# 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.

## A C I D G A S I N E X I S TING OPERATI O NS

PHASE I: FINAL REPORT

Back ground to the Study

t i o n s i n g l o b a l

s , such as fu el

a l s t o r a g e i s n o t a new technolog y. However, it is acknowledged that all the technical issues related to geological storage have not y e t been

n o l o g y c a n b e

f i e l d s as part of

a d

, T u r k e y and

a , a CO 2 -EOR

w a n , w h i c h will

f C O 2 from the

t o a deep saline aquifer since 1996 . To de velop an un d e rstanding

r a n d Wey b urn.

n e x i s ting CO 2 -

u e s and help to

u d i ed in an effort to obtai n Suc h activities

p m ent of deep

p r o j e c t s i n t h e g naturally e x isting accum u l a tions of CO 2 to deter m ine what

a r l i e r , t h e r e a r e

o p e r a t i o n s i n c e

n t r i b u t e t o o u r

nown l b e r t a Research

e f i r s t p h a s e o f t h a t
stud y , which has co m p iled inform ation on t h e geo l ogical setting of the acid gas injection sites and operating/engineering experiences fro m these projects

. An interi m report 2 has already been publishe d

t i o n a t t h e end of 20 01. Th e

p a n d ed version of that one, co v e ring all of t h e acid gas op erations in bo th Alberta

a n d s t a r t e d i n 2 0 0 2

. Phase II of the study involves a due diligence exercise on a selected site th at will establish that such projects are technically

and econom ically sound and that th e carbon balance is positive to allow such projects to be included i n carbon trading regim e s in the future. The proposed Phase III would involve a monitoring pr oj ect. 

## J E C T I O N : A S T U D Y O F

Geological st orage of CO 2 is considered to be an option that coul d a c h i e v e d e e p r e d u c

em issions of anthropo geni c CO 2 , if used in conjunct i on with othe r m i t i g a t i o n m e a s u r e switching, en ergy efficiency an d rene wable energy. Geolo g i c

fully resolve d

. Those is sues outstanding will have to be addressed before t h e t e c h accepted by the polic y m a kers and the public for wide-scal e i m ple m entation.

Worldwide, there are curre ntly som e 74 projects in w h ich CO 2 has been injected i n t o o i l

CO 2 enhanced oil recover y (CO 2 -EOR) operations, mostly in the USA, b u t a l s o i n T r i n i d

Canada. I n the USA, so me 33 Mt of CO 2 is in jected annuall y i n to oil fields. I n C a n a d project has b een established b y EnCan a at the We ybur n oil field in so uthern S a s k a t c h e inject a total of 19 Mt of CO 2 over 25 y ears. In the North Sea, s o me 1 Mt pe r y e a r o Sleipner gas field has been injected i n of the fate of the injected CO 2 , detailed m onitoring pr ojects are underway at both S l e i p n e In additi on, some work is also underway in the USA to stu d y the fate of injected CO 2 i EOR operations. Such infor m ation will assist in a ddr e s s i n g t h e o u t s t a n d i n g t e c h n i c a l i s s develop p ubli c confidence in the technol og y

.

In addition, t h ere are a num b e r of other related acti v iti e s t h a t h a v e b e e n s t
inform ation that could assist in im proving understanding of geological storage of CO 2

. include the stud y of deep well injectio n of in dustr ial wastes in the USA, the d e v e l o repositories for nuclear waste disposal and natural gas storage 1

. In addition, resear c h USA, Europe and Australia are study i n inform ation c a n be gained from thes e oc curre nces rel e vant to geological storage of CO 2

.

Whilst smalle r in scale than the CO 2 -EOR and Sleipner injection opera t i o n s m e n t i o n e d e

so m e 42 acid gas injection projects operating in west ern Canada. Many h a v e b e e n i n the m i d 1990s. T h ese represent another reposit or y of know ledge that c o u l d c o understandin g of the geolo g ical storage of CO 2

.

The IEA Greenhouse Gas R&D Progr amme has participat ed in a project to f i nd out what is k

about the 42 acid gas injection projects in Canada. The stud y was undertaken b y t h e A Council (ARC) and the Alberta Geological Survey (AGS )

. T h i s r e p o r t c o v e r s t h

on th is, cove ring the 31 acid gas injection pr ojects in Alberta in o p e r a current report is an e x and British Colum b ia, including new o p e r a t i o n s a p p r o v e d

1 This w o r k was u nde rtake n fo r the C O 2 Capt ure Project by L a wre n ce Be rke l ey Nat i onal L a b. A sum m ary rep o rt

was pu bl i s he d by B e ns o n et a l at t h e G H G T- 6 C o n f ere n ce, whi l s t t h e f u l l r e po rt ca n be f o un d at

www.c o 2capt u reproject.c om

2 I E A G r eenh ouse G a s R&D Pr og r a mm e, Rep o r t N o PH4 / 15 , Janu ar y 20 03

.

i

## Technical Background

a n a d a , c o n t a i n s

c a r b o n d i oxi de

d o m e s t i c s a le,

9 9 0 ’ s , s u l p h u r

s u l phur i n the

a s o f the order

t e f f o r t s h a v e b e e n m a de to reduce gas flaring. One alternative to flaring, sulphur reco v e ry , is n o t considered to b e econom ically viable in

y t u rned to acid

r e 4 2 a p p r o v e d operations (35 in Alberta & 7 in British Colum b ia) for acid gas injection, of which 39 were active. The growth in acid gas injectio n operations is shown in Figure 1. One operation, althoug h ap proved, has

never been im pl emented by the operat o r. Two othe r operations were stopped because the gas processing plant closed. A significant proporti on of the raw natural gas produc tion i n t h e Alberta b a s i n , C

vary i ng percentages of acid gas co m ponents, specifically h ydroge n sulphide ( H 2 S ) a n d (CO 2 ). Therefore, to mee t pipeline specifications, a nd specificati o n s f o r i n d u s t r i a l a n d the gas m u st be treated to separ ate o u t the acid gas co m ponents. Until the early 1

recovery and gas flaring were considered the m o st econom ic way s of dealing w i t h t h e

waste acid gases. In the early 1990s, the y early em ission from ga s flaring in A l b e r t a w 0.3 Mt SO 2 a nd 6 Mt CO 2

. However, due to publ ic concern, stri ng e n

a depressed sulphur m a rket. Gas processing plant opera tors, theref ore, have incr e a s i n g l gas injection in deep subsurface for m ati ons as the preferred alterna tive to flaring.

The first acid gas injection operation in Alberta wa s started in 198 9. B y 200 2, t h e r e w e

Figure 1: Gr owth of Active Acid Gas Injection Sites in West er n C a n a d a

The acid gas injection operations are m o stly locat ed close to the Rocky Mountain range, where the

5 % i n ject into dee p

s e r v o i r s . The co m position 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 injecti on rates for CO 2 and H 2 S were 0.26 and 0.2 Mt/ y re spectively

. Overall, clos e to 1. 5 Mt C O 2 and 1 Mt H 2 S have been injected t o date int o deep hy drocarbon reservoir s and saline aquifers in western Canad a fro m 1989 t o 20 00.

Details of the plant locations, acid gas injection co mpositions and site geolog y a r e given in t h e m a in report and ha ve onl y been su mmarised in this overvie w. produced gas in Canada tends to be “sour 3 ”. Of t h e acid gas injection operatio n s , 5 saline aquifer s a n d 4 5 % i n t o d e p l e t e d o i l / g a s r e

2 2 2 2

3 So ur g a s m eans t h at t h e nat u r a l gas c o nt ains acid ga s s p ecie s that ca n incl ude C O 2 , H 2 S a n d S O 2

.

ii

## Results and Discussion

e s t u d y are su mmaris e d with particular e m phasi s on what ca n be learnt fr om the acid gas injection operations that is transfer ab le to geolo g ical storage operations fo r CO 2 . The following

a

i t e s ,

•

• Operational s a fety and reservoir integrity

a n d t h e B r i t i s h

p e r a t i o n s m u st
i t h a p p l i c a t i o n s l e d o n t h o s e o f

i d g a s injection

at t h e applicants submit detailed inform ation regarding surface facilities, injection w e ll configurat ions, characteristics of the injection reservoir o r

r e r e viewed by

r c e s , m i ni m i ze

p p r o v al is granted, a set of licensed operati ng param e ters is established by the regulato r s. After that, the ope rators have t o subm it biannual progr e ss reports to the regulat or y agencies on their

i o n s i f they feel

e s u c h c a s e i s

c h e d u l e d i n t h e

o r y process fo r f o p e r a t i o n of acid gas injection sites. In addition, there is a tr ied and teste d surface

h i c h h a s a l l o w e d r e g u l a t o r s t o decide on enforce m ent of plant clos ures in the

event of conc erns regarding the operati on of t h e in je ction well and its possible im pact on the integrit y

n t h ose for CO 2
t i o n s p r o v i d e a

e r e no current

Operational knowledge base

After 14 y ears of operati on, a considerable know ledge base has now been built up relating to the operation of these acid gas injection fa cilities. Th i s knowledge base relates principall y t o pipeline transportation and operational experiences in surface and injection well operations, since no subsurface

r a b l e t o new CO 2 geological storage projects. The results o f t h

r e a s a r e disc ussed:

• Regulation of a c i d g a s i n j e c t i o n s Operational e xperience,

Regulation o f acid gas inj ection sites in Canada

The regulatory bodies concerned are: t h e Alberta Energy and Ut i l i t i e s B o a r d ( A E U B )

Colum b ia Ministry of Ener g y and Mi nes. In Albert a , a p p l i c a t i o n s f o r a c i d g a s i n j e c t i o n o conform to a set of specific requirem e nts given in Ch apter 4.2 of Guide 65 that d e a l s w for convent ional oil and gas reservoirs 4 . Requirem e n t s in British Colum b ia are m o d e l

Alberta. Pro s pective operators are required to a ppl y for and obtai n approval be f o r e a c operations c a n commence. The regul ators require th

aquifer, and injection operations. Befo re approval of any operati on, t h e a p p l i c a t i o n s a the regulatory bodies to ensure that they m a xi m i ze conservation of hy drocar b o n r e s o u environm enta l im pa ct and ensure public safety

.

W h e n a

operations. The regulatory bodies concerned will ex erci s e p o w e r s t o c l o s e d o w n o p e r a t that safety procedures required by the approval s c h e d u l e h a v e b e e n b r e a c h e d

. O n mentioned in the main report where injection pressur es wer e significantly h i g h e r t h a n s approval.

It is cl ear tha t , in both Alberta and Briti sh Colu m b ia, there is a we l l

- d e v e l o p e d r e g u l a t the approval o

m onitoring p r o c e d u r e w

of the reservoir. Regulations fram e d for acid gas in jection shoul d be m o re s t r i n g e n t t h a injection alone, becaus e H 2 S is a highly toxic chem ical species. H o w e v e r , t h e s e r e g u l a useful bench m ark for countries that are considering new CO 2 s t o r a g e p r o j e c t s w h regulations exist.

m onitoring is undertaken. Such operational experi ence should be directly tr a n s f e

4 Alb e rta En ergy Utilities Bo ard, Gu i d e 6 5 : Reso urces Ap p licatio n s fo r C o nv en tio n a l & Gas Reservo i rs, 200 0.

Th is can b e fou n d at: h ttp ://www.eub .go v .ab/b b s / p ro du cts/ g u i d e s/g65 .p df

iiiOperational safety.

p e r a t i onal staff

t i o n a l safety i s

e a s e of the acid

r a l steel tubing

a s i n g , w h i c h is

j e c t i o n w e l l t o l i n g a “packer ”

r a g e f o rmation. This is pressure tested for integrity once a y ear . A down-hole safety valve or check valve is

i d g a s f r o m the

i t h v a l v e s

.

b l i s h e d a r o u n d

t o r s a r e r e q u i r e d t o h a v e a

e c t i v e E R P

, t h e

a l a r m sy ste m s,

n s

.

s t r a n s p o r t i n g t h e acid gases are usually s hort typically 100 to 200m 5 and gene rally are

s i o n , a c o m m on d r a t i o n a l s o p r e v e n t s operational problems as sociated with hy drate fo rmation that can cause co mpressor break down and

t o s t o r e CO 2 in

i c a l r e s e r v o i r s , a l t h o u g h t h e acute toxicit y of H 2 S will warran t increased safety m e asures.

Rese

T r h e s e measure s i n c l u

r o v a l process re quires that a detailed a sses s m ent of the regional geology and

h i s p r o c e s s i s

e g e o l o g ical setting and char acteristics, another feature required in the

a p p s t f o r m a t i o n o r r e s e r v o i r , a n d t h e e potential

ndwater and/or

• The setting of licensed operating limits is a ke y feature in the regulatory process that is designed to protect the integrit y of the injecti on. The licensed operating parameters include th e

d m a xim u m injection vol um es. The bottom hole injection pressure is se t no higher than 90% of the fracture pre ssure to ensure that fracturing of the cap rock does not occur, but in many cases it is m u ch lower, even at 90% of the origina l reservoir pressure when injection ta kes place into a depleted oil or gas res e rvoir

. Since H 2 S is a highly toxic species, eve n small rele as es can c o n s t i t u t e a s e r i o u s r i s k t o o and the local environm ent. One of the key design features, therefore, in ensuring o p e r a that of the injection well. This has to be designed and operated to prevent acci d e n t a l r e l gas. In acid gas injection opera tions, the i n jection well t ypically consists o f a c e n t “string” (i.e. series of connected tubes) with an out er annulus b ounded b y a s t e e l c

ce mented to the subsurface formations. Several saf et y features are i n c o r p o r a t e d i n t h e i n prevent leakage. The casing is isolated from the t ubing string and the acid gas by i n s t a l in the annulus between the casing a n d t h e t u b i n g s t r i n g j u s t a b o v e t h e s u b s u r f a c e s t o

incorporated in the tubing string so that if som e th ing fails at the s u r f a c e , t h e f l o w o f a c formation will be prevented. The well head of the inj ection well is si m ilarly prot e c t e d w

As part of the regulatory process, it is required that an E m ergency Planning Z o n e i s e s t a the injection well in the case of an accidental release of acid gas. T h e o p e r a detailed em ergency respon se plan (ERP) for use in t h e event of a leak. To h a v e a n e f f area surrounding the i n j ection site should be eq uipped with H 2 S d e t e c t i o n a n d windsocks, self-contained b r e a t h i n g a p p a r a t u s , a nd rem o te unit and plant shut do w n s t a t i o

P i p e l i n e constructed of m ild steel. Pipelines are designed to mini m i se the risk of leakag e

. C o r r o cause of pip e line failure, is avoided by deh y dra ting 6 t h e a c i d g a s

. D e h y

pluggi ng.

Such operatio nal safety p r i n c i p l e s a n d e x p e r i e n c e a r e t r a n s f e r a b l e t o p r o j e c t s p r o p o s i n g

g e o l o g

rvoir integrity and protection of overlying water re source s

h e e a r e a n u m b er of me asures e m plo y e d to m a intain the integrity of the res e r v o i r

. T

d e :

• T h e a p p hy drogeology, is undertaken to select the location o f t h e i n j e c t i o n w e l l

. T designed to e v aluate the potential for leakage before approval is gr anted.

• K n o w l e d g e o f t h

r o v a l p r o c e s s , i s critical to assess t h e integrit y o f t h e h o short-and long-ter m fat e of the injected acid gas. Of parti c ular i m portan ce ar migration pathway s from the injection zone to ot her form ations, s h a l l o w g r o u the surface.

setting of the f o l l o w i n g :

o Maxi m u m we ll head and bottom hole injection pressures

o Maxim u m daily injection r a t e s a n

5 The r e a r e case s of pipelines up to 5500m

. 6 Mo isture co n t en ts o f less th an 0

. 5 m o le % are m a in tain ed b y rem o v i ng t h e water cond ensed after each

com p ression st age rather tha n usi n g a se para te dehy dration stage.

ivTypically, the fracture pressures ar e defined f r o m p r e s s u r e d e p t h

- c o r r e l a t i o n d a t a f o r t h e Alberta basin if site-specifi c tests have n o t been carried out.

neral resources, h e t y p e o f f l u i d

I I I wells under

i s n o t e d t h a t t h e

o i l r e c o v e r y in

a t l e s s s t r i n g e n t

o r

Class Ia wells that are designated for the i n jection of oil field and i ndustrial waste fluids 9

.

a r i n g z ones are

e l l

. H o w e v e r ,

o dies to stu d y

t r a s t c a n b e drawn with natural gas regul ations in Europe which

s l o c a t e d a b o v e

g a s s p read is to

g g e s t e d that an

U n d e r g r o u n d

A

, C l ass I well s

e q u i re a perm it.

, a p p e a r s t o b e C a n a d a

. O n e area where t h e regulations differ, howe v er, is that migration and

c t i on. There are

r e g u lator y and

n d i n s i g h t i n t o

i n t e g r ity of t h e

t h t h e c a p r o c k

l e s ) a n d s e c o n d w i t h t h e cements in the injection wells (both in existing and old abandoned wells that are puncturi ng, or penetrating the reservoir). Of these possible fai l ure m odes,

there is cons iderable concern with regard to the im p act that CO 2 alone co u l d have on cem e nts in

abandoned w e ll bores. Si nce many oil and gas fields in Canada ar e penetrated b y sig n ificant num bers of existing and abandoned wells, the potential risk of a failure could be high, wh ich could be enhanced

c k a n d i n j e ction well sing the long-term

g a s

. A key feature of the regul ations is prot ection of groundwater and other energy and m i and of equity and m i neral rights. The classific a tion of the injection wells is bas e d o n t they will hol d . Injection wells on acid gas projects are ty p i c a l l y c o n s i d e r e d a s C l a s s AEUB guidelines 7 , which covers wells in jecting hy drocarbon, inert and sour gases 8

. I t

sa me well cl assific a tion for acid gas injection applies to CO 2 i n j e c t e d f o r e n h a n c e d Canada. Testing and cementing requirem e nts for Cl ass Ib, II and III wells ar e s o m e w h

t h a n f

However Cl a ss Ib, II and I II wells have to be designe d to ensure t h at useable w a t e r b e isolated.

Possible m i gr ation pathwa y s are also an issue in the choice of loc a tion of the i n j e c t i o n w it is noted th at no su bsequent subsurfa ce m onitorin g is required b y the regu l a t o r y b

whether m i g r a t i o n i s o c c u r r i n g

. A c o n call for the monitorin g of vertical leakage b y gas m i gration (if an y ) towards th e a q u i f e r the reservoir to ensure that leakag e re mains m i ni mal and acceptable. Also, any l a t e r a l

be m onitored using a set of m onitoring wells 10

.

Also noteworth y , is a study undertaken b y Battelle for the USDOE 11 in which it was s u injection well for CO 2 int o a n a q u i f e r w o u l d b e C l a s s I u n d e r t h e p r o v i s i o n s o f t h e Injection Control (UIC) programme of t h e Federal Sa fe Drinking Water A c t. I n t h e U S

are wells that inject hazardous or non-ha zardous wast es into geological form ati o n s a n d r Much of t h e i n form ation required in the perm it applica tions for Cla s s I w e l l s i n t h e U S A

si m i l a r t o t h o s e f o r a c i d g a s i n j e c t i o n i n in the USA detailed groundwater modelling studies are required to study plum e

m onitoring will be required of surface water and overly ing aquifer used for water abstr a

a num ber of operational acid gas injection operations in the USA - co m p arison o f t h e U S

m onitoring requirem e nts with those in Canada m i g h t provi de additional infor m a t i o n a practices that might be adopted for CO 2 storage.

Another issue could be t h e reactions of the acid gas and its cons equent im pact on t h e reservoir. T h ere are two possible m odes of re action that could occur, first re a c t i o n w i (which in m o s t c a s e s a r e s h a

by the presence of H 2 S. The degree of reaction of the acid gas w i t h t h e c a p r o cements needs to be ful l y un derstoo d , otherwise there is a risk of comprom i

c o n t a i n m e n t o f t h e i n j e c t e d

7 Alb e rta En ergy Utilities Bo ard, Gu i d e 5 1 , In j ection and Disp o s al Wells – well classificatio n s , co m p leti o n , lo gg ing an d testin g , Mar c h 199 4.

8 It i s not e d i n s e veral o p erat i o ns t h e aci d gas i s di ssol v e d i n t h e p r od uce d wat e r a n d henc e, w h e n i n ject e d , t h e wel l cl assi fi cat i on bec o m e s IB or I I

9 Flu i ds to b e inj ected i n Class 1 a wells in clude: phenolic wa ste waters , acid or ca ustic sol u tions, aque ous sol u t i o ns o f ha l oge nat e d o r ga ni c com p o u n d s , sol u t i o ns c ont ai ni ng hea v y m e t a l s

. 10 I E A G r eenh ouse G a s R&D Pr og r a mm e File No te on G e o l og ical Stor ag e of CO 2 - C o n f licts with and ex perien ce

t o be gai n ed f

r o m nat u ral gas st ora g e, 4 th Janu ar y 20 01

. 11 Proj ect No . DE- R A C 2 6 -9 8FT40 418 , Car bon D i ox id e Sequ estr ation i n Salin e For m atio n s

– Eng i n e er in g and

Eco nom i c Ass e ssm ent – Fi na l Tech ni cal R e po rt , J u l y 9

, 20 01

vvi 

## 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 draw n 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 CO 2 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 CO 2 and other gaseous species. Such a project should consider both surface and sub–surface monitoring to provide confid ence on containment of th e 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 H 2 S might be trapped by mineral fixation is an important question to be resolved. Also, the impact on reservoir integrity, in terms of r eaction 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 CO 2 and 1 Mt H 2 S have been injected into deep hydrocarbon saline aquifers in western Canada. Whilst the quantities of gas injected are modest c

amount of CO 2 injected in CO 2 -EOR operations in th e USA and Canada, neverthe considerable body of knowledge implementation of CO 2 storage in the future. Information and experience exists on the re gas injection sites and the design and operation of compressors, pipe lines and injection relevant to larger CO 2 storage operations.

Any operation where gases are injected into geologi cal reservoirs will provide inform help develop confidence in geological storage of CO 2 . In the case of acid gas injectio demonstrated that the injected acid gases have been contained within the geological

it might be difficu lt t



## Recommendations

Consideration should be given to de veloping a monitoring project at a new acid gas injec at several facilities reflecting the range of reservoirs th at 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 injec tion operations...............................................................5 Compilation project a nd 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 operation s in the Alberta basin, Canada, at the end of 2002................................................................7

. Figure 4. Cumulative amount (all site s) of acid gas approved to be injected, and actually- injected into deep a quifers and reservoirs in the Alberta basin, Canada: a) injection rate, and b) volume.......................................................14

Figure 5. Cumulative amount (a ll sites) of approved CO 2 

### and H 2 

### S 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 CO 2 

### and H 2 

### S actually-injected into deep aquifers and reservoirs in the Albe rta basin, Canada, to the end of 2000: a) injection rate , and b) mass...........................................................16

Figure 7. Solubility of water in ac id gas as a function of pressure for: a) different acid gas composition (CO 2 

### and H 2 

### S) at 30 o 

### C, and b) different temperatures for an acid gas with a composition of 49% CO 2 

### , 49% H 2 

### S and 2% CH 4 

### (see also Lock, 1997; Wichert & Royan, 1996, 1997).................................................17

2

### Figure 8. Phase diagrams for methane (CH 4 

### ), carbon dioxide (CO 2 

### ), hydrogen sulphide (H 2 

### S) and a 50%-50% acid gas mi xture; hydrate conditions for CO 2 

### and H 2 

### S; and a 4-stage acid-gas co m pression c y cle (after W i chert & 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 Boar d, the regulatory agency in Alberta,

Canada AGS Alberta Geological Survey, a Group within AEUB ARC Alberta Research Council, a resear ch 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) ha ve been faced with a growing challenge to reduce atmospheric emissions of hydrogen sulphide (H 2 

### S), which is produced from “sour” hydrocarbon pools. Sour oil and gas are hydrocarbons that contain H 2 

### S and CO 2 

### , which have to be removed before the produced o il or gas is sent to markets. Since surface desulphurization through the Cl aus process is costly and the surface storage of the produced sulphur constitutes a liability, increas ingly more operators are turning to acid gas disposal by injection into deep geologi cal formations. Acid gas is a mixture of hydrogen sulphide and carbon dioxide (H 2 

### S and CO 2 

### ), with minor traces of hydrocarbons, that is the bypr oduct 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 inject ion operations is to dispose of H 2 

### S, significant quantities of CO 2 

### are being injected at the same time because it is uneconomic to separate the two gases. Actually, more CO 2 

### than H 2 

### S has been injected to date into deep geological formations in western Canada. In the context of curre nt efforts to reduce anthropogenic emissions of CO 2 

### , the acid gas injection oper ations in western Canada represent a commercial-scale analog ue to geological storage of CO 2 

### . The latter is an immediately-available a nd technologically-feasible means of reducing CO 2 

### emissions into the atmosphere that is particularly suited for land-locked regions located on sedimentary basins, such as the North Ameri can mid-continent. Large-scale injection of

CO 2 

### into depleted oil and gas reservoirs and into deep sali ne aquifers is one of the most promising methods of ge ological storage of CO 2 

### , 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 n eed addressing, the most important ones relating to the short- and long-term fate of the injected CO 2 

### . Thus, the study of the acid gas injection operations in western Canada provi des the opportunity to learn about the safety of these operations and about the fate of th e injected gases, and represents a unique opportunity to investigat e the feasibility of CO 2 

### geological storage. In the 13 years since the first operation in the world started injec ting acid gas into a depleted reservoir on the outskirts of the city of Edmonton in Albert a, no safety incidents have been reported except for a well blow-out in northern Al berta where the operator has significantly exceeded the permitted injection pressure. Given the H 2 

### S nature, which is more toxic and

corrosive than CO 2 

### , the success of these acid gas inj ection operations indicate that the engineering technology for CO 2 

### 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 inje ction 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 Utilitie s 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 maximi ze 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, inject ion well configurations, characteristics of the injection reservoir or aqui fer, and operations. After approva l for acid gas injection is granted, the operators have to submit to th e regulatory agencies bi annual progress reports on the operations. No applicati on 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 Albe rta was started in 1989, and the next one in 1994. To date, forty-seven applications for in jection of acid gas pr oduced at 42 different gas plants have been approved in wester n 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 th at in several places injection took or takes place in different units, or the quality of the in jected stream is different, in which case an application has to be submitted and approve d 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 inje ction cases themselves are referred to as injection sites. The Appendix presents the ca ptured information by in jection site, and not by operation.

Of the 42 approved operations, 39 were act ive 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 operation s, also in Alberta, have been rescinded after an active period, either because the in jection volumes reached the approved limit, and the operator moved to another site or in jection formation, or because the gas plant producing the acid gas has been decommissioned, with the s our gas being processed at another, nearby plant. At the Zama operation with multiple sites in northern Alberta, injection into two r eefal carbonate reservoirs has been shut down in 1998 and 2000 by the regulatory agency because the operator grea tly exceeded the approved injection volume or pressure. Figures 2 and 3 pr esent, respectively, the histogr am and location of acid gas injection operations in west ern Canada at the end of 2002.

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### 7

### Compilation Project and Report Structure

In January 2002, the Alberta Geological Surv ey (AGS), a group in the Alberta Energy and Utilities Board, and the Alberta Resear ch Council (ARC), jointly undertook a project funded by Canadian federal and provincial governments and agencies, and by the International Energy Agency (IEA) Gree nhouse 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 pr ior to December 2001. The original deadline of the project was Se ptember 2002. In June 2002, the first industry participant joined the project , at which time the funding spons ors agreed to expand the scope of the project to incl ude the 7 acid gas injection operations active in British Columbia and 4 additional acid gas operati ons approved in Albert a since December 2001. Concomitantly, the project deadlin e 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 ac id gas operations. Historical files with the respective regulatory agencies in Alberta and British Columbia were searched for applications for acid ga s injection operations, for approvals and amendments, and for the subsequent progre ss reports submitted by operators. Relevant information from these hard copy documents was entered into a database specially designed and implemented at AGS for inte rnal use and report generation. Several synthesis tables were generated that compile and present informati on from the acid gas injection sites. A series of self-explanator y graphs were produced on the basis of the synthesis tables, which are gr ouped into 3 categories: host ro ck, host fluids and injection operations. These reports and associated graphs are included in the Appendix.

Because the suitability for and approval of ac id gas injection operations are determined by the characteristics and containment propertie s of the injection aquifer or reservoir, which then affect operation and engineering ch aracteristics, the review is summarized in Tables 1 to 6 in the Appendi x in the following order. Tabl e 1 shows the geology of the injection unit and of the underlying and ove rlying formations. Table 2 summarizes the characteristics of aquifer a nd 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 facilitie s. In Table 3, the licen sed injection rate and volume for sites 4336 and 4343 of the same opera tion is the same, as explained in the footnote, although injection take s 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 th e acid gas injection operations, such as: injection wells, pipelines, and gas plant co mpressors, respectively. Tables 1-3 have only 47 lines each, correspondi ng to the 47 injection sites, whil e 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 th ere could be several injection wells. The plant

8

### designation number ends in “00”. The non-ze ro integers making up the plant number are the group indicator for the sites belonging to th at 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 agen cies 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 requi re an acid-gas application since they were originally water disposal operations th at 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

k eff 

### 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 wester n 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 da ta inconsistencies reflect the data and information as submitted by operators. Missing data for some s ites 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, approximate ly 25% of the required information is missing (Table 1). No analysis of the compile d 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 info rmation form the objective of another project phase.

HISTORICAL BACKGROUND

A significant portion of raw natu ral gas production in the Albe rta basin, Canada, contains varying percentages of aci d gas components, specifica lly hydrogen sulphide (H 2 

### S) and carbon dioxide (CO 2 

### ). 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 pr oduce solution gas that contains significant

amounts of H 2 

### S and CO 2 

### (e.g., 4% and 17% respectively at Wayne–Rosedale; Ho et al., 1996). Prior to 1988, if sulphur-recovery tec hnology could not economically remove the sulphur from the acid gas, the alternative wa s to burn the acid gas in flare stacks or incinerators. Each flaring source was permitte d 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 producin g 1 to 5 t/d, to 96% for plants producing more than 10 t/d. Neverthe less, even with sulphur recovery in place, significant volumes of tail, or acid gas, are ge nerated, and this is often flared from stacks at the well sites. In the early 1990s, the year ly average emission from gas flaring in the

Alberta basin was in the order of 0.3 Mt SO 2 

### and 6 Mt CO 2 

### (Longworth et al ., 1996).

Until the late 1980s and early1990s, sulphur recovery and acid gas flaring were considered the most economic ways of deali ng with the sulphur in sour and acid gases. As a result of public concern about flar ing, including environment degradation, human and animal health, and waste, the regulatory agencies increa singly require that operators reduce emissions, particularly in regions wh ere the public concern is high. Because the sulphur world supply is domina ted by recovered sulphur and environmental pressure has driven desulphurization to the point that th e supply has exceeded demand, large tonnages of sulphur are being poured into bloc k storage throughout the world (Connock, 2001), including the Alberta basin. Since desulphurization is un economic in a weak sulphur market, and flaring is publicly unacceptabl e, 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 attr active if, otherwise, ope rators have to build their own sulphur recovery plant or a pipeline to the nearest plant with available capacity, each alternative having its own di fficulties 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 an d fold belt that corresponds to sour gas production from deep reservoirs (Figure 3). Two sites in B.C. are actually located within

the thru s t a nd f old belt. At 2 6 sites approval was given to inje c t the a c id 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 le g 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 ga s 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 impose d by regulatory agencies to address H 2 

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

located in areas suitable for CO 2 

### storage in geological media in the Alberta basin (Bachu, 2000; Bachu & Stewart, 2002).

In 1989, Chevron Canada Ltd. started the firs t 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% H 2 

### S and 85% CO 2 

### 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% H 2 

### S and 80% CO 2 

### into a water-saturated carbonate reef in cen tral Alberta. Also in 1994, Chevron Canada Ltd. started acid gas injection at 30 MPa pressure into a ca rbonate aquifer 2800 m deep at Pembina, west of Edmonton. The approved acid gas composition is 74% H 2 

### S, 21% CO 2 

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

In 1995, PanCanadian Petroleum Ltd. started mi xing, 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 aqui fer 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 

### m 2 

### ), 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% H 2 

### S and 80% CO 2 

### ), with an estimated daily production rate of 21,000 m 3 

### /d, was the result of sweetening a 34 o 

### API

oil with an associated so lution gas containing 4% H 2 

### S and 17% CO 2 

### (Ho et al ., 1996). Injection takes place in a 26 m water-saturat ed carbonate-reef unit, characterized by 6% porosity, 150 x 10 -15 

### m 2 

### (150 md) permeability, 65 o 

### C temperature and 15.5 MPa formation pressure, confined by tight dolomite units. At in-situ conditions, the acid gas density is ~543 kg/m 3 

### (Ho et al ., 1996).

11

### In 1995, Pennzoil Canada Inc. star ted injecting a mix of 20% H 2 

### S and 80% CO 2 

### at 120,000 m 3 

### /d into a depleted oil reservoir in a pinnacle carbonate re ef ~1510 m deep at

Zama X2X in northern Albert a (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 overlai n by 60 to 90 m of anhydrite. The critical point of the acid gas mixture is 42 o 

### C and 7.64 MPa. At target operating conditions of

14.5 MPa and 76 o 

### C (initial reservoir pressure and temperature), the injected acid gas is supercritical, with a density of ~500 kg/m 3 

### and a viscosity of 0.04 cp (Davison et al

., 1999). The caprock threshold disp lacement pressure was measur ed in the laboratory to be 22.3 MPa. Considering that the initial differe ntial pressure across the caprock was ~7 MPa, the maximum operating pressure was established at 30 MPa. Because the formation water naturally contains si gnificant amounts of both CO 2 

### and H 2 

### S, acid gas injection was not expected to cause dissolution of reservoi r rock and/or precipitation. This site was subsequently shut down by AEUB because th e operator greatly exceeded the injection pressure limit.

To date, the largest operation in the Albert a basin in British Columbia (sites 4336 and 4342 in the Appendix) is also the largest in the world, with a licensed cap acity of 391,000

m 3 

### /d, but operating only at 280,000 m 3 

### /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% H 2 

### S and 15% CO 2 

### (340 and 78 t/d H 2 

### S and CO 2 

### , respectively), and the approved injection rate a nd 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 a nd 3581. Sites 2469 and 3465 are actually water disposal sites with a minor amount of dissolved acid gas (“s our water” disposal) and injection at thes e sites is done “randomly” through 49 and 19 wells, respectively. Because these are water disposal schemes appr oved previously as such, the operators did not have to submit a special application to th e 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 wa s rescinded in 1999 because it reached the approved limit, and it was immediately re placed by injection into an underlying formation (site 320 in the A ppendix) 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 operati on continues into an aquifer (site 1522). One operation in the Pe mbina 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 vari es from site to site, from 85% H 2 

### S and 15% CO 2 

### to 2% H 2 

### S and 98% CO 2 

### . Figure 4 presents the variation since 1989 of the approved and actual injection rates and volum es, cumulative for all active acid gas injection operations in western Canada. Figure 5 shows the corresponding approved in jection rates and

volumes of H 2 

### S and CO 2 

### , 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 inject ion 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 CO 2 

### and H 2 

### S in the Alberta basin reached 0.26 and 0.20 Mt/yr, respectively, with a total of 1.1 Mt CO 2 

### and 0.6 Mt H 2 

### S injected to date (Figure 6), driv en by the need to dispose of H 2 

### S driven by the need to dispose of H 2 

### S. All the injection rates and volumes presented in this report are at standard conditions (15 o 

### C and 101.3 kPa).

SITE SELECTION AND OPERATIONS

In Alberta, applications for acid gas dispos al must conform to the specific requirements listed in Chapter 4.2 of Guide 65 that deals wi th applications for c onventional 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 consid erations that relate to: proximity to sour oil and gas production that is the source of aci d gas; confinement of the injected gas; effect of acid gas on the rock matrix; protection of energy, mineral and groundwater resources; equity interests; we llbore integrity and pub lic safety (Keushnig, 1995; Longworth et al ., 1996). The surface operations and th e subsurface aspects of acid gas injection depend on the properties of the H 2 

### S and CO 2 

### mixture, which include, but are not limited to non-aqueous phase behavior , water content, hydrate formation and the density and viscosity of the ac id gas (Carroll & Lui, 1997; Ng et al ., 1999). Knowledge of the phase equilibria for acid gas allows th e optimization of the injection process while addressing corrosion, hydrate formation a nd compressor-outlet pressure concerns.

Acid Gas Properties

The acid gas obtained after the removal of H 2 

### S and CO 2 

### from the sour gas may also contain 1% to 3% hydrocarbon gases, and is sa turated 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 H 2 

### S and CO 2 

### , hence in acid gas, decreases as pressure increases up to 3-8 MP a, depending on temperature, after which it dramatically increases (Figure 7). The solubi lity minimum reflects the pressure at which the acid gas mixture passes into the dense liqui d 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 aci d gas, to avoid pipe and well corrosion, by

13

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### com p ressing the gas from about 100 kPa to around 8 to 10 MPa for injection, and reducing thus the water content to less th an half a m o le % (W ichert & Royan, 1996, 1997).

While there are not m a ny published properties of the acid gas m i xture, the properties of pure CO 2 

### and H 2 

### S have been thoroughly exam ined a nd reported. In their pure state, C O 2 

### and H 2 

### S have sim ilar phase equili bria, but at different pr essures an d tem p eratu r es (Carroll, 1998a). They exhi bit the norm a l vapour/liquid be havior with pressure and

tem p erature (Figure 8), with CO 2 

### condensing at lower temperatures than H 2 

### S. Methane (CH 4 

### ) also exhibits this behavior , but at m u ch lower tem p eratures. 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) locate d between the unary bounding system s in the

pressure-temperature s p ace (Figu r e 8). If water is pres ent, both CO 2 

### and H 2 

### S for m hydrates at tem p eratures up to 10 o 

### C for CO 2 

### and m o re than 30 o 

### C for H 2 

### S (Carroll & Lui, 1997). If there is too little wa ter, the water is di ssolved in the acid ga s and hydrates will generally not form . However, phase diagram s show that hydrates can form without free water being present (Carroll, 1998a,b), t hus operating above the hydrate-form ing

tem p erature is desirab l e.

The properties of the acid gas m i xture are important in facility design and operation because, to optim ize sto r age and m i nim i ze risk, th e acid gas needs to be injected: (1 ) in a dense-fluid phase, to increase storage capaci ty and decrease buoyancy; (2) at bottom

- hole

1 8

### pressures greater than the formation pressure, for injectivity; (3) at temperatures in the system generally greater than 35 o 

### C to avoid hydrate forming, which could plug the pipelines and well; and (4) with water conten t 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 specif ications. A variety of solvents, solvent mixtures and processes are available for gas sweetening; and the selection of the optimum solvent or solvent mixture, and proces s depends on a variety of factors such as sour gas composition, pipeline specificati on, and compression requirements. In western Canada, the gas sweetening processes empl oy amines or amine derivatives as the

chemical solvents of choice. In the sweet ening process, after separation of any gas liquids, the sour gas is flowed through a contactor or ab sorber 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 th e sweet components of the natural gas to pass on through. By the time the natural gas reac hes the top of the tower, all of the CO 2 

### and H 2 

### S 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 efficien cy of the process, better amine forms are being developed, and other solvents are bei ng used in multi-stage separation processes (chemical solvents – e.g. K 2 

### CO 3 

### ; 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 170 o 

### C. 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 compre ssion are required to provide the required discharge pressure (Figure 8). During comp ression, the acid gas mi xture 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 H 2 

### S. In the limit, compression temperatures maintained above 35 o 

### C will avoid hydrates forming (Figure 8).

Even if hydrate forming is avoided, excess water accelerates corro sion 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 4 th 

### 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 ga s, and more than counteracts th e decrease in solubility due to interstage cooling. Hence, a separate de hydration 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 stag e and by keeping the temperature a few degrees above the hydrate stability temperatur e, 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 requi red 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. A dditional safety precautions require addition of chemical inhibitors to the acid gas str eam (e.g., methanol to lower hydrate formation temperatures, and glycol to extract the exces s water from the acid gas stream) or use of special corrosion-resistant steels. Both a dd 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 tran sported through a pipeline to the injection wellhead usually at a short distance from the ga s 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 th e 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 lo ss or gain due to elevation change from the compressor to the well hea d, 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 storag e formation, which depends on the thickness and permeability of the formation and on the viscosity and density of the acid gas at in situ conditi ons. The high pressure s 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%. Consider ing that in most cases the pressure of the subsurface injection formation is near hydro static, the hydraulic head provided by the acid gas provides a significant amount of the to tal pressure required to inject it into the

subsurface formation.

Several safety features are gene rally incorporated in the inject ion 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 inte grity 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 formatio n to the surface will be prevented. The wellhead of the injection well is similarly pr otected with valves. Other safety measures

can be taken if needed.

Although a number of safety valves are alwa ys 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 ar e required to have a deta iled emergency response plan (ERP) if a leak occurs that may impact hum ans. An emergency planning zone, the EPZ (i.e. area of land which may be impacted by the release of H 2 

### S), is defined around the sour gas facility. To have an effective ERP, the area surrounding the in jection site should be equipped with H 2 

### S detection and alarm systems, wi ndsocks, self-contained breathing apparatus, and remote unit and plant shutdown stations.

Subsurface Considerations

The general location for an acid-gas injection we ll 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 geol ogy and hydrogeology, which is designed to evaluate th e 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 conf ining layer (caprock), and any stratigraphic traps or fractures that may affect its ability to contain the acid gas; 3. location and extent of the underlyi ng or lateral bo unding formations; 4. folding or faulting in the area, and an assessment of seismic (neotectonic) risk; 5. rate and direction of the natural flow syst em, to assess the potenti al for migration of the injected acid gas; 6. permeability and heterogeneity of the injection zone; 7. chemical composition of the formation flui ds (water for aquife rs, 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 requirement s, the regulatory agencies require that environmental concerns must be addressed, such as injection-formation suitability, wellbore integrity, operating para meters (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 oilfie ld or industrial waste

fluids. Class Ib wells are used for the dis posal of produced wate r and common oilfield

waste streams. Class II wells are used for th e disposal of brine and brine-equivalent fluids. Class III wells are used for the injec tion 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. Becau se 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 de signation (AEUB, 1994). Completion and logging requirements are simila r for Class II and III wells, and include: 1. all geological zones must be iden tified using logs and/or cores; 2. all potential hydroc arbon-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 syst em 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 char acteristics is critical to assess the integrity of the host formation or reservoir, and the shor t- and long-term fate of the injected acid gas. Of particular importance are potential migr ation 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 (“memb rane”), natural and/or induced fractures (“cracks”) through the confining strata, a nd improperly completed and/or abandoned wells (“punctures”). To avoid diffuse gas mi gration 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 th e 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 th at fracturing is not induced. The maximum bottomhole injection pr essure is set by regulatory agencies at 90% of the fracturing pressure. In the absence of site-speci fic 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 in to a depleted oil or gas reservoir has the advantages of injection pressures being low and of wells and pipeli nes being already in place (Keushnig, 1995).

REVIEW OF OPERATIONS

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

Subsurface Characteristics

The depth of the injection zone varies mo stly 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, defi ned 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 underlyi ng a reservoir. Of these, 28 are in carbonate rocks and 19 are in sandstones (Table 1). Shales constitute the overlyi ng confining unit (caprock) in most cases, although tight limestones, evaporit es 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 10 1 

### -10 2 

### mD (Table 2).

Formation temperature varies between 35 o 

### C at 1397 m depth and 110 o 

### C at 3432 m depth (Table 2), although higher temperatures than the lowest one are recorded at shallower depth (e.g. 56 o 

### C at 1138 m), and a relatively low temperature (82 o 

### C) 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 tr end of increasing gradients from the south, where they are as low as 20 o 

### C/km, to the north, where they reach more than 50 o 

### C/km (Bachu, 1993).

The original formation pressure is generally subhydrostatic with re spect to freshwater,

which is characteristic of the Alberta ba sin (Bachu, 1999), and, except for one very low case of 5915 kPa that actually corresponds to a sour wate r 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 re servoirs, 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 in jection 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 CO 2



### .

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 th e vicinity of evapori tic beds. The very high salinity encountered at a relatively sha llow 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 (33 o 

### API to

68 o 

### API) (Table 2). Because acid gases will li kely have a lower minimum miscibility pressure (MMP) than conventi onal hydrocarbon gases, their us e in enhanced oil recovery often warrants consideration, as was done in th e case of one of the Za ma 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, consid eration may be given also for its use in enhanced gas recovery.

Licensed Operations

The licensed parameters for the acid gas opera tions are listed in Table 3. The composition of the acid gas licensed for in jection varies between 15% CO 2 

### and 85% H 2 

### S, and 98%

CO 2 

### and 2% H 2 

### S, with C+ gases for the balan ce. 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 h ead pressure (WHIP) is generally lower than the formation pressure, except for the few cases where the injection reservoir has been depleted prior to opera tions start up. The maximum approved bottom hole injection pressure (BHIP) is always hi gher than the formation pressure, to ensure injectivity. Approved daily injection rate s vary between 2,800 and 900,000 m 3 

### /day, and maximum allowed injection volumes vary between 6

⋅ 10 6 

### and 1,876

⋅ 10 6 

### m 3 

### . Operation lifetime ranges generally from 10 to 25 year s. In the case of the 2.8 years life-time operation (Table 3), the operator ha s indicated in the original a pplication that it will seek approval for another site in due time. Emergenc y planning zones in cas e of an accidental acid gas escape into the atmosphere vary betw een 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 fres h water, KCl water, produced wa ter, 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 st ainless steel. The majority of the pipelines are mild carbon steel. Currently, stress levels in the pipeline are less than ha lf 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 H 2 

### S and CO 2 

### , with accessory water vapour and hydrocarbon components. Table 6 summarizes the characte ristics of the gas plant compressors. The majority of the compre ssors are diesel. Four-stage compression dominates, with power ranging from 50 to 400 0 HP. The design discharge rate of the acid gas stream ranges from 7,000 to 800,000 m 3 

### /day (i.e. flow rates through the compressors). Generally, the rates of injec tion 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 injec tion pressures range from 2.8 MPa to 8.9 MPa. In the majority of cas es 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 compresse d 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 envir onmental and safety-related, and they directly affect the economics of acid gas injection. Eith er a slow or rapid ac id 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 H 2 

### S leaks.

Subsurface issues are of two in ter-related categories: the eff ect 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 reser voir, and create weak carbonic and sulphuric acids. This leads to a significant reduction in pH that accelerates water-rock reactions. Depending on mineralogy, rock di ssolution or precipitation may occur, affecting the porosity and permeability of the host rock. The fact that both CO 2 

### and H 2 

### S are dissolving in the formation water lead s to some complex reaction paths (Gunter et al

., 2000; Hitchon et al ., 2001) where carbonates precipitate and dissolve, and pyrite/pyrrhotite precipitates. Dissolution of so me of the rock matrix in carbonate strata, or of the carbonates surrounding the sand grai ns in sandstone units results in lower injection pressures in the short term. A majo r concern with the injection process is the potential for formation damage and reduced in jectivity in the vicinity of the acid gas scheme. The reduction in injectivity could possibly be the result of fines migration, precipitation and scale potentia l, oil or condensate banki ng and plugging, asphaltene and elemental sulphur deposition, and hydrate plugging (Bennion et al ., 1996).

Cement compatibility with the acid gas, pr imarily 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 th e 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 pr ior 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 degrad ation, leading to possi ble leaks through the well annulus and/or along casing.

If the acid gas is injected in to the originating or other oil or gas pool, the main concern is the impact on further hydrocarbon recovery fr om the pool and acid-gas production at the

25

### pump, although the operation may prove su ccessful, 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, inte rplay between driving forces, like buoyancy, and aquifer hydrodynamics, and aquifer heterogene ity, 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, an d 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 disp osal zone is isolated by a fault from an adjacent pool in the same formation producing oil with a high H 2 

### S 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. Howe ver, 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 in jected as a dry gas or a solution gas, depending on the wastewater available. The size of the operations approve d to date in western Canada is relatively small, with approved injection rates a nd volumes generally less than 0.1 million m 3 

### /d and

200 million m 3 

### , respectively, with no obvious histor ical trend, although a few very large operations have been approved in 2002 (Figure 9). One may in itially 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 geologi cal considerations th an of technological

know-how.

Compared to other options, acid gas injecti on has less environmental consequences than sulphur recovery (where l eaching of the sulphur piles can lead to groundwater contamination) or flaring (which essentially substitutes SO 2 

### for H 2 

### S in the atmosphere, as well as releasing CO 2 

### ). Knowledge of the phase-equilibri a and properties of the acid gas is extremely important in designing a sa fe injection operation, which minimizes corrosion, hydrate formation and cavitation, leadi ng to a dense-fluid phase for injection. Both monitoring for gas leaks and corrosion, a nd plans for mitigation if a leak occurs, are an essential part of the technology.

Equally important for a safe acid gas injec tion operation is the pr oper 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 c onfining aquitard (or cap rock), 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

CO 2 

### . The experience gained so far in North Am erica, particularly in Canada, can be applied elsewhere in the world. As gas resour ces become more depleted, deeper and more sour gas will be produced; and therefore appl ication of this tec hnology will result in the reduction of significant CO 2 

### emissions even without the incentive of CO 2 

### 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 CO 2 

### and 1 Mt H 2 

### S have been successfully injected into deep hydrocarbon reservoi rs and saline aquifers in Ca nada alone. If one considers also the 16 operations in the United St ates, this experience shows that CO 2 

### storage in geological media is a technology that can suc cessfully be expanded to and applied in large-scale operations that will reduce CO 2 

### emissions into the atmosphere from large CO 2 

### point sources. The technology an d experience developed in the engineering aspects of acid gas injection operations (i.e., design, mate rials, leakage prevention and safety) can be easily adopted for large-scale operations for CO 2 

### geological storage, since a CO 2 

### stream with no H 2 

### S is less corrosive and hazardous. A lthough 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 CO 2 

### -storage site should have. This informa tion can be used for the screening and identification of future sites for the ge ological sequestrati on and storage of CO 2 

### . 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, H 2 

### S has the potential to become a valuab le energy source. Besides hydrocarbons, sulphur and H 2 

### S represent the only additional store of chemical energy that occurs naturally on Earth in substantial quantity (C onnock, 2001). Just as CH 4 

### is oxidized to

CO 2 

### to recover energy, oxidation of H 2 

### S to SO 2 

### can provide energy. If technology can be developed to make this economically attr active, then the acid gas components for injection would become CO 2 

### and SO 2 

### instead of CO 2 

### and H 2 

### S (Connock, 2001).

REFERENCES

Adams, G. H. & Rowe, H. G. 1981. Slaughter Estate Unit CO 2 

### pilot – surface and downhole equipment construction a nd operation in the presence of H 2 

### S. Journal of Petroleum Technology

, 33:6 , 1065-1074. AEUB (Alberta Energy a nd Utilities Board) 1994. Guide 51: Injec tion and Disposal

Wells. Alberta Energy and Utilities Board, Calgary, AB. DOI eub.gov.ab.ca/bbs/produ cts/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/bb s/products/guides/g65.pdf. Bachu, S. 1993. Basement heat flow in th e Western Canada Sedimentary Basin: Tectonophysics, 222:1 , 119-133.

28

### Bachu, S. 1999. Flow systems in the Albert a Basin: Patterns, types and driving

mechanisms. Bulletin of Canadian Petroleum Geology

, 47 , 455-474. Bachu, S. 2000. Sequestration of carbon dioxide in geological medi a: criteria and approach for site selection. Energy Conversion and Management

, 41:9 , 953-970. Bachu, S. & Stewart, S. 2002. Geological se questration 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 47 th 

### Annual Technical Meeting of the CIM Petroleum Society , Calgary, AB, June 10-12, 1996. Carroll, J. J. 1998a. Phase diagrams re veal acid-gas inje ction subtleties. Oil & Gas

Journal

, 96:9 , 92-96. Carroll, J. J. 1998b. Acid-gas in jection encounters diverse H 2 

### S, water phase changes. Oil

& Gas Journal

, 96:10 , 57-59. Carroll, J. J. & Lui, D. W. 1997 Density, pha se 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. & Hutche on, I. 2000. Aquifer disposal of acid gases: modeling of water-rock react ions 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. & Dugw orth, 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 dis posal – 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, Ca lgary, AB, Canada, 28 April – 1 May 1996, SPE, 181-192. Ng, H-J., Carroll J. J. & Maddocks, J. R. 1999. Impact of ther mophysical 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 pr oves 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 injectio n 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

3 1Table 1: Reservoir GeologySiteNo.UnitTypeName Lithology Thk (m)Underlying FormationName Lithology Thk (m)Caprock FormationName Lithology Thk (m)Injection FormationInj. Zone Depth Net PayContainedFluidHalfway Fm Charlie Lake Fm Doig Fm479101Oil & GasShaly siltstone31215561552 -4 SandstoneReservoir Qtz-sandstoneBelloy Fm Montney Fm Taylor Flat Fm37396250WaterSandstone32019421905 -13 SiltstoneAquifer SandstoneWabamun Gp Exshaw Fm Graminia Fm20310130WaterSiltstone44929182715 -10 ShaleAquifer LimestoneWabamun Gp Exshaw Fm Graminia Fm2187130WaterArg-silty carb.58125032285 -10 ShaleAquifer LimestoneEllerslie Mbr Ellerslie Mbr Ellerslie Mbr171412OilShale62514391422 -17 ShaleReservoir SandstoneWabamun-Winterburn Exshaw Fm Winterburn Gp276 10WaterLimestone718981705 -100 ShaleAquifer LimestoneWabamun Gp Banff Fm Blueridge Mbr650190WaterDolomitic shale84422282222 -8 LimestoneAquifer LimestoneHalfway Fm Charlie Lake Fm Doig Fm102515OilShaly siltstone99714011391 -AnhydriteReservoir SandstoneLeduc Fm Ireton Fm Cooking Lake Fm188518OilCarbonates103426952677 -18 ShaleReservoir DolostoneNordegg Mbr Lower Mannville Fm Pekisko-Banff211515Oil & GasDolomitic shale118915621541 -6 ShaleReservoir SandstoneWabamun Gp Exshaw Fm955010OilCarbonates124218401745 -88 ShaleReservoir DolostoneWabamun Gp Exshaw Fm131 8Oil139620581927 -50 ShaleReservoir DolostoneKiskatinaw Fm Belloy & Kiskatinaw Golata Fm352185GasShale148913901355 -8 AnhydriteReservoir Qtz-areniteKeg River Fm Muskeg Fm270Water15101493 -EvaporitesReservoir DolostoneSlave Point Fm Fort Simpson Fm Fort Vermilion Mbr681513GasAnhydrite152213851317 -8 ShaleReservoir LimestoneZama & Keg River Muskeg Fm Lower Keg River1074575Oil & GasCarbonates156315851478 -25 AnhydriteReservoir CarbonatesBelloy Fm Montney Fm Debolt Fm12 240WaterDolostone163016731661 -10 ShaleAquifer SandstoneLeduc Fm Ireton Fm22Water17341200 -30 ShaleReservoir DolostoneKeg River Fm Muskeg Fm Chinchaga Fm5635150WaterAnhydrite189511661110 -18 EvaporitesAquifer DolostoneWabamun Gp Ellerslie-Wabamun Graminia-Blueridge7WaterShaly siltstone19711167 -16 Lime mudstoneAquifer LimestoneBeaverhill Lake Gp Leduc-Cooking Lak150Water20811958 -10 Lime mudstoneAquifer Dol. LimestoneKeg River Fm Muskeg Fm Chinchaga Fm8135140WaterAnhydrite210114541373 -81 AnhydriteAquifer DolostoneKeg River Fm Muskeg Fm Lower Keg River49 85WaterDolostone227116501601 -15 EvaporitesAquifer DolostoneAcid-gas Injection OperationsAlberta Geological Survey32SiteNo.UnitTypeName Lithology Thk (m)Underlying FormationName Lithology Thk (m)Caprock FormationName Lithology Thk (m)Injection FormationInj. Zone Depth Net PayContainedFluidLeduc FmWater2469-Reservoir CarbonatesUpper Leduc Nisku Fm Lower Ireton1121020WaterShale257314531341 -40 DolostoneAquifer DolostoneWabamun Gp Banff Fm Wabamun-Winterbu6690168WaterLimestone263628472781 -60 LimestoneAquifer DolostoneBelloy Fm Montney Fm Taylor Flat Fm8270250WaterCarbonate-rich271921182036 -10 Shaly siltstoneAquifer Siliciclastics & caKeg River Fm Prairie Evaporite F Cambrian System17 185WaterClastics283014331416 -10 SaltAquifer DolostoneBelloy Fm Montney Fm Stoddart Gp21 264WaterCarbonates298216101589 -29 ShaleAquifer SandstoneCooking Lake Fm Duvernay Fm Mildred Mbr805142WaterLimestone308420902010 -40 ShaleAquifer LimestoneLeduc Fm Ireton Shale Waterways Fm54 2WaterShale319519341880 -5 ShaleAquifer DolostoneOstracod-Basal Qtz104Water334012861182 -3Aquifer SandstoneBasal Quartz Sd71Water3465984913 -Aquifer ClasticsCummings Mbr Lloydminster Mbr Woodbend Gp29OilCarbonates3581838809 -SandstoneReservoir SandstoneGlauconitic Ss Upper Mannville Fm Glauconitic & Sunbu750Oil & GasShale & siltston3651-4 Shale & siltstoneReservoir SandstoneBelloy Fm Montney Fm Taylor Flat Fm4345199WaterDolomitic shale372024502407 -26 ShaleAquifer SandstoneKiskatinaw Fm Taylor Flat Fm Golata Fm413020WaterShale380418011760 -24 Sand & shaleAquifer SandstoneNisku Fm Calmar Fm Nisku-Upper Ireton92 4WaterDolomitic shale396834783386 -14 ShaleReservoir CarbonatesBaldonnel Fm Nordegg Mbr Charlie Lake Fm48Oil405815351487 -30ReservoirPardonet FmCharlie Lake Fm182GasAnhydrite417428152633 -27Reservoir CarbonatesDebolt Fm Stoddart Gp32Oil424821962164 -15 SiltstoneReservoir CarbonatesHalfway Fm Charlie Lake Fm Doig Fm61189185WaterShale429217131652 -9 DolostoneAquifer SandstoneHalfway Fm Charlie Lake Fm Doig Fm273559WaterShale433616171590 -13 AnhydriteAquifer SandstoneHalfway Fm Charlie Lake Fm Doig Fm273559WaterShale434316171590 -13 AnhydriteAquifer SandstoneBaldonnel Fm Nordegg Mbr Charlie Lake Fm5840020GasAnhydrite448913551297 -25 ChertReservoir DolostoneKiskatinaw Fm Kiskatinaw Fm Golata Fm133025GasMudstone451224562443 -10 ShaleReservoir SandstoneDebolt Fm Montney Fm75 83Water46801025950 -4 ShaleAquifer CarbonatesAcid-gas Injection OperationsAlberta Geological Survey33Table 2: Reservoir Properties and FluidsSiteNo.Reservoirvolume(1000 m3)Porosity(fraction)Permeability(md)Formation PressureFormationTemperature(°C)Original Startup(kPa) (kPa)Na(mg/l)Ca(mg/l)TDS(mg/l)HCO(mg/l)APIgravitySpecificgravityMolecularmassFormation Water Oil Produced Gas3Avg.Injectiondepth (m)312 1520068 NA 37.3 0.712 20.621554 15320 0.12 1670076 53400 4760 471 NA NA NA1620006101924 30449 0.06 27000 41530 9830 481 NA NA NA1528135692817 75581 0.08 2024470NA NA NA3202394 35625 0.15 1024560 NA 23200 2880 397 0.684 19.8694005391431 50718 0.10 5915 21605 5756 293 NA NA NA843844 0.20 1776269NA NA NA1072225997 0.12 1280060 9500 9289 340.8 869 0.7022 20.341396 61034 0.16 2858882 NA 37 0.742 21.5742686 1241189 1213558 4215 16850 3964 105 0.6695583016311552 1551242 0.05 1798258 NA 56.6 NA NA5217931396 0.05 2031763 NA 33.4 NA NA11519931489 0.21 1303547 6100 52095 5485 278 NA1567221821373 5001510 0.06 1500079 5842 35.2 NA NA3421522 0.08 1339449 3110 NA13511563 0.04 1447976 13394 48600 11400 1435 36.15 0.691 2016835545015321630 0.18 1670057 12855 54500 5240 257 NA 0.604 17.515680439616671734 0.10 53 9465 27100 11100 771 68.1 0.73 21.11200001371001895 0.05 1116456NA NA NA26600030811381971 0.13 890045NA NA NA2012081 0.07 1570071 15700 NA NA NA6712101 0.04 1129252NA NA NA22614142271 0.05 1323758 13237 NA NA NA135000130016262469NA 32600 4510 552 NA 1.121 NA1066182573 0.22 35 7500 24330 3160 971 NA 1.024 NA78924508413972636 0.09 24680103NA NA NA3072814Acid-gas Injection OperationsAlberta Geological Survey34SiteNo.Reservoirvolume(1000 m3)Porosity(fraction)Permeability(md)Formation PressureFormationTemperature(°C)Original Startup(kPa) (kPa)Na(mg/l)Ca(mg/l)TDS(mg/l)HCO(mg/l)APIgravitySpecificgravityMolecularmassFormation Water Oil Produced Gas3Avg.Injectiondepth (m)2719 0.12 2000076NA 0.62 36.7914000033020772830 0.06 1379038 106920 21976 126 NA NA NA34143024114252982 0.20 1374460 54500 5240 257 NA 0.604 17.515680420916003084 0.05 70 15459 48930 30968 166 51.5 0.65 18.82226634812050 303195 0.06 65 15500 30200 11100 895 NA 0.915 26.51224494161907 1533340 0.16 930051 1700 NA 0.693 20.4512343465NA NA NA9493581 0.30 5200 NA NA230824 65003651 11500 1170 0.851 24.63720 0.12 2308482 55253 2505 795 NA NA NA159216232024293804 0.11 1650063 60100 4330 207 NA NA NA1620003791781 93968 0.10 35860110 11000 NA NA NA615009203432 6934058 0.09 68 8300 13793 173 3853 NA NA1511 54174 3214582 4200 21200 146 5338 NA3648002724 14248 0.04 76 17596 0.629 18.2376000114121804292 0.12 1568564 8549 110 854 NA NA NA2374216834336 0.12 1311361 66490 2442 2330 NA NA NA177691386316044343 0.12 1311361 29600 1420 807 NA NA NA16044489 0.10 1115464 6031 13793 173 3853 NA13264512 0.09 2313382 2000 NA 0.573 16.624504680 0.10 53 7670 26900 1620 555 NA 0.593 38.4177800988 10401Acid-gas Injection OperationsAlberta Geological Survey35

## Table 3: Licensed Operations

Site

No. CO (mol frac) H S (mol frac) Licensed In j . Gas

2 2 Total Approved Inj. Volume

(1000 m3) Maximum Approved

BHIP (kPa) WHIP (kPa) Life time EPZ (km) (years) Max. Approved Injection Rate

(1000 m3/d)

0.25 0.75 312 14910 5000 10 3.0 27 34500

0.32 0.66 320 22000 8000 15 3.5 60 263000

0.15 0.75 449 33000 12000 5.3 30 63000

0.79 0.20 581 35800 13000 10 6.2 34 124100

0.57 0.42 625 10546 9000 20 58 213000

0.31 0.01 718 8596 3750 0.0 6 6000

0.65 0.35 844 20300 10500 15 2.4 16 38000

0.44 0.34 997 26000 13000 10 1.1 4.2 16000

0.31 0.63 1034 31380 12300 25 5.5 12 40000

0.95 0.04 1189 11000 7500 15 0.4 40 70000

0.29 0.67 1242 21500 9000 20 3.7 2.8 8100

0.45 0.52 1396 20303 12000 11 5.0 18 35000

0.57 0.41 1489 13035 7100 25 3.7 5 18700

0.70 0.30 1510 16707 12000 1.7 210 88000

0.70 0.30 1522 21000 11000 3.0 210 220000

0.61 0.38 1563 14500 12000 8 17.0 160 157000

0.70 0.30 1630 17982 10000 15 1.3 21 94200

0.87 0.13 1734 9000 15 35 64000

0.34 0.64 1895 11500 7000 15 2.0 65 140000

0.80 0.17 1971 18220 9800 10 2.0 11 41000

0.50 0.48 2081 21760 11700 15 2.9 40 185100

0.34 0.64 2101 18925 7600 15 3.8 26.3 106000

0.75 0.25 2271 18192 9500 15 3.2 74.6 290000

0.50 0.50 2469 8273

0.70 0.17 2573 15274 8000 1.5 45 160000

0.45 0.55 2636 10500 28 109000

0.51 0.49 2719 24607 9000 20 5.0 42 150000

0.88 0.09 2830 22000 10000 12 1.2 24 86000

0.71 0.25 2982 14210 9000 15 2.2 21 58200

0.72 0.25 3084 20000 10000 15 1.9 25 115000

0.82 0.17 3195 20000 10000 15 1.0 28 140000

0.83 0.15 3340 6000 6 30000

0.60 0.13 3465 11000

Acid-gas Injection Operations A lberta Geological Surve y Footnote: For Site No. 4343 see Site No. 4336 for the total approved injection rate and volume (same operation) 

### 3 6Site

No. CO (mol frac) H S (mol frac) Licensed In j . Gas

2 2 Total Approved Inj. Volume

(1000 m3) Maximum Approved

BHIP (kPa) WHIP (kPa) Life time EPZ (km) (years) Max. Approved Injection Rate

(1000 m3/d)

0.70 0.30 3581 6700 12 16000

0.98 0.02 3651 23500 8500 10 0.1 130 649000

0.29 0.70 3720 37400 19000 25 5.0 106 956000

0.28 0.69 3804 17576 5500 20 3.8 24.5 180000

0.15 0.85 3968 33000 12000 8 8.5 340 430000

0.48 0.50 4058 17600 9790 5.2 114 416000

0.15 0.81 4174 30600 12135 2.8 900 1330000

0.60 0.40 4248 20000 10500 20 1.8 69 380000

0.60 0.40 4292 10500 2.0 69 16600

0.15 0.85 4336 23000 10500 1.6 391 1876000

0.15 0.85 4343 23000 10500 15 3.5 see footnote see footnote

0.38 0.54 4489 21000 9790 1.4 228 416000

0.41 0.59 4512 23050 6500 18 15 37000

0.63 0.37 4680 8200 8000 10 22.5 82000

Acid-gas Injection Operations A lberta Geological Surve y Footnote: For Site No. 4343 see Site No. 4336 for the total approved injection rate and volume (same operation) 

### 3 7

## 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 6.99 Inhibited crude oil 1540 2286

320 263792 139.7 29.8 60.3 J-55 6.99 Inhibited H2O 1900 1942

449 205662 177.8 54 73 J-55 9.67 Inhibited crude oil 2720 2947

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 9.67 2200 2295

997 154078 140 23.1 73 1388

164367 140 23.1 73 J-55 9.67 1390 1425

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 6.99 Diesel 1360 1420

1510 128598 178 34.2 73 L-80 9.67 1487 1490

1522 128595 177.8 29.76 73 L-80 9.67 Fresh H2O, inhibited 1300 1525

280511 178 38.7 73 L-80 9.67 Fresh H2O, inhibited 1322

1563 179488 177.8 39 60.3 J-55 6.99 Diesel 1484 1495

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 9.67 Inhibited crude oil 1218 1225

1895 266164 177.8 34.23 60.3 L-80 6.99 Inhibited Diesel 1086 1172

1971 278209 114 17 60.3 L-80 6.99 Water 1166 1199

2081 260661 177.8 34.3 73 L-80 9.67 Inhibited H2O 1938 1993

2101 280608 139.7 25.3 60.3 L-80 6.99 Fresh H2O, inhibited 1393 1475

2271 235982 139.7 25 73 J-55 9.67 Fresh H2O, inhibited 1582 1601

2469 88409 408

88471 386

88516 359

88589 371

88612 371

88621 244 53.57 178 K-55 29.30 1027 1046

88629 371

88636 398

88645 354

88659 371

88670 244 53.57 178 K-55 29.76 1019 1039

88674 371

Acid-gas Injection Operations A lberta Geological Surve y 

### 3 8Site

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 29.76 968 1018

88731 244 53.57 178 K-55 29.76 999 1055

88748 366

89961 244 53.57 168 29.80 988 931

89967 244 53.57 178 K-55 29.30 1012 1074

89973 371

89997 371

90041 371

90053 371

90070 399

90074 392

90105 178 29.76 140 J-55 20.83 988 1034

90130 371

90168 371

90196 371

90208 371

90229 244 53.57 178 K-55 29.76 1010 1034

90273 244 53.57 178 K-55 29.30 1014 1028

90281 344

90297 371

90301 371

90306 244 53.57 178 K-55 29.76 1017 1090

90342 90342

90352 317

90356 244 178 K-55 29.76 1006 1010

90361 244 178 K-55 29.76 1020 1068

91440 399

91461 244 53.57 178 K-55 29.76 1024 1037

91496 395

91544

91554 244 53.57 178 K-55 29.76 1085 1087

91566 244 53.95 140 J-55 20.90 1023 1042

91636 409

91637 178 29.76 140 J-55 20.80 1053 1076

152071 244 54 178 K-55 29.80 1001 1020

162252 244 53.7 178 K-55 29.30 1009

2573 204185 177.8 56 73 J-55 14.14 Water 1324 1344

2636 290514 139.7 25.3 73 L-80 9.67 Fresh H2O, inhibited 2768 2957

2719 263896 139.7 29.8 60.3 L-80 6.99 Fresh H2O, inhibited 2030 2145

2830 204006 177.8 30 73 L-80 9.67 Inhibited crude oil 1424 1500

Acid-gas Injection Operations A lberta Geological Surve y 

### 3 9Site

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 9.67 KCl water, inhibited 1879 1996

3340 83493 177.8 34 73 J-55 9.67 1175 1365

3465 55392 912

55409 922

55412 915

55457 912

55466 139.7 917

55480 139.7 901 945

55493 177.8 905 951

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 9.67 1445 1510

14519 178 34.2 60 J-55 6.99 1483 1546

3720 4444 178 34.23 60 L-80 6.99 2401 2495

3804 263546 140 23.1 60.3 J-55 6.99 1761 2010

3968 161153 177.8 43.2 73 L-80 9.67 3379 3335

4058 5000458 177.8 34.3 89 L-80 13.70 1414 1509

5013792 178 34.2 89 L-80 13.80 1416 1487

4174 5001572 177.8 43.2 114 L-80 18.90 2711

4248 5004038 2221

4292 5013892 178 38.7 73 L-80 1658 2105

4336 5010427 140 23.7 73 L-80 9.67 1577 1647

4343 5010429 178 34.3 73 L-80 9.67 1568 1674

4489 5000496 140 20.8 73 L-80 9.67 1290 1324

4512 5008653 178 43.2 89 L-80 13.80 2430 3307

4680 5016659 140 25.3 73 2000 series f 2.49 928.6 935

Acid-gas Injection Operations A lberta Geological Surve y 

### 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 A lberta Geological Surve y 

### 41Site

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 A lberta Geological Surve y 

### 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 A lberta Geological Surve y 

### 43Plant

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 A lberta Geological Surve y 

### 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

45Reservoir Type and Lithology for Acid Gas Injection OperationsAcid-gas Injection OperationsHost RockAlberta Geological Survey0 4 8 12 16 20 24 28ReservoirAquiferNumber of Acid Gas SitesCarbonateSiliciclastic46Acid-gas Injection OperationsHost RockAlberta Geological SurveyNet Pay of Injection Reservoir or Aquifer0102030405060708090100 3 12 3 20 4 49 5 81 6 25 7 18 8 44 9 97 1 03 4 1 18 9 1 24 2 1 39 6 1 48 9 1 56 3 1 51 0 1 52 2 1 63 0 1 73 4 1 89 5 1 97 1 2 08 1 2 10 1 2 27 1 2 46 9 2 57 3 2 63 6 2 71 9 2 83 0 2 98 2 3 08 4 3 19 5 3 34 0 3 46 5 3 58 1 3 65 1 3 72 0 3 80 4 3 96 8 4 05 8 4 17 4 4 29 2 4 24 8 4 33 6 4 34 3 4 48 9 4 51 2 4 68 0

Net Pay (m)CarbonateSiliciclastic47Porosity of Host Rock for Acid Gas Injection OperationsAcid-gas Injection OperationsHost RockAlberta Geological Survey00.050.10.150.20.250.30.35 31 2 32 0 44 9 58 1 62 5 71 8 84 4 99 7 10 34 11 89 12 42 13 96 14 89 15 10 15 22 15 63 16 30 17 34 18 95 19 71 20 81 21 01 22 71 24 69 25 73 26 36 27 19 28 30 29 82 30 84 31 95 33 40 34 65 35 81 36 51 37 20 38 04 39 68 40 58 41 74 42 48 42 92 43 36 43 43 44 89 45 12 46 80

Porosity (fraction)Core Plug PorosityPorosity Range48Porosity of Acid Gas Injection ZonesAcid-gas Injection OperationsHost RockAlberta Geological Survey05001000150020002500300035000 0.05 0.1 0.15 0.2 0.25 0.3 0.35Porosity (fraction)

Depth (m KB)CarbonateSiliciclastic49

# 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

50Original Formation Pressure in Acid Gas Injection ZonesAcid-gas Injection OperationsHost FluidsAlberta Geological Survey05001000150020002500300035000 5000 10000 15000 20000 25000 30000 35000 40000Pressure (kPa)

Depth (m KB)Hydrostatic pressure assuming fresh water51Formation Temperature in Acid Gas Injection ZonesAcid-gas Injection OperationsHost FluidsAlberta Geological Survey05001000150020002500300035000 20 40 60 80 100 120 140 160 180 200Temperature (oC)

Depth (m KB)Geothermal gradients25 °C/km30 °C/km35 °C/km40 °C/km45 °C/km50 °C/km52Formation Water Salinity in Acid-Gas Injection ZonesAcid-gas Injection OperationsHost FluidsAlberta Geological Survey05001000150020002500300035000 50000 100000 150000 200000 250000 300000 350000Formation Water Salinity (TDS mg/l)

Depth (m KB)53Reservoir Oil Gravity for Acid Gas Injection in Depleted Oil ReservoirsAcid-gas Injection OperationsHost FluidsAlberta Geological SurveyOil API Gravity050010001500200025003000350030 40 50 60 70

Depth (m KB)54Specific Gravity of Natural Gas in Depleted Gas Reservoirs Used for Acid Gas InjectionAcid-gas Injection OperationsHost FluidsAlberta Geological SurveyGas Specific Gravity05001000150020002500300035000.4 0.5 0.6 0.7 0.8 0.9 1 1.1

Depth (m KB)55

# 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

56Depth of the Injection Zone Interval for Acid Gas Injection OperationsAcid-gas Injection OperationsInjection OperationsAlberta Geological Survey0500100015002000250030003500 31 2 32 0 44 9 58 1 62 5 71 8 84 4 99 7 10 34 11 89 12 42 13 96 14 89 15 63 15 10 15 22 16 30 17 34 18 95 19 71 20 81 21 01 22 71 24 69 25 73 26 36 27 19 28 30 29 82 30 84 31 95 33 40 34 65 35 81 36 51 37 20 38 04 39 68 40 58 41 74 42 92 42 48 43 36 43 43 44 89 45 12 46 80

Depth (m KB)Approximate depth of CO2phase change to supercritical fluid57Pressures Associated with Acid Gas Injection OperationsAcid-gas Injection OperationsInjection OperationsAlberta Geological Survey050001000015000200002500030000350004000045000 31 2 32 0 44 9 58 1 62 5 71 8 84 4 99 7 10 34 11 89 12 42 13 96 14 89 15 10 15 22 15 63 16 30 17 34 18 95 19 71 20 81 21 01 22 71 24 69 25 73 26 36 27 19 28 30 29 82 30 84 31 95 33 40 34 65 35 81 36 51 37 20 38 04 39 68 40 58 41 74 42 48 42 92 43 36 43 43 44 89 45 12 46 80

Pressure (kPa)Maximum Approved Bottom Hole Injection Pressure (BHIP)Injection Formation Pressure at StartupMaximum Approved Wellhead Injection Pressure (WHIP)58Approved Maximum Bottom Hole Injection Pressure for Acid Gas Injection OperationsAcid-gas Injection OperationsInjection OperationsAlberta Geological Survey05001000150020002500300035000 5000 10000 15000 20000 25000 30000 35000 40000 45000Bottom Hole Injection Pressure (kPa)

Depth (m KB)59Maximum Approved Daily Acid Gas Injection Rate for Injection OperationsAcid-gas Injection OperationsInjection OperationsAlberta Geological Survey01002003004005006007008009001000 31 2 32 0 44 9 58 1 62 5 71 8 84 4 99 7 10 34 11 89 12 42 13 96 14 89 15 10 15 22 15 63 16 30 17 34 18 95 19 71 20 81 21 01 22 71 24 69 25 73 26 36 27 19 28 30 29 82 30 84 31 95 33 40 34 65 35 81 36 51 37 20 38 04 39 68 40 58 41 74 42 48 42 92 43 36 43 43 44 89 45 12 46 80

Daily Injection Rate (1000 m
3 /d)CarbonateSiliciclastic60Licensed Composition of the Injected Acid GasAcid-gas Injection OperationsInjection OperationsAlberta Geological Survey00.10.20.30.40.50.60.70.80.91 3 12 3 20 4 49 5 81 6 25 7 18 8 44 9 97

1 03 4 1 18 9 1 24 2 1 39 6 1 48 9 1 56 3 1 51 0 1 52 2 1 63 0 1 73 4 1 89 5 1 97 1 2 08 1 2 10 1 2 27 1 2 46 9 2 57 3 2 63 6 2 71 9 2 83 0 2 98 2 3 08 4 3 19 5 3 34 0 3 46 5 3 58 1 3 65 1 3 72 0 3 80 4 3 96 8 4 05 8 4 17 4 4 29 2 4 24 8 4 33 6 4 34 3 4 48 9 4 51 2 4 68 0

Mole Fraction of Injected GasH2S (mol fraction)CO2 (mol fraction)61Acid-gas Injection OperationsInjection OperationsAlberta Geological Survey05000100001500020000250003000010 20 30 40 50 60 70 80 90 100 110Temperature (oC)

Pressure (kPa)CarbonateCritical Point H2SVapourization curve of H2SSiliciclasticCritical Point for CO2Vapourization curve of CO2Liquid CO2Gaseous CO2Gaseous H2SLiquid H2SSupercritical CO2 

### Supercritical H 2 

### SIn situ P-T and Phase Conditions forAcid Gas Injection Zones, with CO2and H2S Phase Diagrams62Well Statistics around Acid Gas Injection Sites in AlbertaAcid-gas Injection OperationsInjection OperationsAlberta Geological Survey01020304050607080 31 2/ 3 20 44 9 58 1 62 5 71 8 84 4 99 7 10 34 11 89 12 42 13 96 14 89

15 63 / 15 10/1522 16 30 17 34 18 95 19 71 20 81 21 01 22 71 24 69 25 73 26 36 27 19 28 30 29 82 30 84 31 95 33 40 34 65 35 81 36 51 37 20 38 04 39 68 40 58 41 74 42 48 / 42 92 43 36 / 43 43 44 89 45 12 46 80

Number of Wells around the Injection SiteTotal surrounding wellsAbandonned wells149 wells total63Pipeline Length from the Gas Plant to the Acid Gas Injection WellAcid-gas Injection OperationsInjection OperationsAlberta Geological Survey0100020003000400050006000 3 12 3 20 4 49 5 81 6 25 7 18 8 44 9 97

1 03 4 1 18 9 1 24 2 1 39 6 1 48 9 1 51 0 1 52 2 1 52 2 1 56 3 1 56 3 1 63 0 1 73 4 1 89 5 1 97 1 2 08 1 2 10 1 2 27 1 2 46 9 2 57 3 2 63 6 2 71 9 2 83 0 2 98 2 3 08 4 3 19 5 3 34 0 3 46 5 3 58 1 3 65 1 3 72 0 3 80 4 3 96 8 4 05 8 4 17 4 4 24 8 4 29 2 4 33 6 4 34 3 4 48 9 4 51 2 4 68 0

Pipeline Length (m)64