonnages 

of sulphur are being poured into block storage throughout the world (Connock, 2001), 

including the Alberta basin. Since desulphurization is uneconomic in a weak sulphur 

market, and flaring is publicly unacceptable, operators in the Alberta basin are 

increasingly turning to acid gas disposal through injection into deep subsurface 

formations, mostly in saline aquifers, but also in depleted oil and gas reservoirs. The on10
site geological disposal is particularly attractive if, otherwise, operators have to build 

their own sulphur recovery plant or a pipeline to the nearest plant with available capacity, 

each alternative having its own difficulties or undesirable effects, such as cost, economic 

risk, pipeline right of way, and plant proliferation (Keushnig, 1995). 

The acid gas injection sites in the Alberta basin are by and large located mostly in the 

region close to the Rocky Mountain thrust and fold belt that corresponds to sour gas 

production from deep reservoirs (Figure 3). Two sites in B.C. are actually located within 

the thrust and fold belt. At 26 sites approval was given to inject the acid gas into deep

saline aquifers in regional-scale flow systems confined by regional-scale aquitards. At 17 

sites injection took or takes place in depleted oil and/or gas reservoirs, and at 4 sites the 

acid gas is injected into the underlying water leg of depleted oil and gas reservoirs (sites 

designated as “reservoir” in the Appendix, but with “water” as the reservoir fluid). The 

acid gas could increase oil or gas recovery if it is injected to maintain reservoir pressure 

(Longworth et al., 1996; Connock, 2001). Because site selection and approval must meet 

a set of stringent requirements imposed by regulatory agencies to address H2S emissions 

(Keushnig, 1995; Longworth et al., 1996), the sites meet also the criteria for and are 

located in areas suitable for CO2 storage in geological media in the Alberta basin (Bachu, 

2000; Bachu & Stewart, 2002). 

In 1989, Chevron Canada Ltd. started the first acid-gas injection operation at Acheson 

(site 3340 in the Appendix), on the outskirts of Edmonton in Alberta, designed to handle 

a mixture of 15% H2S and 85% CO2 by injecting it at a depth of 1100 m into a depleted 

sandstone oil reservoir (Lock, 1997). The operation experienced elemental sulphur 

deposition, which plugged the injection well (Longworth et al., 1996). The next 

operation, by a different company, started in 1994 by injecting 20% H2S and 80% CO2

into a water-saturated carbonate reef in central Alberta. Also in 1994, Chevron Canada 

Ltd. started acid gas injection at 30 MPa pressure into a carbonate aquifer 2800 m deep at 

Pembina, west of Edmonton. The approved acid gas composition is 74% H2S, 21% CO2, 

1% hydrocarbon gases and 4% water (Lock, 1997). 

In 1995, PanCanadian Petroleum Ltd. started mixing, at surface, acid gas with produced 

water at elevated pressure, and injected the solution (“sour water”) into a water-saturated 

sandstone zone underlying an oil pool at Hansman Lake (site 3581 in the Appendix), and 

into a deep, dolomitized carbonate-shelf aquifer at Thompson Lake in eastern Alberta 

(Kopperson et al., 1998a,b). Both injection zones are overlain by shales. The sandstone 

aquifer has high porosity (30% on average) and permeability (up to several darcies, 

or 10-12 m2), while the carbonate zone has 22% porosity. Also in 1995, PanCanadian 

started an acid-gas injection operation at Wayne-Rosedale, northeast of Calgary in 

Alberta (site 3195 in the Appendix). The acid gas mixture (20% H2S and 80% CO2), with 

an estimated daily production rate of 21,000 m3/d, was the result of sweetening a 34oAPI 

oil with an associated solution gas containing 4% H2S and 17% CO2 (Ho et al., 1996). 

Injection takes place in a 26 m water-saturated carbonate-reef unit, characterized by 6% 

porosity, 150 x 10-15 m2

 (150 md) permeability, 65oC temperature and 15.5 MPa 

formation pressure, confined by tight dolomite units. At in-situ conditions, the acid gas 

density is ~543 kg/m3 (Ho et al., 1996). 

11
In 1995, Pennzoil Canada Inc. started injecting a mix of 20% H2S and 80% CO2 at 

120,000 m3/d into a depleted oil reservoir in a pinnacle carbonate reef ~1510 m deep at 

Zama X2X in northern Alberta (site 1563 in the Appendix). Because the acid gas was 

miscible with oil in that reservoir, at one point during the operation it was used in 

conjunction with a miscible-flood scheme to enhance the oil recovery (Davison et al., 

1999). The ~115 m dolomitized reef, with an average porosity of 7.6%, is underlain by 

~45 m of tight lime mudstone and is overlain by 60 to 90 m of anhydrite. The critical 

point of the acid gas mixture is 42o

C and 7.64 MPa. At target operating conditions of 

14.5 MPa and 76o

C (initial reservoir pressure and temperature), the injected acid gas is 

supercritical, with a density of ~500 kg/m3 and a viscosity of 0.04 cp (Davison et al., 

1999). The caprock threshold displacement pressure was measured in the laboratory to be 

22.3 MPa. Considering that the initial differential pressure across the caprock was ~7 

MPa, the maximum operating pressure was established at 30 MPa. Because the formation 

water naturally contains significant amounts of both CO2 and H2S, acid gas injection was 

not expected to cause dissolution of reservoir rock and/or precipitation. This site was 

subsequently shut down by AEUB because the operator greatly exceeded the injection 

pressure limit. 

To date, the largest operation in the Alberta basin in British Columbia (sites 4336 and 

4342 in the Appendix) is also the largest in the world, with a licensed capacity of 391,000 

m3/d, but operating only at 280,000 m3/d. Acid gas is injected into the same formation 

through two wells some 4.5 km apart, because dry gas is injected through one (site 4336) 

and acid gas mixed with water is injected through the other (site 4343). The acid gas 

stream contains 85% H2S and 15% CO2 (340 and 78 t/d H2S and CO2, respectively), and 

the approved injection rate and volume are for both wells. 

The acid gas is or was mixed with water at surface, prior to injection, at the following 

sites: 718, 997, 2469, 2573 (up to 1999), 3465 and 3581. Sites 2469 and 3465 are actually 

water disposal sites with a minor amount of dissolved acid gas (“sour water” disposal) 

and injection at these sites is done “randomly” through 49 and 19 wells, respectively. 

Because these are water disposal schemes approved previously as such, the operators did 

not have to submit a special application to the regulatory agency to inject sour water. 

Operations at two sites, 997 and 3581, were rescinded in 1997 and 1998, respectively, 

either because the injection volumes reached the approved limit, and the operator moved 

to another site or injection formation, or because the gas plant producing the acid gas has 

been decommisioned. Injection at site 312 was rescinded in 1999 because it reached the 

approved limit, and it was immediately replaced by injection into an underlying 

formation (site 320 in the Appendix) Injection at sites 1510 and 1563 at Zama into 

depleted reservoirs (Figure 3) were shut down by the regulatory agency in May 1998 and 

December 2000, respectively, because the operator greatly exceeded the approved 

injection volume or pressure. Injection for that acid gas operation continues into an 

aquifer (site 1522). One operation in the Pembina field (Figure 3; site 844 in the 

Appendix), although approved, was never implemented. 

12
Currently, acid gas injection in the Alberta basin occurs over a wide range of aquifer and 

reservoir characteristics, acid-gas composition, and operating conditions. The 

composition of the injected acid gas varies from site to site, from 85% H2S and 15% CO2

to 2% H2S and 98% CO2. Figure 4 presents the variation since 1989 of the approved and 

actual injection rates and volumes, cumulative for all active acid gas injection operations 

in western Canada. Figure 5 shows the corresponding approved injection rates and 

volumes of H2S and CO2, also cumulative for all sites. The drop in the cumulative 

approved injection rate and the leveling-off in approved injection volumes in 1999-2000 

(Figures 4 and 5) corresponds to the shut down of the two injection sites, 1510 and 1563, 

for injecting beyond the licensed limits. The actual injection rates and volumes are 

significantly below the approved limits (Figure 4). In 2000, the last year with complete 

records, the actual cumulative injection rates for CO2 and H2S in the Alberta basin 

reached 0.26 and 0.20 Mt/yr, respectively, with a total of 1.1 Mt CO2 and 0.6 Mt H2S 

injected to date (Figure 6), driven by the need to dispose of H2S driven by the need to 

dispose of H2S. All the injection rates and volumes presented in this report are at standard 

conditions (15o

C and 101.3 kPa). 

SITE SELECTION AND OPERATIONS 

In Alberta, applications for acid gas disposal must conform to the specific requirements 

listed in Chapter 4.2 of Guide 65 that deals with applications for conventional oil and gas 

reservoirs (AEUB, 2000). Requirements in B.C. are modeled after those in Alberta. The 

selection of an acid-gas injection site needs to address various considerations that relate 

to: proximity to sour oil and gas production that is the source of acid gas; confinement of 

the injected gas; effect of acid gas on the rock matrix; protection of energy, mineral and 

groundwater resources; equity interests; wellbore integrity and public safety (Keushnig, 

1995; Longworth et al., 1996). The surface operations and the subsurface aspects of acid 

gas injection depend on the properties of the H2S and CO2 mixture, which include, but 

are not limited to non-aqueous phase behavior, water content, hydrate formation and the 

density and viscosity of the acid gas (Carroll & Lui, 1997; Ng et al., 1999). Knowledge 

of the phase equilibria for acid gas allows the optimization of the injection process while 

addressing corrosion, hydrate formation and compressor-outlet pressure concerns. 

Acid Gas Properties 

The acid gas obtained after the removal of H2S and CO2 from the sour gas may also 

contain 1% to 3% hydrocarbon gases, and is saturated with water vapor in the range of 2 

to 6%. In general, the ability of acid gas to hold water increases with temperature and 

decreases with the addition of small amounts of methane. However, unlike the case of 

hydrocarbon gases, 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 (Figure 7). The solubility minimum reflects the pressure at which 

the acid gas mixture passes into the dense liquid phase form, where the solubility of water 

can increase substantially with increasing pressure due to the molecular attraction 

between these polar compounds (Wichert & Royan, 1996, 1997). This property of the 

acid gas mixture is used in dewatering the acid gas, to avoid pipe and well corrosion, by 

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compressing the gas from about 100 kPa to around 8 to 10 MPa for injection, and 

reducing thus the water content to less than half a mole % (Wichert & Royan, 1996, 

1997). 

While there are not many published properties of the acid gas mixture, the properties of 

pure CO2 and H2S have been thoroughly examined and reported. In their pure state, CO2

and H2S have similar phase equilibria, but at different pressures and temperatures 

(Carroll, 1998a). They exhibit the normal vapour/liquid behavior with pressure and 

temperature (Figure 8), with CO2 condensing at lower temperatures than H2S. Methane 

(CH4) also exhibits this behavior, but at much lower temperatures. The phase behavior of 

the acid gas binary system is represented by a continuous series of two-phase envelopes 

(separating the liquid and gas phases) located between the unary bounding systems in the 

pressure-temperature space (Figure 8). If water is present, both CO2 and H2S form

hydrates at temperatures up to 10oC for CO2 and more than 30oC for H2S (Carroll & Lui, 

1997). If there is too little water, the water is dissolved in the acid gas and hydrates will 

generally not form. However, phase diagrams show that hydrates can form without free 

water being present (Carroll, 1998a,b), thus operating above the hydrate-forming 

temperature is desirable.

The properties of the acid gas mixture are important in facility design and operation 

because, to optimize storage and minimize risk, the acid gas needs to be injected: (1) in a 

dense-fluid phase, to increase storage capacity and decrease buoyancy; (2) at bottom-hole 

18
pressures greater than the formation pressure, for injectivity; (3) at temperatures in the 

system generally greater than 35oC to avoid hydrate forming, which could plug the 

pipelines and well; and (4) with water content lower than the saturation limit, to avoid 

corrosion. 

Surface Operations 

The sweetening of sour gas takes place at gas processing plants where the natural gas is 

processed to reach pipeline and sales specifications. A variety of solvents, solvent 

mixtures and processes are available for gas sweetening; and the selection of the 

optimum solvent or solvent mixture, and process depends on a variety of factors such as 

sour gas composition, pipeline specification, and compression requirements. In western 

Canada, the gas sweetening processes employ amines or amine derivatives as the 

chemical solvents of choice. In the sweetening process, after separation of any gas 

liquids, the sour gas is flowed through a contactor or absorber tower in a one- or twostage process where the sour gas typically comes in contact with an amine or amine 

derivative solution. The amine or its derivative reacts with the acid gas, dissolving it, 

trapping it in the water phase and allowing the sweet components of the natural gas to 

pass on through. By the time the natural gas reaches the top of the tower, all of the CO2

and H2S should have been absorbed by the amine solution. Because the cost of the 

separation step is a major part of the acid gas injection operation, amine solvent mixtures 

are being optimized to increase the efficiency of the process, better amine forms are 

being developed, and other solvents are being used in multi-stage separation processes 

(chemical solvents – e.g. K2CO3; physical solvents – e.g. Selexol). 

After separation, the gas is now sweet, meeting pipeline and market specifications for 

allowable acid gas content. The gas-saturated amine solvent is collected from the bottom 

of the tower and is regenerated by heating the aqueous solution to approximately 170oC. 

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

be cooled and then compressed in excess of the subsurface storage formation pressure for 

injection. Typically, four stages of compression are required to provide the required 

discharge pressure (Figure 8). During compression, the acid gas mixture heats up and, 

therefore, cooling is required after each stage of compression. It is desirable to keep the 

compression cycle at a higher temperature than the stability field for hydrates to prevent 

compressor breakdown and plugging. The hydrate-forming temperature at any pressure 

of an acid gas increases with increasing content of H2S. In the limit, compression 

temperatures maintained above 35o

C will avoid hydrates forming (Figure 8). 

Even if hydrate forming is avoided, excess water accelerates corrosion of the steel in 

contact with the acid gas, and ultimately this is the main reason why dehydration of the 

acid gas is needed. By the 4th stage in a cycle (Figure 8), compression will tend to 

dewater the acid gas up to a maximum pressure between 3 and 5 MPa (Figure 7) if there 

are no hydrocarbon impurities present. Further compressing the acid gas to higher 

pressures increases the solubility of water in the acid gas, such that any residual excess 

water dissolves into the acid gas, and more than counteracts the decrease in solubility due 

to interstage cooling. Hence, a separate dehydration step may not be needed because no 

19
free-water will be present in the system (Clark et al., 1998). Thus, by collecting the 

condensed water during each compression stage and by keeping the temperature a few 

degrees above the hydrate stability temperature, the probability of hydrate formation and 

corrosion are minimized, and lower-quality, less expensive steels can be used for 

transporting the acid gas mixture to the subsurface storage formation. 

To avoid pump cavitation, the acid gas must not enter the two-phase region during 

compression. Higher temperatures, although required in the process to avoid hydrate 

formation and plugging of the lines, lead to accelerated corrosion. Both plugging and 

corrosion can lead to containment failure. Additional safety precautions require addition 

of chemical inhibitors to the acid gas stream (e.g., methanol to lower hydrate formation 

temperatures, and glycol to extract the excess water from the acid gas stream) or use of 

special corrosion-resistant steels. Both add to the cost of the operation. Corrosion 

monitoring is normally done to assess the effectiveness of the treatments. 

Once the acid gas is compressed, it is transported through a pipeline to the injection 

wellhead usually at a short distance from the gas plant. The well consists of a central steel 

tubing string with an outer annulus bounded by a steel casing that is cemented to the 

subsurface formations. The acid gas flows down the well tubing and into the subsurface 

storage formation through perforations in the well casing. The discharge pressure from 

the compressor must exceed the sum of: formation pressure minus the pressure-head in 

the well tubing (weight of the fluid column), the pressure loss or gain due to elevation 

change from the compressor to the well head, and all the pressure losses along the way 

from the compressor into the formation (due to friction in the pipeline to the wellhead 

and in the tubing string, and across perforations). Ultimately, the discharge pressure must 

consider the desired injectivity into the subsurface storage formation, which depends on 

the thickness and permeability of the formation and on the viscosity and density of the 

acid gas at in situ conditions. The high pressures after the fourth compression stage 

stabilize, upon cooling, the high-density liquid-phase of the acid gas, which can have a 

density of approximately 75% of the density of water, providing the hydrocarbon content 

is not greater than approximately 2%. Considering that in most cases the pressure of the 

subsurface injection formation is near hydrostatic, the hydraulic head provided by the 

acid gas provides a significant amount of the total pressure required to inject it into the 

subsurface formation. 

Several safety features are generally incorporated in the injection well to prevent leakage. 

The casing is isolated from the tubing string and the acid gas by installing a packer in the 

annulus between the casing and the tubing string just above the subsurface storage 

formation, which is pressure tested for integrity once a year. A down-hole safety valve or 

a check valve can be incorporated in the tubing string so that if equipment fails at surface, 

the back-flow of acid gas from the formation to the surface will be prevented. The 

wellhead of the injection well is similarly protected with valves. Other safety measures 

can be taken if needed. 

Although a number of safety valves are always installed, both in the well and in the 

surface facilities, to be able to isolate the containment lines for the acid gas injection 

20
system into small volumes, the release of even small volumes of acid gas can be harmful. 

Consequently, the operators are required to have a detailed emergency response plan 

(ERP) if a leak occurs that may impact humans. An emergency planning zone, the EPZ 

(i.e. area of land which may be impacted by the release of H2S), is defined around the 

sour gas facility. To have an effective ERP, the area surrounding the injection site should 

be equipped with H2S detection and alarm systems, windsocks, self-contained breathing 

apparatus, and remote unit and plant shutdown stations. 

Subsurface Considerations 

The general location for an acid-gas injection well is often influenced by the proximity to 

sour gas oil or gas production facilities that are the source of acid gas. The specific 

location is based on a general assessment of the regional geology and hydrogeology, 

which is designed to evaluate the potential for leakage (Longworth et al., 1996) and 

which includes: 

1. size of the injection zone, to confirm that it is large enough to volumetrically hold all 

of the injected acid gas over the project lifetime; 

2. thickness and extent of the overlying confining layer (caprock), and any stratigraphic 

traps or fractures that may affect its ability to contain the acid gas; 

3. location and extent of the underlying or lateral bounding formations; 

4. folding or faulting in the area, and an assessment of seismic (neotectonic) risk; 

5. rate and direction of the natural flow system, to assess the potential for migration of 

the injected acid gas; 

6. permeability and heterogeneity of the injection zone; 

7. chemical composition of the formation fluids (water for aquifers, oil or gas for 

reservoirs); 

8. formation temperature and pressure; 

9. analyses of formation and caprock core (if available); and, finally, 

10. a complete and accurate drilling history of offsetting wells within several km of the 

injection well, to identify any wells or zones that may be impacted by the injected 

acid gas. 

In addition to the above technical requirements, the regulatory agencies require that 

environmental concerns must be addressed, such as injection-formation suitability, 

wellbore integrity, operating parameters (to ensure formation and well integrity), and 

optimization of the injection space, considered to be a limited resource. Disposal wells in 

the Alberta basin are classified into four classes, depending on the nature of the injected 

fluid (AEUB, 1994). Class Ia wells are used for the disposal of oilfield or industrial waste 

fluids. Class Ib wells are used for the disposal of produced water and common oilfield 

waste streams. Class II wells are used for the disposal of brine and brine-equivalent 

fluids. Class III wells are used for the injection of hydrocarbons, or inert or other gases. 

Class IV wells are used for injection of potable water or steam. The classification serves 

to define well completion requirements. Because of the nature of acid gas injection 

operations, the wells are considered as Class III disposal wells, unless the acid gas is 

dissolved in produced water prior to injection, in which case the well is designated as 

21
either Class Ib or Class II, depending on the produced-water designation (AEUB, 1994). 

Completion and logging requirements are similar for Class II and III wells, and include: 

1. all geological zones must be identified using logs and/or cores; 

2. all potential hydrocarbon-bearing zones and the shallow potable groundwater 

aquifers must be hydraulically isolated by cement; 

3. injection must be through tubing, and the annulus must be filled with a corrosioninhibiting fluid; 

4. hydraulic isolation and cement integrity must be confirmed by a full-length casing 

log; and 

5. safety devices must be installed both above the ground and in the well bore to ensure 

that failure of any component in the system does not result in environmental damage. 

If the injection pressure drops for any reason, the well is automatically shut-in, to prevent 

acid gas backflow. 

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 from the injection zone to 

other formations, shallow groundwater and/or the surface. These potential pathways are 

of three types: the caprock pore space (“membrane”), natural and/or induced fractures 

(“cracks”) through the confining strata, and improperly completed and/or abandoned 

wells (“punctures”). To avoid diffuse gas migration through the caprock pore space, the 

difference between the pressure at the top of the injection aquifer or reservoir and the 

pressure in the confining layer must be less than the caprock threshold displacement 

pressure, which is the pressure needed for the acid gas to overcome the capillarity barrier 

and displace the water which saturates the caprock pore space. To avoid acid gas 

migration through fractures, the injection zone must be free of natural fractures, and the 

injection pressure must be below a certain threshold to ensure that fracturing is not 

induced. The maximum bottomhole injection pressure is set by regulatory agencies at 

90% of the fracturing pressure. In the absence of site-specific tests, the pressures are 

limited by pressure-depth correlations, based on basin-wide statistical data for the Alberta 

basin. From this point of view, injection into a depleted oil or gas reservoir has the 

advantages of injection pressures being low and of wells and pipelines being already in 

place (Keushnig, 1995). 

REVIEW OF OPERATIONS 

All references to tables in the following are to Tables 1-6 in the Appendix. 

Subsurface Characteristics 

The depth of the injection zone varies mostly in the 1100-2300 m range, although in a 

few cases it is as shallow as 705 m, and as deep as 3478 m (Tables 1 and 2). The shallow 

injection zones (i.e. at 705 m, 809 m and 913 m depth) correspond actually to sour water 

injection. The thickness of the injection zone, as defined geologically, varies between 4 

and 276 m; however, the actual net pay, defined by rocks with porosity and permeability 

22
adequate for injection, reaches only 100 m. At 26 sites the acid gas is injected into a deep 

saline aquifer, and at 17 sites it is injected into a depleted oil or gas reservoir, and at 4 

sites in the water leg underlying a reservoir. Of these, 28 are in carbonate rocks and 19 

are in sandstones (Table 1). Shales constitute the overlying confining unit (caprock) in 

most cases, although tight limestones, evaporites and anhydrites are also present. Their 

thickness varies between 2 and 270 m. (Table 1). The porosity of the injection zone 

varies between 4% and 30% (Table 2). The carbonate rocks generally have low porosity, 

except for carbonate reefs. Only the porosity of sandstone rocks displays a general trend 

of decreasing porosity with increasing depth. Rock permeability is indicated for less than 

half of the sites cases and varies from as low as 0.55 mD to as high as 10,400 mD, 

although most values are of the order of 101

-102 mD (Table 2). 

Formation temperature varies between 35o

C at 1397 m depth and 110oC at 3432 m depth 

(Table 2), although higher temperatures than the lowest one are recorded at shallower 

depth (e.g. 56oC at 1138 m), and a relatively low temperature (82oC) is indicated for a 

deep injection zone (2450 m). The relatively wide spread in temperature variation with 

depth for the acid-gas injection zones is due to the variability in geothermal gradients 

across the Alberta basin, which exhibits a trend of increasing gradients from the south, 

where they are as low as 20oC/km, to the north, where they reach more than 50oC/km 

(Bachu, 1993). 

The original formation pressure is generally subhydrostatic with respect to freshwater, 

which is characteristic of the Alberta basin (Bachu, 1999), and, except for one very low 

case of 5915 kPa that actually corresponds to a sour water injection operation, varies 

between 8900 kPa and 35,860 kPa (Table 2). The cases where the pressure seems to be 

slightly above hydrostatic correspond actually to high salinity formation waters. If the 

real formation water density is taken into account, then pressure at all sites is hydrostatic 

or less. 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 (Table 2). Production-induced drawdown 

occurs also in the case of injection into an aquifer underlying an oil pool, and into an 

aquifer located very close to an oil pool. In 10 cases the formation pressure at start up 

was below the critical pressure of CO2. 

Generally, formation waters are very saline, with salinity varying in a very wide range, 

from ~24,000 mg/l to ~341,000 mg/l (Table 2). Although there is a broad trend of 

increasing salinity with depth, exceptions are due to injection zones being either 

characterized by fresher water influx, or in the vicinity of evaporitic beds. The very high 

salinity encountered at a relatively shallow depth corresponds to injection into a 

carbonate aquifer in eastern Alberta overlain by thick halite beds. For the case of acid gas 

being injected into depleted oil reservoirs, the oils are medium to very light (33o

API to 

68oAPI) (Table 2). Because acid gases will likely have a lower minimum miscibility 

pressure (MMP) than conventional hydrocarbon gases, their use in enhanced oil recovery 

often warrants consideration, as was done in the case of one of the Zama sites (Davison et 

al., 1999). Reservoir gases are generally light (specific gravity less than 0.75) except for 

23
four cases of 0.851, 0.915, 1.024 and 1.121 (Table 2). Because acid gas is generally 

heavier than these reservoir gases, consideration may be given also for its use in 

enhanced gas recovery. 

Licensed Operations 

The licensed parameters for the acid gas operations are listed in Table 3. The composition 

of the acid gas licensed for injection varies between 15% CO2 and 85% H2S, and 98% 

CO2 and 2% H2S, with C+ gases for the balance. The maximum approved well-head 

injection pressure (WHIP) and bottom hole injection pressure (BHIP) reach 19,000 kPa 

and 37,400 kPa, respectively. The maximum approved well head pressure (WHIP) is 

generally lower than the formation pressure, except for the few cases where the injection 

reservoir has been depleted prior to operations start up. The maximum approved bottom 

hole injection pressure (BHIP) is always higher than the formation pressure, to ensure 

injectivity. Approved daily injection rates vary between 2,800 and 900,000 m3

/day, and 

maximum allowed injection volumes vary between 6⋅106 and 1,876⋅106 m3. Operation 

lifetime ranges generally from 10 to 25 years. In the case of the 2.8 years life-time 

operation (Table 3), the operator has indicated in the original application that it will seek 

approval for another site in due time. Emergency planning zones in case of an accidental 

acid gas escape into the atmosphere vary between as small as 40 m and as large as 8.5 km 

around the injection well. 

Surface Characteristics 

Injection well characteristics are listed in Table 4. Casing depths range from 856 to 3,334 

meters. Casing diameter ranges from 114 to 244 mm, while the tubing diameter ranges 

from 60 to 178 mm. The annulus fluid is sealed by a packer and is corrosion inhibited by 

being filled with either fresh water, KCl water, produced water, crude oil, or diesel. 

Pipeline characteristics are compiled in Table 5. 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 4 to 11 mm. Typically, 

only the shorter pipelines are stainless steel. The majority of the pipelines are mild carbon 

steel. Currently, stress levels in the pipeline are less than half the approved levels, and do 

not exceed 30%, while licensed levels are as high as 61%. 

No attempt has been made to compare the sweetening steps for the sour gas stream for 

the different sites. The comparison starts at the compression stage, where the acid gas 

stream has been concentrated to a mixture of H2S and CO2, with accessory water vapour 

and hydrocarbon components. Table 6 summarizes the characteristics of the gas plant 

compressors. The majority of the compressors are diesel. Four-stage compression 

dominates, with power ranging from 50 to 4000 HP. The design discharge rate of the acid 

gas stream ranges from 7,000 to 800,000 m3

/day (i.e. flow rates through the 

compressors). Generally, the rates of injection actually used are close to the maximum 

approved rates. However, this is not true for the compressor discharge pressures. They 

are generally more than 25% lower than the maximum approved wellhead injection 

24
pressure (WHIP). Maximum wellhead injection pressures range from 2.8 MPa to 8.9 

MPa. In the majority of cases dehydration is supplied by the compression cycle as 

discussed previously, and only in a few cases triethylene glycol, refrigeration or a 

desiccant is used. Generally, the compressed acid gas is injected in a pressuretemperature 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. 

ISSUES 

Critical issues are for the most part environmental and safety-related, and they directly 

affect the economics of acid gas injection. Either a slow or rapid acid gas leak can result 

in loss of life or contamination of the bio- and atmosphere leading to degradation of the 

environment. Surface safety is addressed through engineering, installation of safety 

valves and monitoring systems, and emergency procedures in case of H2S leaks. 

Subsurface issues are of two inter-related categories: the effect of the acid gas on the rock 

matrix and well cements, and plume containment. 

When the acid gas contacts the subsurface formation, it will readily dissolve in the 

formation water in an aquifer, or connate water in a reservoir, and create weak carbonic 

and sulphuric acids. This leads to a significant reduction in pH that accelerates water-rock 

reactions. Depending on mineralogy, rock dissolution or precipitation may occur, 

affecting the porosity and permeability of the host rock. The fact that both CO2 and H2S 

are dissolving in the formation water leads to some complex reaction paths (Gunter et al., 

2000; Hitchon et al., 2001) where carbonates precipitate and dissolve, and 

pyrite/pyrrhotite precipitates. Dissolution of some of the rock matrix in carbonate strata, 

or of the carbonates surrounding the sand grains in sandstone units results in lower 

injection pressures in the short term. A major concern with the injection process is the 

potential for formation damage and reduced injectivity in the vicinity of the acid gas 

scheme. The reduction in injectivity could possibly be the result of fines migration, 

precipitation and scale potential, oil or condensate banking and plugging, asphaltene and 

elemental sulphur deposition, and hydrate plugging (Bennion et al., 1996). 

Cement compatibility with the acid gas, primarily in the injection well, but also in 

neighboring wells, is crucial for safety and containment. For example, a non-carbonate 

and calcium cement blend shattered when tested in an acid-gas stream for several weeks 

(Whatley, 2000). Thus, the compatibility of the acid gas with the cement that bonds the 

casing to the formation should be tested at a minimum. While the cement for the newly 

implemented acid-gas operation can be tested and properly selected prior to drilling, the 

cements in nearby wells are already in place and their condition is largely unknown. 

Some of these wells could be quite old, with the cement already in some stage of 

degradation as a result of brine composition. The acid gas, when reaching these wells, 

may enhance and speed up the cement degradation, leading to possible leaks through the 

well annulus and/or along casing. 

If the acid gas is injected into the originating or other oil or gas pool, the main concern is 

the impact on further hydrocarbon recovery from the pool and acid-gas production at the 

25
pump, although the operation may prove successful, like the Zama X2X pool (Davison et 

al., 1999). If the gas mixture is injected into an aquifer, the degree to which it forms a 

plume and migrates from the injection well depends on various factors, including 

pressure and temperature, solubility, interplay between driving forces, like buoyancy, and 

aquifer hydrodynamics, and aquifer heterogeneity, which controls gravity override and 

viscous fingering. 

The fate of the injected acid gas in the subsurface is not known, because subsurface 

monitoring is not required, and it is difficult and expensive. Only the well-head gas 

composition, pressure, temperature and rate have to be reported to regulatory agencies. 

There is only one recently reported case (2002) where the operator believed, when it 

applied for the injection license, that the disposal zone is isolated by a fault from an 

adjacent pool in the same formation producing oil with a high H2S content, only to have 

acid gas breakthrough at two offset producing wells some 900 m away from the injection 

well after several months since the start of injection. However, the operator, owner of 

both the oil pool and of the acid gas disposal facility, decided to continue both operations. 

CONCLUSIONS 

From an engineering point of view, acid gas injection has been developed into a mature 

technology. It can be injected as a dry gas or a solution gas, depending on the wastewater 

available. 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 

200 million m3, respectively, with no obvious historical trend, although a few very large 

operations have been approved in 2002 (Figure 9). One may initially expect an increase 

in operation size as knowledge and technology advances, but the lack of a historical trend 

is more a reflection of economic and geological considerations than of technological 

know-how. 

Compared to other options, acid gas injection has less environmental consequences than 

sulphur recovery (where leaching of the sulphur piles can lead to groundwater 

contamination) or flaring (which essentially substitutes SO2 for H2S in the atmosphere, as 

well as releasing CO2). Knowledge of the phase-equilibria and properties of the acid gas 

is extremely important in designing a safe injection operation, which minimizes 

corrosion, hydrate formation and cavitation, leading to a dense-fluid phase for injection. 

Both monitoring for gas leaks and corrosion, and plans for mitigation if a leak occurs, are 

an essential part of the technology. 

Equally important for a safe acid gas injection operation is the proper characterization 

and selection of the subsurface injection zone (reservoir or aquifer). Critical elements are 

containment and prevention of leakage and/or migration through natural or man-made 

conduits, such as fractures (“cracks”) and abandoned wells (“punctures”). Maintaining 

the integrity of the confining aquitard (or caprock), which is subjected to physical and 

chemical stresses, is essential. 

26
	






















































































	 












  	
 
 

  












    

    






	

a:	

27
Acid gas injection is more than an industrial, scaled-up analogue for geological storage of 

CO2. The experience gained so far in North America, particularly in Canada, can be 

applied elsewhere in the world. As gas resources become more depleted, deeper and more 

sour gas will be produced; and therefore application of this technology will result in the 

reduction of significant CO2 emissions even without the incentive of CO2 emission 

trading. With the advent of trading, acid gas injection should become even more 

appealing to oil and gas producers. 

By the end of 2002, close to 1.5 Mt CO2 and 1 Mt H2S have been successfully injected 

into deep hydrocarbon reservoirs and saline aquifers in Canada alone. If one considers 

also the 16 operations in the United States, 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 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 hazardous. Although the fate of the injected acid 

gas has not been monitored to date, the subsurface information about aquifer and 

reservoir rocks and fluids may provide a wealth of information as to what characteristics 

a good CO2-storage site should have. This information can be used for the screening and 

identification of future sites for the geological sequestration and storage of CO2. In 

addition, monitoring the fate of the injected acid gas at one or more such sites will 

provide invaluable information about the long-term fate of injected acid and greenhouse 

gases. 

Finally, H2S has the potential to become a valuable energy source. Besides hydrocarbons, 

sulphur and H2S represent the only additional store of chemical energy that occurs 

naturally on Earth in substantial quantity (Connock, 2001). Just as CH4 is oxidized to 

CO2 to recover energy, oxidation of H2S to SO2 can provide energy. If technology can be 

developed to make this economically attractive, then the acid gas components for 

injection would become CO2 and SO2 instead of CO2 and H2S (Connock, 2001). 

REFERENCES 

Adams, G. H. & Rowe, H. G. 1981. Slaughter Estate Unit CO2 pilot – surface and 

 downhole equipment construction and operation in the presence of H2S. Journal 

 of Petroleum Technology, 33:6, 1065-1074. 

AEUB (Alberta Energy and Utilities Board) 1994. Guide 51: Injection and Disposal 

 Wells. Alberta Energy and Utilities Board, Calgary, AB. DOI 

 eub.gov.ab.ca/bbs/products/guides/g51-1994.pdf. 

AEUB (Alberta Energy and Utilities Board) 2000. Guide 65: Resources Applications 

 for Conventional & Gas Reservoirs. Alberta Energy and Utilities Board, Calgary, 

 AB, 113-136. DOI eub.gov.ab.ca/bbs/products/guides/g65.pdf. 

Bachu, S. 1993. Basement heat flow in the Western Canada Sedimentary Basin: 

 Tectonophysics, 222:1, 119-133. 

28
Bachu, S. 1999. Flow systems in the Alberta Basin: Patterns, types and driving 

 mechanisms. Bulletin of Canadian Petroleum Geology, 47, 455-474. 

Bachu, S. 2000. Sequestration of carbon dioxide in geological media: criteria and 

 approach for site selection. Energy Conversion and Management, 41:9, 953-970. 

Bachu, S. & Stewart, S. 2002. Geological sequestration of anthropogenic carbon dioxide 

 in the Western Canada Sedimentary Basin. Journal of Canadian Petroleum 

 Technology, 41:2, 32-40. 

Bennion, D. B., Thomas, F. B., Bennion, D. W. & Bietz, R. F. 1996. Formation screening 

 to minimize permeability impairment associated with acid gas or sour gas 

 injection/disposal. CIM Paper 96-93 Presented at the 47th Annual Technical 

 Meeting of the CIM Petroleum Society, Calgary, AB, June 10-12, 1996. 

Carroll, J. J. 1998a. Phase diagrams reveal acid-gas injection subtleties. Oil & Gas 

 Journal, 96:9, 92-96. 

Carroll, J. J. 1998b. Acid-gas injection encounters diverse H2S, water phase changes. Oil 

 & Gas Journal, 96:10, 57-59. 

Carroll, J. J. & Lui, D. W. 1997 Density, phase behavior keys to acid gas injection. Oil 

 & Gas Journal, 95:25, 63-72. 

Clark, M. A., Syrek, W. Y., Monnery, W. D., Jamaluddin, A. K. M., Bennion, D. B., 

 Thomas, F. B., Wichert, E., Reed, A. E. & Johnson, D. J. 1998 Designing an 

 optimized injection strategy for acid gas disposal without dehydration. In: 

 Proceedings of the Seventy-Seventh Gas Processors Association Annual 

 Convention, Tulsa, OK, 49-56. 

Connock, L. 2001. Acid gas injection reduces sulphur burden. Sulphur, 272, 35-41. 

Davison, R. J., Mayder, A., Hladiuk, D. W. & Jarrell, J. 1999. Zama acid gas 

 disposal/miscible flood implementation and results. Journal of Canadian 

 Petroleum Technology, 38:2, 45-54. 

Gunter, W. D., Perkins, E. H. & Hutcheon, I. 2000. Aquifer disposal of acid gases: 

 modeling of water-rock reactions for trapping acid wastes. Applied Geochemistry, 

15, 1085-1095. 

Hitchon, B., Perkins, E. H. & Gunter, W. D. 2001. Recovery of trace metals in 

 formation waters using acid gases from natural gas. Applied Geochemistry, 16, 

 1481-1497. 

Ho, K. T., McMullen, J., Boyle, P., Rojek, O., Forgo, M. & Beatty, T. 1996. Subsurface 

 acid gas disposal scheme in Wayne-Rosedale, Alberta. SPE Paper 35848, In: 

 Proceedings of the Gas Technology Symposium, Calgary, AB, Canada, 28 April – 

 1 May 1996, SPE, 699-704. 

Keushing, H. 1995. Hydrogen sulphide – if you don’t like it, put it back. Journal of 

 Canadian Petroleum Technology, 34:6, 18-20. 

Kopperson, D., Horne, S., Kohn, G., Romansky, D., Chan, C. & Dugworth, G. L. 1998a. 

 Injecting acid gas with water creates new disposal option. Oil & Gas Journal, 

96:31, 33-37. 

Kopperson, D., Horne, S., Kohn, G., Romansky, D., Chan, C. & Dugworth, G. L. 1998b. 

 Two cases illustrate acid gas/water injection scheme. Oil & Gas Journal, 96:32, 

 64-70. 

29
Lock, B. W. 1997. Acid gas disposal – A field perspective. In: Proceedings of the 

 Seventy-Sixth Gas Processors Association Annual Convention, San Antonio, TX, 

 March 10-12, 1999, Tulsa, OK, p. 161-170. 

Longworth, H. L., Dunn, G. C. & Semchuk, M. 1996. Underground disposal of acid gas 

 in Alberta, Canada: regulatory concerns and case histories. SPE Paper 35584, In: 

 Proceedings of the Gas Technology Symposium, Calgary, AB, Canada, 28 April 

 – 1 May 1996, SPE, 181-192. 

Ng, H-J., Carroll J. J. & Maddocks, J. R. 1999. Impact of thermophysical properties 

 research on acid gas injection process design. In: Proceedings of the Seventy-

 Eighth Gas Processors Association Annual Convention, Nashville, TN, March 1-

 3, 1999, Tulsa, OK, 114-120. 

Whatley, L. 2000. Acid-gas injection proves economic for west-Texas plant. Oil & 

 Gas Journal, 98:21, 58-61. 

Wichert, E. & Royan, T. 1996. Sulfur disposal by acid gas injection. SPE Paper 35585, 

In: Proceedings of the Gas Technology Symposium, Calgary, AB, Canada, 28 

 April – 1 May 1996, SPE, 193-200. 

Wichert, E. & Royan, T. 1997. Acid gas injection eliminates sulfur recovery expense. Oil 

 & Gas Journal, 95:17, 67-72. 

30
Synthesis Reports 

Acid Gas Injection Operations 

in Western Canada 

Synthesis Tables 

1. Reservoir Geology 

2. Reservoir Properties and Fluids 

3. Licensed Injection Operations 

4. Acid Gas Injection Wells 

5. Pipelines 

6. Gas Plant Compressors 

Synthesis Graphs 

 Host Rock 

 Host Fluids 

 Operations 

31
Table 1: Reservoir Geology

Site 

No.

Unit 

Type Name 

Name Lithology Thk (m)

Caprock Formation

Name Lithology Thk (m)

Injection Formation

Inj. Zone Depth Net Pay

Contained

 Fluid

312 Reservoir Qtz-sandstone Oil & Gas 1552 - 1556 Halfway Fm Charlie Lake Fm Doig Fm 4 4 Sandstone 101 

320 Aquifer Sandstone Water 1905 - 1942 Belloy Fm Montney Fm Taylor 

37 13 Siltstone 250 

449 Aquifer Limestone Water 2715 - 2918 Wabamun Gp Exshaw Fm Gramin

203 10 Shale 130 

581 Aquifer Limestone Water 2285 - 2503 Wabamun Gp Exshaw Fm Gramin

218 10 Shale 130 

625 Reservoir Sandstone Oil 1422 - 1439 Ellerslie Mbr Ellerslie Mbr Ellerslie 

17 17 Shale 12 

718 Aquifer Limestone Water 705 - 981 Wabamun-Winterburn Exshaw Fm Winterb

276 10 100 Shale 

844 Aquifer Limestone Water 2222 - 2228 Wabamun Gp Banff Fm Bluerid

6 8 Limestone 190 

997 Reservoir Sandstone Oil 1391 - 1401 Halfway Fm Charlie Lake Fm Doig Fm 10 Anhydrite 15 

1034 Reservoir Dolostone Oil 2677 - 2695 Leduc Fm Ireton Fm Cookin

18 18 Shale 18 

1189 Reservoir Sandstone Oil & Gas 1541 - 1562 Nordegg Mbr Lower Mannville Fm Pekisko

21 6 Shale 15 

1242 Reservoir Dolostone Oil 1745 - 1840 Wabamun Gp Exshaw Fm 95 88 Shale 10 

1396 Reservoir Dolostone Oil 1927 - 2058 Wabamun Gp Exshaw Fm 131 8 50 Shale

1489 Reservoir Qtz-arenite Gas 1355 - 1390 Kiskatinaw Fm Belloy & Kiskatinaw Golata 

35 8 Anhydrite 85 

1510 Reservoir Dolostone Water 1493 - Keg River Fm Muskeg Fm Evaporites 270

1522 Reservoir Limestone Gas 1317 - 1385 Slave Point Fm Fort Simpson Fm Fort Ve

68 8 Shale 13 

1563 Reservoir Carbonates Oil & Gas 1478 - 1585 Zama & Keg River Muskeg Fm Lower 

107 25 Anhydrite 75 

1630 Aquifer Sandstone Water 1661 - 1673 Belloy Fm Montney Fm Debolt 

12 240 10 Shale 

1734 Reservoir Dolostone Water 1200 - Leduc Fm Ireton Fm 30 Shale 22

1895 Aquifer Dolostone Water 1110 - 1166 Keg River Fm Muskeg Fm Chinch

56 18 Evaporites 150 

1971 Aquifer Limestone Water 1167 - Wabamun Gp Ellerslie-Wabamun Gramin

16 Lime mudstone 7 

2081 Aquifer Dol. Limestone Water 1958 - Beaverhill Lake Gp Leduc-Cooking Lak 10 Lime mudstone 150

2101 Aquifer Dolostone Water 1373 - 1454 Keg River Fm Muskeg Fm Chinch

81 81 Anhydrite 140 

2271 Aquifer Dolostone Water 1601 - 1650 Keg River Fm Muskeg Fm Lower 

49 85 15 Evaporites 

Acid-gas Injection Operations 
Site 

No.

Unit 

Type Name 

Name Lithology Thk (m)

Caprock Formation

Name Lithology Thk (m)

Injection Formation

Inj. Zone Depth Net Pay

Contained

 Fluid

2469 Reservoir Carbonates Water - Leduc Fm

2573 Aquifer Dolostone Water 1341 - 1453 Upper Leduc Nisku Fm Lower 

112 40 Dolostone 20 

2636 Aquifer Dolostone Water 2781 - 2847 Wabamun Gp Banff Fm Wabam

66 60 Limestone 168 

2719 Aquifer Siliciclastics & ca Water 2036 - 2118 Belloy Fm Montney Fm Taylor 

82 10 Shaly siltstone 250 

2830 Aquifer Dolostone Water 1416 - 1433 Keg River Fm Prairie Evaporite F Cambr

17 185 10 Salt 

2982 Aquifer Sandstone Water 1589 - 1610 Belloy Fm Montney Fm Stodda

21 264 29 Shale 

3084 Aquifer Limestone Water 2010 - 2090 Cooking Lake Fm Duvernay Fm Mildred 

80 40 Shale 42 

3195 Aquifer Dolostone Water 1880 - 1934 Leduc Fm Ireton Shale Waterw

54 2 5 Shale 

3340 Aquifer Sandstone Water 1182 - 1286 Ostracod-Basal Qtz 104 3

3465 Aquifer Clastics Water 913 - 984 Basal Quartz Sd 71

3581 Reservoir Sandstone Oil 809 - 838 Cummings Mbr Lloydminster Mbr Woodb

29 Sandstone 

3651 Reservoir Sandstone Oil & Gas - Glauconitic Ss Upper Mannville Fm Glauco

4 Shale & siltstone 50 

3720 Aquifer Sandstone Water 2407 - 2450 Belloy Fm Montney Fm Taylor 

43 26 Shale 199 

3804 Aquifer Sandstone Water 1760 - 1801 Kiskatinaw Fm Taylor Flat Fm Golata 

41 24 Sand & shale 20 

3968 Reservoir Carbonates Water 3386 - 3478 Nisku Fm Calmar Fm Nisku-U

92 4 14 Shale 

4058 Reservoir Oil 1487 - 1535 Baldonnel Fm Nordegg Mbr Charlie 

48 30

4174 Reservoir Carbonates Gas 2633 - 2815 Pardonet Fm 182 27 Charlie 

4248 Reservoir Carbonates Oil 2164 - 2196 Debolt Fm Stoddart Gp 32 15 Siltstone

4292 Aquifer Sandstone Water 1652 - 1713 Halfway Fm Charlie Lake Fm Doig Fm 61 9 Dolostone 185 4336 Aquifer Sandstone Water 1590 - 1617 Halfway Fm Charlie Lake Fm Doig Fm 27 13 Anhydrite 59 4343 Aquifer Sandstone Water 1590 - 1617 Halfway Fm Charlie Lake Fm Doig Fm 27 13 Anhydrite 59 

4489 Reservoir Dolostone Gas 1297 - 1355 Baldonnel Fm Nordegg Mbr Charlie 

58 25 Chert 20 

4512 Reservoir Sandstone Gas 2443 - 2456 Kiskatinaw Fm Kiskatinaw Fm Golata 

13 10 Shale 25 

4680 Aquifer Carbonates Water 950 - 1025 Debolt Fm Montney Fm 75 83 4 Shale

Acid-gas Injection Operations 
Table 2: Reservoir Properties and Fluids

Site 

No.

Reservoir 

volume 

(1000 m3)

Porosity 

(fraction)

Permeability 

(md)

Formation Pressure Formation 

Temperature

 (°C)

 Original Startup (kPa) (kPa)

Na 

(mg/l)

Ca 

(mg/l)

TDS 

(mg/l)

HCO 

(mg/l)

A

gra

Formation Water O

3

Avg. Injection depth (m)

312 15200 1554 15 68 NA 37

320 0.12 16700 1924 30 76 53400 4760 471 NA 

610 162000

449 0.06 27000 41530 9830 481 NA 

2817 75 569 152813

581 0.08 20244 2394 35 70 320 NA 

625 0.15 10245 1431 50 60 NA 23200 2880 397 

539 69400

718 0.10 5915 21605 5756 293 NA 

843

844 0.20 17762 2225 69 107 NA 

997 0.12 12800 1396 6 60 9500 9289 340.8 869 1034 0.16 28588 2686 124 82 NA 37 

74

1189 12135 1552 155 58 4215 16850 3964 105 

1631 55830

1242 0.05 17982 1793 58 NA 56

52

1396 0.05 20317 1993 63 NA 33

115

1489 0.21 13035 1373 500 47 6100 52095 5485 278 NA 182 156722

1510 0.06 15000 79 5842 35

342

1522 0.08 13394 1351 49 3110 NA

1563 0.04 14479 1532 76 13394 48600 11400 1435 36.

450 168355

1630 0.18 16700 1667 57 12855 54500 5240 257 NA 

396 156804

1734 0.10 53 9465 27100 11100 771 68

100 137 120000

1895 0.05 11164 1138 56 308 266000 NA 

1971 0.13 8900 45 201 NA 

2081 0.07 15700 71 15700 NA 

671

2101 0.04 11292 1414 52 226 NA 

2271 0.05 13237 1626 58 13237 NA 

1300 135000

2469 NA 32600 4510 552 NA 

106618

2573 0.22 35 7500 24330 3160 971 NA 

1397 5084 78924

2636 0.09 24680 2814 103 307 NA 

Acid-gas Injection Operations 
Site 

No.

Reservoir 

volume 

(1000 m3)

Porosity 

(fraction)

Permeability 

(md)

Formation Pressure Formation 

Temperature

 (°C)

 Original Startup (kPa) (kPa)

Na 

(mg/l)

Ca 

(mg/l)

TDS 

(mg/l)

HCO 

(mg/l)

A

gra

Formation Water O

3

Avg. Injection depth (m)

2719 0.12 20000 2077 76 330 140000 NA 

2830 0.06 13790 1425 38 106920 21976 126 NA 

241 341430

2982 0.20 13744 1600 60 54500 5240 257 NA 

209 156804

3084 0.05 70 15459 48930 30968 166 51

2050 30 481 222663

3195 0.06 65 15500 30200 11100 895 NA 

1907 153 416 122449

3340 0.16 9300 1234 51 1700 NA 3465 949 NA 

3581 0.30 5200 

824 6500 230

3651 11500 1170 3720 0.12 23084 2429 82 55253 2505 795 NA 

2320 159216

3804 0.11 16500 1781 9 63 60100 4330 207 NA 

379 162000

3968 0.10 35860 3432 693 110 11000 NA 

920 61500

4058 0.09 68 8300 13793 173 3853 

1511 5

4174 32145 2724 1 82 4200 21200 146 5338 NA 364800

4248 0.04 76 17596 

2180 1141 76000

4292 0.12 15685 1683 64 8549 110 854 NA 

23742

4336 0.12 13113 1604 61 66490 2442 2330 NA 

3863 177691

4343 0.12 13113 1604 61 29600 1420 807 NA 4489 0.10 11154 1326 64 6031 13793 173 3853 NA4512 0.09 23133 2450 82 2000 NA 4680 0.10 53 7670 26900 1620 555 NA 

988 10401 77800

Acid-gas Injection Operations 
Table 3: Licensed Operations

Site 

No. CO 

(mol frac)

H S 

(mol frac)

Licensed Inj. Gas 

2 2

Total Approved 

Inj. Volume

(1000 m3)

Maximum Approved 

BHIP 

(kPa)

WHIP

(kPa)

Life time EPZ 

(years) (km)

Max. Approved 

Injection Rate 

(1000 m3/d)

312 14910 5000 10 3.0 0.25 0.75 27 34500

320 22000 8000 15 3.5 0.32 0.66 60 263000

449 33000 12000 5.3 0.15 0.75 30 63000

581 35800 13000 10 6.2 0.79 0.20 34 124100

625 10546 9000 20 0.57 0.42 58 213000

718 8596 3750 0.0 0.31 0.01 6 6000

844 20300 10500 15 2.4 0.65 0.35 16 38000

997 26000 13000 10 1.1 0.44 0.34 4.2 16000

1034 31380 12300 25 5.5 0.31 0.63 12 40000

1189 11000 7500 15 0.4 0.95 0.04 40 70000

1242 21500 9000 20 3.7 0.29 0.67 2.8 8100

1396 20303 12000 11 5.0 0.45 0.52 18 35000

1489 13035 7100 25 3.7 0.57 0.41 5 18700

1510 16707 12000 1.7 0.70 0.30 210 88000

1522 21000 11000 3.0 0.70 0.30 210 220000

1563 14500 12000 8 17.0 0.61 0.38 160 157000

1630 17982 10000 15 1.3 0.70 0.30 21 94200

1734 9000 15 0.87 0.13 35 64000

1895 11500 7000 15 2.0 0.34 0.64 65 140000

1971 18220 9800 10 2.0 0.80 0.17 11 41000

2081 21760 11700 15 2.9 0.50 0.48 40 185100

2101 18925 7600 15 3.8 0.34 0.64 26.3 106000

2271 18192 9500 15 3.2 0.75 0.25 74.6 290000

2469 8273 0.50 0.50

2573 15274 8000 1.5 0.70 0.17 45 160000

2636 10500 28 109000 0.45 0.55

2719 24607 9000 20 5.0 0.51 0.49 42 150000

2830 22000 10000 12 1.2 0.88 0.09 24 86000

2982 14210 9000 15 2.2 0.71 0.25 21 58200

3084 20000 10000 15 1.9 0.72 0.25 25 115000

3195 20000 10000 15 1.0 0.82 0.17 28 140000

3340 6000 6 30000 0.83 0.15

3465 11000 0.60 0.13

Acid-gas Injection Operations Footnote: For Site No. 4343 see Site No. 4336 for the Alberta Geological Survey

total approved injection rate and volume (same 

operation) 36
Site 

No. CO 

(mol frac)

H S 

(mol frac)

Licensed Inj. Gas 

2 2

Total Approved 

Inj. Volume

(1000 m3)

Maximum Approved 

BHIP 

(kPa)

WHIP

(kPa)

Life time EPZ 

(years) (km)

Max. Approved 

Injection Rate 

(1000 m3/d)

3581 6700 12 16000 0.70 0.30

3651 23500 8500 10 0.1 0.98 0.02 130 649000

3720 37400 19000 25 5.0 0.29 0.70 106 956000

3804 17576 5500 20 3.8 0.28 0.69 24.5 180000

3968 33000 12000 8 8.5 0.15 0.85 340 430000

4058 17600 9790 5.2 0.48 0.50 114 416000

4174 30600 12135 2.8 0.15 0.81 900 1330000

4248 20000 10500 20 1.8 0.60 0.40 69 380000

4292 10500 2.0 0.60 0.40 69 16600

4336 23000 10500 1.6 0.15 0.85 391 1876000

4343 23000 10500 15 3.5 0.15 0.85 see footnote see footnote

4489 21000 9790 1.4 0.38 0.54 228 416000

4512 23050 6500 18 0.41 0.59 15 37000

4680 8200 8000 10 0.63 0.37 22.5 82000

Acid-gas Injection Operations Footnote: For Site No. 4343 see Site No. 4336 for the Alberta Geological Survey

total approved injection rate and volume (same 

operation) 37
Table 4: Acid Gas Injection Wells

Site 

No.

Well 

Number Depth 

(m KB)

Production Tubing

Size

(mm)

Production Casing Type of Fluid 

in the Annulus

Packer 

Depth 

(m KB)

Size 

(mm)

Density 

(kg/m)

Density 

(kg/m)

Grade

312 143013 139.7 23.1 60.3 J-55 2286 6.99 Inhibited crude oil 1540

320 263792 139.7 29.8 60.3 J-55 1942 6.99 Inhibited H2O 1900

449 205662 177.8 54 73 J-55 2947 9.67 Inhibited crude oil 2720

581 151636 177.8 38.7 73 J-55 9.67 Fresh H2O, inhibited 2290

625 138139 139.7 23 60.3 6.99 KCl water, inhibited 1628 1658

718 142129 244 53.6 140 S0055 20.83 666

844 260595 140 25.3 73 L-80 2295 9.67 2200

997 154078 140 23.1 73 1388

164367 140 23.1 73 J-55 1425 9.67 1390

188894 140 23.1 73 9.67 1401 1445

1034 108999 177.8 38.7 60.3 J-55 6.99 Fresh H2O, inhibited 2670

1189 90706 139.7 20.3 73 J-55 9.67 Fresh H2O, inhibited 1531

1242 178540 139.7 25.3 60.3 J-55 6.99 Produced H2O, inhibited 1733

1396 170753 139.7 25.3 60.3 J-55 6.99 Fresh H2O, inhibited 1931

1489 209673 139.7 25.3 60.3 J-55 1420 6.99 Diesel 1360

1510 128598 178 34.2 73 L-80 1490 9.67 1487

1522 128595 177.8 29.76 73 L-80 1525 9.67 Fresh H2O, inhibited 1300

280511 178 38.7 73 L-80 9.67 Fresh H2O, inhibited 1322

1563 179488 177.8 39 60.3 J-55 1495 6.99 Diesel 1484

184266 114 15.6 60 J-55 6.99

1630 221341 177.8 56.6 73 9.67 3%KCl, inhibited H2O 1663

1734 194384 139.7 20.8 73 L-80 1225 9.67 Inhibited crude oil 1218

1895 266164 177.8 34.23 60.3 L-80 1172 6.99 Inhibited Diesel 1086

1971 278209 114 17 60.3 L-80 1199 6.99 Water 1166

2081 260661 177.8 34.3 73 L-80 1993 9.67 Inhibited H2O 1938

2101 280608 139.7 25.3 60.3 L-80 1475 6.99 Fresh H2O, inhibited 1393

2271 235982 139.7 25 73 J-55 1601 9.67 Fresh H2O, inhibited 1582

2469 88409 408

88471 386

88516 359

88589 371

88612 371

88621 244 53.57 178 K-55 1046 29.30 1027

88629 371

88636 398

88645 354

88659 371

88670 244 53.57 178 K-55 1039 29.76 1019

88674 371

Acid-gas Injection Operations Alberta Geological Survey 38
Site 

No.

Well 

Number Depth 

(m KB)

Production Tubing

Size

(mm)

Production Casing Type of Fluid 

in the Annulus

Packer 

Depth 

(m KB)

Size 

(mm)

Density 

(kg/m)

Density 

(kg/m)

Grade

2469 88686 371

88727 244 53.57 178 K-55 1018 29.76 968

88731 244 53.57 178 K-55 1055 29.76 999

88748 366

89961 244 53.57 168 29.80 988 931

89967 244 53.57 178 K-55 1074 29.30 1012

89973 371

89997 371

90041 371

90053 371

90070 399

90074 392

90105 178 29.76 140 J-55 1034 20.83 988

90130 371

90168 371

90196 371

90208 371

90229 244 53.57 178 K-55 1034 29.76 1010

90273 244 53.57 178 K-55 1028 29.30 1014

90281 344

90297 371

90301 371

90306 244 53.57 178 K-55 1090 29.76 1017

90342 90342

90352 317

90356 244 178 K-55 1010 29.76 1006

90361 244 178 K-55 1068 29.76 1020

91440 399

91461 244 53.57 178 K-55 1037 29.76 1024

91496 395

91544

91554 244 53.57 178 K-55 1087 29.76 1085

91566 244 53.95 140 J-55 1042 20.90 1023

91636 409

91637 178 29.76 140 J-55 1076 20.80 1053

152071 244 54 178 K-55 1020 29.80 1001

162252 244 53.7 178 K-55 1009 29.30

2573 204185 177.8 56 73 J-55 1344 14.14 Water 1324

2636 290514 139.7 25.3 73 L-80 2957 9.67 Fresh H2O, inhibited 2768

2719 263896 139.7 29.8 60.3 L-80 2145 6.99 Fresh H2O, inhibited 2030

2830 204006 177.8 30 73 L-80 1500 9.67 Inhibited crude oil 1424

Acid-gas Injection Operations Alberta Geological Survey 39
Site 

No.

Well 

Number Depth 

(m KB)

Production Tubing

Size

(mm)

Production Casing Type of Fluid 

in the Annulus

Packer 

Depth 

(m KB)

Size 

(mm)

Density 

(kg/m)

Density 

(kg/m)

Grade

2982 221031 139.7 23.07 73 K-55 9.67 Inhibited crude oil 1598

3084 228593 139.7 20 60 J-55 2005 2124

3195 202360 177.8 34.2 73 L-80 1996 9.67 KCl water, inhibited 1879

3340 83493 177.8 34 73 J-55 1365 9.67 1175

3465 55392 912

55409 922

55412 915

55457 912

55466 139.7 917

55480 139.7 945 901

55493 177.8 951 905

55526 893

55553 906

55591 891

55615 894

55647 898

55649

150266 946

150267 950

175435 960

194314 937

3581 52915 856

186679 987

3651 14517 139.7 25.3 73 J-55 1510 9.67 1445

14519 178 34.2 60 J-55 1546 6.99 1483

3720 4444 178 34.23 60 L-80 2495 6.99 2401

3804 263546 140 23.1 60.3 J-55 2010 6.99 1761

3968 161153 177.8 43.2 73 L-80 3335 9.67 3379

4058 5000458 177.8 34.3 89 L-80 1509 13.70 1414

5013792 178 34.2 89 L-80 1487 13.80 1416

4174 5001572 177.8 43.2 114 L-80 2711 18.90

4248 5004038 2221

4292 5013892 178 38.7 73 L-80 1658 2105

4336 5010427 140 23.7 73 L-80 1647 9.67 1577

4343 5010429 178 34.3 73 L-80 1674 9.67 1568

4489 5000496 140 20.8 73 L-80 1324 9.67 1290

4512 5008653 178 43.2 89 L-80 3307 13.80 2430

4680 5016659 140 25.3 73 2000 series f 935 2.49 928.6

Acid-gas Injection Operations Alberta Geological Survey 40
Table 5: Pipelines

Site 

No.

Pipeline 

Length (m)

Pipe 

Grade

Pipe Outside

Diameter (mm)

Pipe Wall 

Thickness (mm)

Max Operating 

Pressure (kPa)

Max Allowable 

Stress Level (%)

312 2250 259

320

449 420 316 SS 48.3 3.68 12800 49

581 3480 359 88.9 4.8 13000 33.5

625 500 B 88.9 11.13 13960 23

718

844

997

1034 150 316 SS 60.3 5.54 11380 36

1189 1460 290 88.9 4.78 8280 27

1242 600 304 SS 60.3 5.54 14240 38

1396

1489 3000 290 60.3 4.8 13790 30

1510 5450 359 88.9 4 12400 38

1522 450 359 88.9 4.8 12400 32

810 359 88.9 4 12400 38

1563 190 359 88.9 4 14890 46

4300 359 88.9 4 14890 46

1630 130 Sch 160 60.3 8.74 17250 25

1734 100 316L SS 88.9 5.4 10340 27

1895 1050 290 60.3 3.2 9930 32

1971 13000

2081 316L SS 60.3 16500

2101 800 304 SS 60.3 3.91 10500 48

2271 200 290 114.3 4 12400 61

2469

2573 200 SS 60.3 5.54 9075

2636 650 359 60.3 4.8 10800 19

2719

2830

2982

3084

3195

3340 2200 290 60.3 3.9 7000 19

Acid-gas Injection Operations Alberta Geological Survey 41
Site 

No.

Pipeline 

Length (m)

Pipe 

Grade

Pipe Outside

Diameter (mm)

Pipe Wall 

Thickness (mm)

Max Operating 

Pressure (kPa)

Max Allowable 

Stress Level (%)

3465

3581

3651

3720

3804 230 304 L SS 60.3 5.54 8274

3968 20000 114.3 8.56

4058 1600 290 88.9 4.8 18790 60

4174 14450 168.3 14650

4248

4292

4336 1584 60.3 3.2 10720

4343 300 60.3 3.2 12160

4489 16500 290 88.9 4.8 11750 37.5

4512 2420 359.2 88.9 4 19000

4680 350 359 60.3 3.9 9929 21.4

Acid-gas Injection Operations Alberta Geological Survey 42
Table 6: Gas Plant Compressors

Plant

 No.

Manufacturer HP 

Rating

Driver

Type

No. of 

stages

Design Rate 

(1000 m3/d)

Discharge 

Pressure (kPa)

Dehydration 

Method

300 Refrigeration

300 Diesel

400 Ariel 200 Diesel 4 30 7250 None

500 Diesel 4 Refrigeration

600 300 Diesel 4 5600 None

700

800

900

1000

1100 Knox Western 300 Diesel 4 36 4400 TEG

1200 Ariel 50 Diesel 4 6820 None

1300 Ariel 250 Diesel 4 23 8330 None

1400 Ariel 150 Diesel 4 7 8350 Dry Desiccation

1500 560 Diesel 4 84 8700 None

1500 Ariel 617 Electric 5 105 7550 None

1600 300 Diesel 4 5500 Refrigeration

1700 Ariel 350 Diesel 4 30 5800 TEG

1800 4 None

1900 150 Diesel 4 14 6840 None

2000 4 8000 None

2100 Ariel 250 Diesel 4 26 4100 None

2200 5 TEG

2400

2500 Dresser Rand 800 Diesel

2600

2700

2800 300 Diesel 4 6100 None

2900

3000

3100

3300 200 Diesel 4 15 2800 TEG

3400

3500

3600 Ariel 1100 Diesel 4 198 8357

Acid-gas Injection Operations Alberta Geological Survey 43
Plant

 No.

Manufacturer HP 

Rating

Driver

Type

No. of 

stages

Design Rate 

(1000 m3/d)

Discharge 

Pressure (kPa)

Dehydration 

Method

3700 Diesel 103

3800 Energy Industries 250 Diesel 4 22 7350 no dehydration

3900 1900 Electric 5 169 8275 refrigeration

4000 Ariel 1500 Electric 4 106 6700 TEG

4100 Dresser 4000 Diesel 4 800 7585 prior dehydration

4200 Ariel Electric 5 50

4300 Gemini 2400 Electric 5 422 8936

4400 Ariel 1500 Electric 4 106 4450 refrigeration

4500 Ariel 200 Diesel 4 15 5500 TEG

4600 Energy Industries 250 Diesel 4 7 TEG

Acid-gas Injection Operations Alberta Geological Survey 44
Synthesis Graphs 

Acid Gas Injection Operations 

in Western Canada 

Host Rock 

 Injection Reservoir Type and Lithology 

 Net Pay of Injection Reservoir 

 Range of Porosity of Host Rock 

 Porosity vs. Depth of Host Rock 

45
Reservoir Type and Lithology for Acid Gas Injection Operatio

Acid-gas Injection Operations Host Rock 

0 4 8 12 16 20 

Reservoir

Aquifer

Number of Acid Gas Sites
Acid-gas Injection Operations Host Rock 

Net Pay of Injection Reservoir or Aquifer

0

102030405060708090

100

312320449581625718844997103411891242139614891563151015221630173418951971208121012271246925732636271928302982308431953340346535813651372038043968

Net Pay (m)
Porosity of Host Rock for Acid Gas Injection Operations

Acid-gas Injection Operations Host Rock 

0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

312

320

449

581

625

718

844

997

1034

1189

1242

1396

1489

1510

1522

1563

1630

1734

1895

1971

2081

2101

2271

2469

2573

2636

2719

2830

2982

3084

3195

3340

3465

3581

3651

3720

3804

3968

Porosity (fraction)

Core Plug PorosityPorosity Range
Porosity of Acid Gas Injection Zones

Acid-gas Injection Operations Host Rock 

0

500

100015002000250030003500

0 0.05 0.1 0.15 0.2 0.25 

Porosity (fraction)

Depth (m KB)
Synthesis Graphs 

Acid Gas Injection Operations 

in Western Canada 

Host Fluids 

 Original Formation Pressure at Injection Zones 

 Formation Temperature of Injection Zones 

 Formation Water Salinity 

 Oil API Gravity in Depleted Oil Reservoirs used 

for Injection 

 Specific Gravity in Depleted Gas Reservoir used 

for Injection 

50
Original Formation Pressure in Acid Gas Injection Zones

Acid-gas Injection Operations Host Fluids 

0

500

100015002000250030003500

0 5000 10000 15000 20000 25000 30000 

Pressure (kPa)

Depth (m KB)

Hydrostatic pressur
Formation Temperature in Acid Gas Injection Zones

Acid-gas Injection Operations Host Fluids 

0

500

100015002000250030003500

0 20 40 60 80 100 120 140 16

Temperature (

oC)

Depth (m KB)

Geothermal gradien

25 °C/k30 °C/k35 °C/k40 °C/k45 °C/k50 °C/k
Formation Water Salinity in Acid-Gas Injection Zones 

Acid-gas Injection Operations Host Fluids 

0

500

100015002000250030003500

0 50000 100000 150000 200000 250000 

Formation Water Salinity (TDS mg/l)

Depth (m KB)
Reservoir Oil Gravity for Acid Gas Injection in Depleted Oil Rese

Acid-gas Injection Operations Host Fluids 

Oil API Gravity

0

500

100015002000250030003500

30 40 50 60 

Depth (m KB)
 Specific Gravity of Natural Gas in Depleted Gas Reservoirs Used for Ac

Acid-gas Injection Operations Host Fluids 

Gas Specific Gravity

0

500

100015002000250030003500

0.4 0.5 0.6 0.7 0.8 0.9 

Depth (m KB)
Synthesis Graphs 

Acid Gas Injection Operations 

in Western Canada 

Acid Gas Injection Operations 

 Injection Interval Depths 

 Wellhead and Formation Pressures of Acid Gas 

Injection Operations 

 Bottom Hole Injection Pressures vs. Depth 

 Maximum Approved Acid Gas Injection Rate 

 Composition of Injected Acid Gas in Alberta 

 In-situ Pressure, Temperature and Phase 

Conditions for the Injected Acid Gas 

 Well Statistics for Injection Sites 

 Pipeline Length 

56
Depth of the Injection Zone Interval for Acid Gas Injection Oper

Acid-gas Injection Operations Injection Operations 

0

500

100015002000250030003500

312

320

449

581

625

718

844

997

1034

1189

1242

1396

1489

1563

1510

1522

1630

1734

1895

1971

2081

2101

2271

2469

2573

2636

2719

2830

2982

3084

3195

3340

3465

3581

3651

3720

3804

3968

4

Depth (m KB)

Approximate depth of CO2 phase change to s
Pressures Associated with Acid Gas Injection Operations

Acid-gas Injection Operations Injection Operations 

0

5000

1000015000200002500030000350004000045000

312

320

449

581

625

718

844

997

1034

1189

1242

1396

1489

1510

1522

1563

1630

1734

1895

1971

2081

2101

2271

2469

2573

2636

2719

2830

2982

3084

3195

3340

3465

3581

3651

3720

3804

3968

4

Pressure (kPa)

Maximum Approved Bottom Hole Injection Pressure (BHIP)Injection Formation Pressure at StartupMaximum Approved Wellhead Injection Pressure (WHIP)
Approved Maximum Bottom Hole Injection Pressure for Acid Gas Injecti

Acid-gas Injection Operations Injection Operations 

0

500

100015002000250030003500

0 5000 10000 15000 20000 25000 30000 35000 

Bottom Hole Injection Pressure (kPa)

Depth (m KB)
Maximum Approved Daily Acid Gas Injection Rate for Injection Op

Acid-gas Injection Operations Injection Operations 

0

100200300400500600700800900

1000

312

320

449

581

625

718

844

997

1034

1189

1242

1396

1489

1510

1522

1563

1630

1734

1895

1971

2081

2101

2271

2469

2573

2636

2719

2830

2982

3084

3195

3340

3465

3581

3651

3720

3804

3968

Daily Injection Rate (1000 m3/d)

CarbonateSiliciclastic
 Licensed Composition of the Injected Acid Gas

Acid-gas Injection Operations Injection Operations 

0

0.10.20.30.40.50.60.70.80.9

1312

320

449

581

625

718

844

997

1034

1189

1242

1396

1489

1563

1510

1522

1630

1734

1895

1971

2081

2101

2271

2469

2573

2636

2719

2830

2982

3084

3195

3340

3465

3581

3651

3720

3804

3968

Mole Fraction of Injected Gas

H2S (mol fraction)CO2 (mol fraction)
Acid-gas Injection Operations Injection Operations 

0

5000

1000015000200002500030000

10 20 30 40 50 60 70 80 9

Temperature (oC)

Pressure (kPa)

Carbonate Critical Point H2S Vapourization curve of H2SSiliciclastic Critical Point for CO2 Vapourization curve of CO2

Liquid CO2

Gaseous CO2 Gaseou

Liquid H2S

Supercritical CO2

In situ P-T and Phase Conditions for 

Acid Gas Injection Zones, with CO2 and H2S Phase Diagra
Well Statistics around Acid Gas Injection Sites in Alberta

Acid-gas Injection Operations Injection Operations 

0

1020304050607080

312/320

449

581

625

718

844

997

1034

1189

1242

1396

1489

1563/1510/1522

1630

1734

1895

1971

2081

2101

2271

2469

2573

2636

2719

2830

2982

3084

3195

3340

3465

3581

3651

3720

3804

3

Number of Wells around the Injection Site

Total surrounding wellsAbandonned wells

149 wells total
Pipeline Length from the Gas Plant to the Acid Gas Injection W

Acid-gas Injection Operations Injection Operations 

0

100020003000400050006000

312

320

449

581

625

718

844

997

1034

1189

1242

1396

1489

1510

1522

1522

1563

1563

1630

1734

1895

1971

2081

2101

2271

2469

2573

2636

2719

2830

2982

3084

3195

3340

3465

3581

3651

3720

3804

3968

4

Pipeline Length (m)