### OVERVIE W OF ACID-GAS INJECTION O P ERATIONS IN WE S TERN CANADA

Stefan Bachu 1 * an d W illiam D. Gun t er 2

1 Alb e rta En ergy an d Utilities Bo ard

, Ed m o n t o n , AB, T6 B 2X3, Can a d a 2 Al bert a R e se ar ch C o unci l

, E d m ont on , AB , C a nada

A B STRAC T

Ove r2

. 5 M t C O 2 and 2

. 0 M t H 2 S have been i n ject e d i n t o d eep sal i n e a qui fers a nd de pl et ed hy dr ocar b o n rese rv oi r s
at

48 si t e s i n west ern C a na d aby th e end o f 20 0 3 , d r i v e n by th e need t o di spo s e of H 2 S pr od uce d wi th natu ral gas fr om sour gas reser v oi rs. In j ect i on of aci d gas (C O 2 and H 2 S) occu rs o v er a wi de ra n g e of a qui f e r a nd re ser voi r ch aracteristics, acid g a s com p o s itio n s , an d op erating co nd itio ns. Th ese aci d

- g a s in j ection o p eratio n s are a commercial sc ale analogue to CO 2 geol o g i c a l st orage an d ar e rep r ese n t a t i v e of a qui fers and r e ser v oi rs i n cont i n e n t a l sedi m e nt ary basi ns th at ha ve un der g one c o m p acti on an d erosi o n , l i k e th ose bet w een t h e R o cky M o un t a i n s and t h e Appalachia ns i n North Am erica, where CO 2 i n ject i o n a n d geol ogi cal st or age on a larg e scale is m o st lik ely to b e im pl em ent e d i n C a nada an d t h e Uni t e dSt at es.

INTRODUCTION

Si nce 19 9 0

, fa ced wi th th e c h al l e nge o f re duci n g at m o spheri c emi ssi ons of hy dr oge n sul p hi de ( H 2 S) pr o duce d fr om “sour” h y d r o car bo n po ol s, oi l and ga s pr o duce r s i n th e Al be rt a B a si n i n west er n C a nada ha ve b een tu rni ng t o di sp osal of aci d gas (H 2 S a n d CO 2 , with mi n o r traces of hydrocarbons) by in je ction into deep ge ol ogica l form ations.
To dat e , 48 ap pl i cat i ons fo r i n ject i o n of aci d g a s p r od uce dat 42 di f f ere n t gas pl ant s ha v e bee n ap p r o v e d i n west ern C a nada , o f w h i c h 4 1 we re a c t i v e at th e en d o f 20 0 3 (Fi g ure 1) . M o st ope rat i o ns i n je ct aci d gas at a si ngl e si t e (sing l e well), b u t a few inj e ct o rh a v e inj e cted at sev e ral sites, su ch th at in to tal th ere are 4 8 inj ectio n sites for 42

ope rat i o ns. O n e o p erat i o n w a s not im pl em ent e d an d t w o were resci n dedafter a perio d of ope r ation, either becaus e injection volumes reache d t h e approved limit, or because t h e gas pla n t producing the a c i d gas was dec o mmissioned. At a third operation the site was rescin de d because the injection volum e reache d the limit of the inje ction rese rvoir, and it wa s re placed with i n je ction int o a de eper saline forma tion. At a n othe r operati o n, three diffe re nt sites ha ve been s u ccessively suspe n ded by the re gul atory age n cy because of rese rvoi r ove rpressu ri ng , with i n j ection cu rren tly

occu rri ng i n t o a dee p sal i n e f o rm at i on.

Fi gure 1: L o c a t i on a n dst atu s at th e e n d of 20 0 3 of aci d- g a s i n ject i o n o p e rat i ons i n wes t ern C a nada

.

* Corresponding author: E-mail: Stefan.B achu@g ov.ab.caAt th ree ope rat i ons th e aci d gas i s di ss ol ve d i n wat e r p r i o r t o i n ject i o n, and th e res u l t i ng w eak aci di c sol u t i o n (“sour water”) is in j ected

. At sev e n o th e r sites, o f wh ic h th ree ha ve bee n resci n ded

, wet aci d gas (i .e . aci d gas wi th free wate r pre s ent) is injected. Dry acid g a s (i.e. with no free water p r esen t) is in j ected at all o th e r sites. Ex cep t fo r the cases of injection i n s o luti on, t h e acid gas is injected a s a dense flui d ( liq u i d or supercritical). The cu mu lativ e in

j ection rate for all acid g a s inj ectio n sites in western C a nada reac he d m o re th a n 1 M t /y r i n 20 0 3

, o f whi c h

app r oxi m a t e ly 48 0 kt i s C O 2 (Figure 2a). The cumu lative vol um e of acid gas injected to the en d of 2 0 0 3 reac he d

m o re th an 4

. 5 Mt, o f wh ich sl ig h tly m o re th an h a lf is C O 2 (Fig ur e 2b )

.
These acid-ga s injection operations re pre s e n t a commercial-scale anal ogue to ge ologic al storage of CO 2 . The

t echn o l o gy an d ex pe ri ence devel ope d i n th e en gi nee r i n g as pect s o f aci d- gas i n jecti on op erat i o ns (i .e. desi g n , materials, leakage pre v ention and safety) ca n be ad o p t e d f o r l ar g e

- scal e ope rat i o ns f o r C O 2 ge ol o g i c a l st orage

. T h e characte r istics of the s e ope rations provi de a wealth of inform ation t h at ca n be us ed for t h e sc reeni n g and id en tificatio n o f fu ture sites for g e o l ogical sequestration a n d storage of CO 2 . Wi th t h e ad vent o f emissi on tr a d i n g, aci d ga s i n ject i o n co ul dbec o m e even m o re appeal i n g t o oi l andga s pr od u cers [1]

.

Fi gure 2: Ti me ev o l u tion of cu mu lativ e (all o p e ration s ) a) inj ectio n rate; an d b ) inj e cted vo lu m e s, at th e acid

- g a s i n

ject i o n o p erat i ons i n west er n C a nada

, sh owing also th e fractio n of inj e cted H 2 S a n d CO 2 .

LICENSING AND OPE RATING PARAMETERS

Ap pl i cat i ons f o r aci d gas di s pos al nee d t o con f orm t o th e specific requi r em ents that deal with ap p licatio n s for

con v e n t i onal o i l and gas rese rv oi rs [e. g . 2]

. The sel ect i o n o f a n aci d

- g a s i n ject i o n si t e nee d s t o a d d r ess vari ous

co nsid eration s th at relate to : 1 ) p r ox imity o f th e in j ection s ite to th e so u r oil o rg a s facility th at is th e so u r ce o f acid

gas; 2 ) c o nfi n e m ent of t h e i n j ect ed ga s; 3 ) ef fect o f aci dgas o n th e r o ck m a tr i x ; 4 ) pr ot ec t i on of e n e r gy , m i neral an d

g r ou nd water reso urces; 5 ) eq uity in terests; an d 6) well b o re in tegrity an d p u b lic safety [3, 4 ] . Th e sp ecifi c lo catio n i s base d o n a ge n e ral assessm ent of th e re gi ona l geol o g y an d hy d r o g e o l o gy , whi c h i s desi g n ed t o eval uat e th e p o t e nt i a l for leaka g e. Knowledge of the ge ol ogical setting a n d c h aract eristics i s critical to assess th e i n tegrity o f th e ho s t fo rm ati on o rr e serv oi r , an d th e sh ort

- an d l o n g -t erm fat e of the injecte d acid gas

. Of partic ular importance ar e pot e n t i a l mi grat i on pat h way s wi th i n th e i n ject i on z o ne (t he sp rea d o f th e i n ject ed aci d gas pl um es i n aq ui fer s i s

co nsid ered in detail in a co m p an ion p ap e r [5 ] ) and fro m th e in j ection zon e to o th e r fo rm at io n s , sh allow groun dwater and/ or the s u rface. To avoid leakag e through the caproc k or through induc e d fracture s , the m a ximu m bottomhole in

j ection p r essu re is set b y regu lato ry ag en cies at 9 0 % of the fract uri n g press u re in the injection zone . M o re recently, re gul atory age n cies ar e li miting the bottom hole inj ection pre ssure i n the case of inj ection into de pleted h ydro c arbon reservo i rs to t h e in itial reservo i r pressure or even less.

Regulatory agencies license only the m a ximu m H 2 S cont ent of t h e inje cted acid ga s, whic h varies between 5%

an d 9 7 % m o le fractio n. Th e rest co m p rises m o stly CO 2 , with a few pe rcent C+ gases for the balance

. The actual

avera g e com position of the inject e d aci d g a s vari es fr om 83% H 2 S and14% C O 2 to 2 % H 2 S and 95 % C O 2 . The

max i mu m ap pr ov ed w e llh ead inj ection pr essu r e v ar i es b e tw een 3

, 75 0 an d 19 ,00 0 k P a. A ppr ov ed daily in j ectio n
rat e s vary bet w een 2, 00 0 a nd 90 0, 0 00 m 3 /d ay. Max i mu m a llo wed inj ectio n vo lu mes v ary b e tween 6x 10 6 and1

, 8 76x 10 6 m 3 . Based o n t h e esti m a ted to tal i n j ection vo lu me an d aq uife r o rrese rv oir cap ac ity, th e acid g a s inj ection sites ar e p l anned to op er ate fo r p e r i od s o f 10 to 25 year s. For s o m e specific case histori e s, see [6].

FACILITIES

Aft e r separat i o n o f a n y gas l i qui ds, t h e p r o duce d s o ur ga s i s passe d th r o u g h a c ont act or or abs o r b e r t o we r i n a

one - or t w o

- st a g e pr ocess wh ere th e s o ur ga s t y pi cal l y com e s in con t act with an amin e o ramin e d e ri vativ e so lu ti o n

. The water-saturate d acid-ga s stream leaves the rege ne rat i on uni t at 35 t o 7 0 kPa an d mu st be co ol ed, th e n

com p ressed f o r dee p i n ject i o n. Aft e r th e aci d gas i s separat e d, i t i s co mp ress ed , dehy d r at ed, pi pel i n e d an d i n ject e d th ro ugh a d i spo s al w e ll ( F igur e 3) . Th ese op er ation s d e p e n d on th e pr oper ties o f th e H 2 S and CO 2 mi x ture, the t w o g a ses h a v i ng si mi lar p h a se eq u ilibria [7, 8

, 9 ] . Th e critical p o i n t s are T=31 .1 o C and P=7, 38 0 kP a fo r C O 2 and T=10 0.2 o C and P= 8, 96 3 kP a fo r H 2 S. The phase be havi o u r of t h e aci d gas sy st em i s represe n t e d by a cont i n u o u s seri es of t w o- p h ase e n vel o pes separat i n g th e l i qui d an d gas pha ses (e. g . Fi gu re 3)

. B o t h C O 2 and H 2 S f o rm hy dr at es
at te m p erature s up t o 10 o C for CO 2 and m o re th an 3 0 o C fo r H 2 S, ev en if free water is no t p r esen t [7

, 9

, 10 ], th us it is desira ble to operate a b ove t h e hy drate

- forming te m p erature

. Maintaining tem p eratures above 35 o C (Figu r e 3)

p r ev en ts co m p r e ssor b r eakdow n and p l ugg in g, as w e ll as p l ugg ing o f th e p i p e lin e and inj ection w e ll. A c id g a s obt ai ne d a f t e r th e rem oval o f H 2 S and C O 2 fro m th e so ur gas is u s u a lly satu rated with water v ap o r in t h e ran g e of 2

to 6 %

. Th e so lub ility o f water in b o t h H 2 S and C O 2 , he nce in acid ga s, dec r eases as pre ssure i n cre a ses up t o 3-8 MPa, d e p e nd ing o n tem p erature, after wh ich it d r am atical ly in creases. Th e so l u b ility min i mu m reflects th e p r essure at wh ich t h e acid -g as mi x tu r e p a sses i n to th e d e nse liq u i d phase, wh ere t h e so lub ility o f water in creases su b s tan tially with in creasing pressu re du e to th e m o l ecul ar attr act i on b e t w een th e s e p o l ar c o m pou nd s [1 1, 12] . T h i s pr ope rt y i s

use d i n natu ral l y dewat e ri n g th e aci d ga s b y com p ressi ng th e gas fr om abo u t 1 0 0 kP a t o ar ou n d 8 t o 1 0 M P a fo r in

j ection

, thu s redu cing t h e water con t en t t o less th an 0.5 mo le% to avo i d p i p e and well co rro s i o n [11

, 12

, 13 ].

Fi gure 3: Ty pical o p e ratin g co nd itio ns for acid g a s inj ectio n showing t h e co m p ression an d d e h ydration cycle,

tran sp ortatio n fro m th e g a s p l an t to t h e inj ecti o n well, and inj ectio n, i n relati o n t o th e acid g a s ph ase an d h ydrate fo rmin g co nd itio ns (after [14 ] ).

Mo st of th e com p resso r d r i v ers are electric m o to rs in Al b erta, and n a tural-g a s fu elled eng i n e s i n British Co lu m b ia.
I n A l ber t a, add i ng g a s eng i nes to an app r ov ed p l an t r e quir e s a thor ough rev i ew o f NO
x emi ssi ons f o r t h e pl ant

. Also , th e m a in ten a n c e co st of electric m o to rs is less th an t h at o f n a t u ral g a s eng i n e s. M o st in stallatio n s requ ire on ly four stages of com p ression. Maximu m com p ressor disc h arge in jection press u res ran g e fr om 2.8 M P a to 8. 9 M P a. Gen e rally, th e co m p ressed acid g a s is i n j e cted in a p r es sure -tem perature ra nge where the liqui d phase is stable,

resu lting in an ap preciab le h e ad pressu re b e i n g g e n e rated du e to th e h e i g ht o f co lu mn o f th is liq u i d in th e wellbo r e,
thus l o we ri n g th e re qui red c o m p ressor di sch arge pres su re. To av oi d ca vi t a t i on, th e aci d gas mu st not ent e r th e t w o

pha se regi on du ri n g com p re ssi on . Whi l e sou rgas or s w eet gas th at i s i n ject ed i n cy cl i ng (nat ur al gas st orage )schemes requires dehydration, many acid gas disposal schemes do not need to dehydrate the acid gas. By the 4 th stage in a cycle (Figure 3), compression at pressures between 3 and 5 MPa will tend to dewater the acid gas if there are no hydrocarbon impurities present [10]. Further compressi ng the acid gas increases the solubility of water in the acid gas, such that residual excess water dissolves into the acid gas, and more than counteracts the decrease in solubility due to inter-stage cooling. In the majority of cases dehydration is supplied by the compression cycle and only in a few cases tri-ethylene glycol , refrigeration or a desiccant is used.

Pipelines reflect the fact that most of the current acid gas disposal projects handle small rates, in that most of the lines have a diameter of 60 mm (2 inchnominal). The line lengths in many in stances are short, reflecting the fact that operators have either drilled the di sposal well near the plant, or are using a prior existing well adjacent to the plant. The design stress levels, and es pecially the actual operating stress leve ls, are low, again reflecting the low injection pressure levels. Most lines are made out of carbon steel, although many of the short lines are made out of stainless steel. Emergency shutdown valves are installed at both ends of the disposal pipeline. The pipelines connect the plant compressors to the injection wells, and range in length from 100 m to 20 km, with diameters ranging from 48 to 168 mm and wall thickness from 3.2 to 11 mm.

The bottom hole pressure needed for injection is provide d by the pressure at the wellhead and the hydrostatic weight of the acid gas in the well, minus friction losses down hole and across perforations. The wellhead is equipped with a pressure control valve that regulates pre ssure. Regulations require that all disposal wells be equipped with downhole packers, to protect the casing strings. Casing depths range from 856 to 3,335 metres. Casing diameter ranges from 114 to 244 mm, while the tubing diameter ranges from 60 to 244 mm. Many wells are equipped with L-80 grade tubing, which is considerably stronger than would be required for the experienced injection pressure levels. To protect the tubing against th e possibility of internal corrosion, several operators have elected to use internally coated tubing . If the gas is undersaturated in water content, corrosion is minimal in any case. Subsurface safety valves have been installed in ma ny tubing strings, as a safety measure in the unlikely case of backflow of acid gas from the formation. Many tubing strings are equipped with premium threads, to avoid potential tubing leaks. Overall, many precautions have be en applied in well completions to ensure safe operations.

SUBSURFACE CHARACTERISTICS

Table 1 summarizes the characteristics of the geological me dia into which the acid gas is injected. In 29 cases injection takes place in carbonate rocks and in 19 cases in siliciclastics. In most cases shales and shaly siliciclastics constitute the overlying confining unit (top seal), but also tight limestones, evaporites and anhydrites are present. Reservoir containment of the acid gases by geological trapping is discussed in more detail in [15]. Other trapping types for acid gas are hydrodynamic traps formed by deep aquifers, discussed in [16], and mineral traps discussed by [17] and [18]. The initial formation pressure is generally subhydrostatic with respect to freshwater, except for onecase, in the Foothills in northeastern British Columbia, where the injection reservoir was initially slightly overpressured. In the case of acid gas injection into depleted oil or gas reservoirs, the original reservoir pressure was drawn down as a result of production, such that formation pressure at the start of acid gas injection was less than the original formation pressure, sometimes significantly, reachi ng as low as 1170 kPa. In 10 cases the formation pressure at start-up was below the critical pressure of CO 2 .

TABLE 1: CHARACTERISTICS OF THE AQUIFERS AND OIL OR GAS RESERVOIRS USED FOR ACID GAS INJECTION IN WESTERN CANADA.

Characteristic Minimum Value Maximum Value Average injection depth (m) 824 3432 Formation thickness (m) 4 276 Net pay (m) 2 100 Porosity (%) 4 30 Permeability (mD) 1 4,250 Formation pressure (kPa) 5,915 35,860 Formation temperature (  ̊ C) 26 110 Water salinity (mg/l) 19,740 341,430 Oil gravity (  ̊ API) 16 68 Gas specific gravity 0.573 1.121In-situ phase and thermodynamic properties of the formation brines and acid gases are discussed in more detail in [19]. For the case of acid gas being injected into depleted oil reservoirs, the oils are medium to very light (24  ̊ API to 68  ̊ API), and in one case the oil is heavy (16  ̊ API). Acid gases generally have a lower minimum miscibility pressure than conventional hydrocarbon gases, therefore, theycan be used in enhanced oi l recovery (EOR), as it was done at one site [20]. Rese rvoir gases are generally light (specific gravity less than 0.75). Because acid gas is generally heavier than these reservoir gases, it may also be considered for use in enhanced gas recovery. More details about the subsurface characteris tics of the acid-gas injection in west ern Canada can be found in [21].

CONCLUSIONS

By the end of 2003, approximately 2.5 Mt CO 2 and 2.0 Mt H 2 S have been successfully injected into deep hydrocarbon reservoirs and saline aquifers in western Canada. This experience shows that CO 2 storage in geological media is a technology that can successful ly 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 size of the operations approved to date in western Canada is relatively small, with approved inj ection rates and volumes generally less than 0.1 million m 3 /d and 1000 million m 3 , respectively. The technology and experience developed in the engineering aspects of acid-gas injection operations (i.e. design, materials, leakage prevention and safety) can be easily adopted for large-scale operations for CO 2 geological storage, since a CO 2 stream with no H 2 S is less corrosive and less hazardous. No safety incidents have been reported in the 15 years sin ce the first operation in the wo rld started injecting acid gas into a depleted reservoir on the outskirts of the city of Edmonton, Alberta. Given that H 2 S is more toxic and corrosive than CO 2 , the success of these acid-gas injection operations indicate that the engineering technology for CO 2 geological storage is in a mature stage. The major issu es that need addressing in th e near future are the longterm containment of the injected ga ses in the subsurface, and the safe ty of large-scale operations.

REFERENCES

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