PROJECT MANAGER. Preben Randhol. Inge Manfred Carlsen. CO 2 injeksjonsbrønner CO 2 nedbrytningsmekanismer

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1 SINTEF Petroleumforkning AS SINTEF Petroleum Reearch NO-7465 Trondheim TITLE REPORT Ivaretakele av brønnintegritet ifm CO 2 injekjon (avrop nr: ) Enuring well integrity in connection with CO 2 injection Telephone: (+47) Fax: (+47) (aut.) Enterprie No.: NO AUTHOR(S) Preben Randhol, Karen Valencia, Ali Taghipour, Idar Akervoll, Inge Manfred Carlen CLASSIFICATION Unretricted REPORT NO /02/07 CLIENT(S) Petroleumtilynet (Petroleum Safety Authority Norway) v/ Monica Oveen REG. NO DATE 27 December 2007 PROJECT MANAGER Preben Randhol SIGN. NO. OF PAGES 59 NO. OF APPENDICES LINE MANAGER Inge Manfred Carlen SUMMARY Thi report review the current practice related to well integrity in the petroleum indutry. The relevance of uch practice to CO 2 torage i dicued in detail. Experience from indutrial analog ha hown that the bigget rik from CO 2 torage will be from leakage from poor quality or aging injection well, leakage from abandoned well and from inadequate monitoring that could have been ued for early intervention (Benon, 2005). In view of thi, the report cover degradation procee due to CO 2, tandard on the maintenance of the integrity of well in the petroleum indutry, well abandonment regulation, monitoring approache currently ued by the petroleum indutry for early detection of leakage, remediation option that could be ued to manage leaking well and a brief dicuion of the afety apect of CO 2 well. KEYWORDS ENGLISH CO 2 injection well CO 2 degradation mechanim Well integrity Well monitoring Well remediation KEYWORDS NORWEGIAN CO 2 injekjonbrønner CO 2 nedbrytningmekanimer Brønnintegritet Brønn-monitorering Brønnutbedring H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\1\

2 - 2 - Table of Content 1. Introduction Scope of work Degradation procee due to CO Potential wellbore leakage pathway CO 2 equilibrium Cement Portland cement Cement additive Acid reitant cement Cement Teting Steel Elatomer CO 2 injection well Well activitie Drilling Operation Completion Production Method to acertain well integrity prior to hand-over Hole Stability and formation propertie Caing integrity tet Cement Evaluation Maintenance of well integrity of injection well Permanent abandonment of CO 2 well Propoed abandonment procedure for CO 2 well (Carlen and Abdollahi, 2007) Comparion of propoed abandonment procedure for CO 2 well with NORSOK guideline for oil and ga well Material election Well barrier Completion tring Temporary well abandonment Monitoring of permanently abandoned well Well Monitoring Preure and temperature Reitivity Geochemical method and tracer Well log Geophyical monitoring Fibre optic Remediation of leakage Expandable tubular Squeeze cementing, polymer gel etc Safety apect of CO 2 well Further work CO 2 blowout Component/Material teting for CO 2 environment...52 H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\2\

3 CO 2 for EOR Field communication CO 2 reproduction from torage Converting well for CO 2 and abandoned well Safety apect for CO 2 well teting/intervention Reference...54 H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\3\

4 Introduction Thi report review the current practice related to well integrity in the petroleum indutry. The relevance of uch practice to CO 2 torage i dicued in detail. Experience from indutrial analog ha hown that the bigget rik from CO 2 torage will be from leakage from poor quality or aging injection well, leakage from abandoned well and from inadequate monitoring that could have been ued for early intervention (Benon, 2005). In view of thi, the report cover degradation procee due to CO 2, tandard on the maintenance of the integrity of well in the petroleum indutry, well abandonment regulation, monitoring approache currently ued by the petroleum indutry for early detection of leakage, remediation option that could be ued to manage leaking well and a brief dicuion of the afety apect of CO 2 well. 2. Scope of work 1. Overview of CO 2 degradation mechanim for the different well barrier component, uch a cement, teel and elatomer. a. During injection b. From a permanent plugging apect 2. Literature tudy to ae what the indutry i doing in connection with CO 2 well integrity offhore on NCS and in Europe. 3. Conideration to be aeed in connection with CO 2 well integrity for the whole life cycle of the well. How to plug the well for the future, monitoring of the well etc A dicuion around the afety apect of CO 2 well. H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\4\

5 Degradation procee due to CO Potential wellbore leakage pathway Poible leakage pathway through an abandoned well are hown in Figure 3.1 (Celia et al., 2004). It can be een from the figure that leakage could occur due to poorly cemented caing, caing failure and improper abandonment. Cement that ha properly et ha very low permeability, in the order of 10-2 m 2. No ignificant flow of CO 2 can occur unle the cement ha degraded or ha not et properly. Caing failure on the other hand could occur due to corroion, eroion or improper deign. Figure 3.1 Schematic of poible leakage pathway through an abandoned well (a) between caing and cement (b) between cement plug and caing (c) through the cement pore pace (d) through the caing (e) through fracture in cement (d) between cement and rock (Celia et al., 2004) Poible leakage pathway for CO 2 injection well are the ame a in Figure 3.1 except that there i no cement plug in place. In addition, a the preure inide the wellbore i higher than the preure outide, the preferential flow path will be in the oppoite direction. 3.2 CO 2 equilibrium When ordinary cement i expoed to CO 2 ga it will react with it epecially in a wet environment. CO 2 ga will be in equilibrium with the water phae through the equilibria: CO 2 (g) = CO 2 (aq) CO 2 (aq) + H 2 O = H 2 CO 3 (aq) H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\5\

6 - 6 - H 2 CO 3 = HCO H + HCO 3 - = CO H + An increae in ga preure or CO 2 content in the ga phae will lead to an increae in CO 2 in the aqueou phae and conequently a drop in ph. CO 2 i therefore in reality a carbonic acid. High concentration of CO 2 will lead to a very low ph of the water phae. It i therefore very corroive to material uch a cement and teel. 3.3 Cement Cement containing Ca(OH) 2 will react with the CO 2 in the air or water phae a hown in the two equation below repectively: Ca(OH) 2 + CO 2 (g) = CaCO 3 () + H 2 O Ca(OH) 2 + H 2 CO 3 (aq) = CaCO 3 () + 2 H 2 O Thi proce i called carbonation and lead to a lower poroity due to the precipitation of calcium carbonate take up a larger volume than the Ca(OH) 2. The econd reaction that can occur in air and water repectively are: 3CO 2 (g) + Ca 3 Si 2 O7*4H 2 O = 3 CaCO 3 + 2SiO 2 *2H 2 O 3H 2 CO 3 (aq) + Ca 3 Si 2 O7*4H 2 O = 3 CaCO 3 + 2SiO 2 *2H 2 O + 3H 2 O Thi reaction lead to an increae in poroity due to that the volume of Ca 3 Si 2 O 7 *4H 2 O i larger than CaCO 3 (). It i common to generalize the calcium ilicate hydrate to the form: C-S-H a the amount of calcium to ilicate to hydrate varie. However, the reaction above are true for the different type of C-S-H. The ilicate hydrate product from the reaction above i alo uually an amorphou phae and not crytalline which give poorer trength of the cement. However when there i exce CO 2 with a low ph the CaCO 3 will diolve. The net reult i the poroity increae and the trength deteriorate and it lead to a further carbonation of the cement Portland cement Portland cement i the mot widely ued cement in the indutry. The problem i however that Portland cement i not reitant to CO 2. It i not thermodynamically table in contact with CO 2 and will deteriorate over time, Krilov et al. (2000). For CO 2 torage over a long time (1000 year perpective) well with Portland cement will oppoe a leakage rik. It wa found by Onan et al. (1984) that at upercritical CO 2 condition the rate of carbonation wa influenced by the partial preure of the CO 2 and the temperature. The H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\6\

7 - 7 - water content level wa found to be econdary with repect to the rate. Carbonation wa only oberved in the outer region of the ample at low temperature and preure while complete carbonation wa oberved at high temperature and preure. At low temperature and preure it wa alo oberved that dynamic ytem lead to more carbonation than tatic ytem. Miletone et al. (1986) teted cement lurrie with different amount of ilicate. They found that at 150 C and 8 bar CO 2 preure the ample without ilicate had only a mall carbonation front around the outer urface. For the ample containing lot of ilicate the carbonation front wa much deeper. Thi may be due to the increae in poroity that occur when ilicate react with CO 2 thu the CO 2 can penetrate the ample further. However, 20% ilicate i needed to get below the permeability of 0.1mD which i the API recommendation. Miletone et al. (1990) did imilar but more realitic experiment. The ample with ilicate had a higher trength than the ample without prior to the experiment. After expoing the ample for 10 month to CO 2 the ample with ilicate had lot 60% of the volume while the ample without had lot 35% of the volume. Figure 3.2 Experimental etup for teting cement at upercritical CO 2 condition Barlet-Gouédard et al. (2006) H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\7\

8 - 8 - Portland cement wa teted by Barlet-Gouédard et al. (2006) in an autoclave. Sample were teted in both CO 2 aturated water and in upercritical CO 2 atmophere at 90 C. A drawing of the apparatu i hown in Figure 3.2. The rate of carbonation in both media can be een from Figure 3.3. The carbonation and poroity alteration of the Portland cement can be een in Figure 3.4 and Figure 3.5 repectively. Figure 3.3 Rate of carbonation for Portland cement, Barlet-Gouédard et al. (2006) H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\8\

9 - 9 - Figure 3.4 The carbonation for Portland cement, Barlet-Gouédard et al. (2006) Figure 3.5 The poroity alteration in Portland cement. Excerpt of Figure 3.4, Barlet-Gouédard et al. (2006) H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\9\

10 Carey et. al. (2007) did a tudy of the cement from the SACROC unit in Wet Texa, USA. The 240 m thick reervoir i located at 2100 m depth and ha a temperature of 54C and a preure of 180 bar. The reervoir i limetone with md permeability and around 10% poroity. The cementing at total depth wa neat Portland cement. The well 49-6 wa drilled in 1950 and wa firt expoed to CO 2 in In the following year it wa a producer for 10 year in low preure environment. The next 7 year it wa an injector (high preure) and tonne of CO 2 paed through the well according to Carey et. al. (2007) Sample of the caing and cement wa taken from about 6-4m above the caprock-reervoir contact, ee Figure 3.6. Shale ample wa alo collected. The cement wa analyed and it wa found that it had been partly carbonated. The cement that wa in contact with the hale rock i heavily carbonated. The cement cloe to the caing i pure carbonate like a vein filling. No obviou proof of direct CO 2 interaction with the hale wa found. The permeability of the cement wa found to be higher than pritine Portland cement. SEM imaging howed that CaCO 3 had precipitated in the void paced. Generally it wa concluded that the tructural integrity of the Portland cement wa adequate to prevent ignificant tranport of fluid. However, CO 2 wa found to have migrated along the cement caing and cement hale interface for ome time. Figure 3.6 Photograph of ample recovered from well 49-6 howing the caing (left), gray cement with a dark rind adjacent to the caing, 5-cm core of gray cement, gray cement with an orange alteration zone in contact with a zone of fragmented hale, and the hale country rock, Carey et. al (2007) The low temperature in the SACROC field i probably the mot important factor for the level of carbonation oberved. Tet done by Kutchko el al. (2007) at 50 C and Barlet- Gouédard et al. (2006) at 90 C howed that carbonation i much fater at higher temperature. Onan et al. (1984) alo found higher carbonation at higher temperature. One factor can be the low kinetic of CaCO 3 at low temperature. What the SACROC core how i that flow path exited epecially at the cement interface. H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\10\

11 Cement additive According to Beddoe et. al. (2005) adding quartz to Portland cement in order to make it more acid reitant will leave only the cement pate affected by CO 2. The cement can therefore be enhanced in order to reduce the carbonation rate. Cement deterioration will till occur but the degree of tortuoity induced by the aggregate particle will decreae the rate. Addition of Microilica to the Portland Grade G cement gave lower permeability and better mechanical trength according to Noik et al (1998) The CO 2 reitance wa not teted though. It i reaonable to aume that additive to Portland cement uch a ilicate, microilicate, latex, polymer, can change the propertie of the cement and reduce the amount of Portland cement, but it will not hinder the carbonation from occurring due to that the Portland cement i thermodynamically untable in contact with CO Acid reitant cement Schlumberger ha developed a new CO 2 reitant cement which they have teted, Barlet-Gouédard et al. (2006). The cement i not decribed other than that it ha reduced amount of Portland cement. The tet revealed that carbonation occurred, but that the level wa lower and more homogeneouly. Comparing to pure Portland cement it wa concluded that thi cement wa more CO 2 reitant. Brookhaven National Laboratory upported by DOE, Halliburton, UnoCal Corporation, and CalEnergy Operating Corporation ha developed a phophate baed cement. The cement i claimed to have outtanding reitance to CO 2 and acid at brine temperature up to 320 C, Sugama T (2006). The CaP cement i commercialied by Halliburton under the name ThermaLock. Tet ha been performed in H 2 SO 4 olution of low ph~1.1 with HCO 3 - a CO 2 ource. According to Brother (2005) teting howed that Thermalock had a 3 % weight lo compared to 50 % weight lo of Portland cement. The Thermalock cement ha been ued in geothermal well and CO 2 injection well. Another phophate baed cement ha been developed by Argonne National Laboratory, Wagh AS (2005a, 2005b). It i baed on Magneium Potaium Phophate. Magenium i le prone to carbonation compared to calcium and hould have better reitance to CO 2. The cement i developed for the Arctic condition with very low temperature. No tet for the reitance to CO 2 have been found o how well the cement behave in a CO 2 environment i not known Cement Teting There i no tandard method of teting cement for CO 2 well. But the cement hould be teted both in upercritical CO 2 atmophere and aturated water olution. Before and after teting the propertie uch a permeability and poroity hould be meaured. SEM and XRD analyi hould alo be ued to determine the alteration of the mineral. Scratch tet and triaxial tet can alo be ued to determine the trength of core. ICP meaurement of the water phae can determine the amount of diolved ion from the ample. H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\11\

12 Both SINTEF Petroleum Reearch and Schlumberger have developed methodology and apparatu for teting cement at upercritical CO 2 condition. The equipment are quite imilar. The equipment ued by Schlumberger can be een in Figure 3.2. One difference to the Schlumberger apparatu i that the SINTEF apparatu can be agitated during the experiment by connecting a motor which rock the whole contained back and forth. By doing thi one can prevent that the olution around the core i tagnant and that new olution come into contact with the core. The ample in the SINTEF apparatu are upended inide the autoclave due to the agitation. The experiment can be run at temperature up to 200 C and high preure (1000 bar) to tet the reitance to CO 2 on cement ample. Variou configuration can be teted ome example are hown in Figure 3.7. Figure 3.7. Poible compoite tet plug. Left: plug for triaxial teting; right: hollow cylinder plug with teel tube inide or outide cement bond teting (lat plug with cement on top). The cement i hown in grey. 3.4 Steel Acidic environment can induce corroion in different type of teel. Acid ued for acidation, H 2 S, CO 2 and oxygen and chloride can all lead to corroion of the well. The main reaction in carbon teel i: Fe + 2H + Fe 2+ + H 2 The iron diolve into iron ion in the olution and leave a corroded urface. The important factor i the ph of the olution in contact with the teel. The ph can be calculated accurately uing thermodynamic model and the corroion rate for carbon teel can be calculated uing the NORSOK M-506. Uually carbon teel i not ufficient for normal well condition. According to NORSOK M-001 the limit for tainle teel AISI 316 i max temperature of 60 C and minimum ph of 3.5. If teel with higher chromium concentration content i ued one can obtain better corroion protection. 13% Cr can have a max temperature of 90 C at ph 3.5 while 22% and 25% Cr can have a max temperature of 150 C given critical H 2 S level. H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\12\

13 Zhang H et al (2005) teted the temperature effect of 13% Cr tainle teel. At 90 C when the pecimen are expoed to CO 2 environment, the corroion proce primarily compoe diolution and growth of paive film according to the following cheme: Cr + 3H 2 O Cr(OH) 3 + 3H + + 3e - A the temperature i increaed, corroion i high, thereby the paive film i detroyed. Poible corroion proce i given by the following reaction Fe 2+ + CO 3 2- FeCO 3 () Fe + HCO 3 - FeCO 3 + H + + 2e - It wa found that there i little corroion product on the pecimen urface at 90 C, more product depoit at 120 C, a layer of corroion product film appear at 150 C. Moreira et al (2004) tudied CO 2 corroion of 13% Cr v 13Cr-5Ni-2Mo tainle teel. At 90 C and 120 C, there were ome viible defect exiting in the paive film, but at 150 C, integrity and compact corroion product layer covered the paive film, le defect in the corroion product layer. Both tatic and dynamic condition where tudied. During dynamic condition the flow velocity wa 1 m/. For both condition the temperature were 125 C, 150 C and 175 C with a CO 2 partial preure of MPa. The tatic tet howed that the 13% Cr teel corroded fater than the 13Cr-5Ni-2Mo. The ratio between the 13% Cr teel and the 13Cr 5Ni 2Mo teel corroion rate were found to be: 8 time at 125 C, 12 time at 150 C and 44 time at 175 C Cr - Static (mm/y) 13Cr5Ni2Mo - Static (mm/y) 13Cr - Dynamic (mm/y) 13Cr5Ni2Mo - Dynamic (mm/y) 1.2 Corroion rate (mm/y) Temperature (C) Figure 3.8 Corroion rate of 13Cr and 13Cr5Ni2Mo teel for dynamic and tatic condition at temperature 125 to 175, Moreira et al (2004) H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\13\

14 Table 3.1 Number of year it take to corrode through a tubing with OD=9 5/8 and ID=8 ½ baed on data from Moreira et al (2004) Temperature Static Dynamic C 13Cr 13Cr5Ni2Mo 13Cr 13Cr5Ni2Mo According to Havlik et al (2007), 13% Cr how good performance in CO 2 environment. However, it i not applicable in higher temperature and in combination with low amount of H 2 S. 13Cr i alo enitive to oxygen corroion. 22% or 25% Cr duplex teel i very cotly and uually not an option for long pipe ection. However, even if 22% or 25% Cr i better uited at high temperature and H 2 S content it can uffer evere corroion during acid treatment. It i therefore very important that if uing thi type of material the operational contraint i not to acid wah the well. It need to be well documented o that it i undertood by the different dicipline during the life cycle of the well. Nickel alloy can alo be conidered if duplex teel cannot be ued. Another option could be to ue a lower grade teel with an internal coating. However, the coating i not reliable and any breach will lead to rapid corroion and deterioration of the teel. So the choice of material will largely depend on the condition expected for the CO 2 well. It i important not to mix low grade eal with high grade tubing/caing metal for example. Thi will lead to galvanic corroion due to the difference in electric potential between the metal. All component: tubing, caing, wellhead, hanger, liner etc hould be choen to be of ame teel quality. It i therefore alo very important that one quality check the material from the upplier before intalling them in the well a a wrong teel quality of metal eal for example may rapidly lead to a well integrity failure. A metal are prone to corrode it i not uited to be left in contact with CO 2 when the well i abandoned. 3.5 Elatomer Searching for literature on behaviour of elatomer in CO 2 environment did not give any reult unfortunately. H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\14\

15 CO 2 injection well A CO 2 injection well i very imilar to a typical ga injection well except that downhole component have higher preure rating and corroion reitance. Experience with regard to CO 2 handling ha already been gained from EOR operation and for acid ga dipoal (IPCC, 2005). A typical built-for-purpoe CO 2 injection well and a wellhead are hown in Figure 4.1 (RITE, 2007). Downhole configuration of a typical injection well include a packer, an on-off tool and a downhole hutoff valve. Thee well are uually equipped with annular preure monitor to help detect leak in packer and tubing. Thi i important for taking rapid corrective action. Figure 4.1 Typical built-for-purpoe CO 2 injection well (after RITE, 2007). In mot cae, production or injection well in depleted oil/ga field are alo reued a CO 2 injection well. When well are re-ued for CO 2 injection, it i important to review the activitie conducted during the well operating life a they affect the well integrity. In thi ection, the different activitie that may be carried out in the well lifetime prior to converion a CO 2 injector and their poible effect on well integrity are firt reviewed. Second, the different method ued to check the well integrity for further ue a a CO 2 injector are dicued. Finally, exiting guideline to maintain well integrity of injection well are covered. 4.1 Well activitie The impact on well integrity of the different activitie that may be carried out during the well operating life prior to converion a a CO 2 injector i dicued in thi ection. The different well activitie include drilling operation, completion and production H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\15\

16 operation. For built-for-purpoe CO 2 injector, dicuion on the drilling and completion operation are applicable Drilling Operation Drilling activity tart with pudding and conclude with preparation of the well for teting, completion or upenion/abandonment. The drilling activity could impact wellbore tability, caing integrity and the cement integrity Drilling and borehole tability During drilling, the primary preure barrier i the fluid column. The drilling mud alo form a filter cake to prevent wall collape. Keeping the borehole wall intact enure that the cement column would be properly et during completion. Borehole cave-in reult in an under-reamed hole which could affect the cementing operation Caing etting There i higher rik of compromiing the caing integrity during drilling operation. Prior to landing, all component of caing tring including connection, circulation device and landing tring hall be ubject to load cae verification. For through-tubing drilling operation, the tubing and acceorie hall be reclaified to caing and redeigned to meet drilling load (NORSOK, 2004). The following point hould be conidered in caing deign (NORSOK, 2004): Planned well trajectory and bending tree induced by dogleg and curvature Maximum allowable etting depth with regard to kick margin Etimated pore preure development Etimated formation trength Etimated temperature gradient Drilling fluid and cement program Load induced by well ervice and operation Etimated caing wear Setting depth retriction due to formation evaluation requirement Potential for H 2 S and/or CO 2 Metallurgical conideration ECD and urge/wab effect due to narrow clearance Iolation of weak formation, potential lo zone, loughing and caving formation and protection of reervoir Geo-tectonic force applicable Incident cenario during drilling which could erve a bai for etimating expected load hould include occurrence of ga kick and dynamic load from running of caing, including overpull to free tuck caing, inflow or fluid lo while running or pulling tring, preence of olid/and, preence of H 2 S, hydrate, wax and emulion. When hydrate, wax or emulion are preent, contingency meaure could be to upply heat to the affected area or inject uitable chemical inhibitor. It hould be noted that H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\16\

17 heating the affected area reult in thermal load while injection of uitable chemical inhibitor reult in higher internal preure Cementing the caing/liner The quality of the cementing operation i alo crucial in maintaining wellbore integrity. The mot widely ued cement in the petroleum indutry are the Portland-type cement. When it i properly et, the cement lurry can become a nearly impermeable and durable material. Cement bond to rock by a proce of crytal growth while cement bond to caing by filling the pit pace in the urface of the caing. Good quality cementing will likely protect againt cement degradation and caing corroion. In a CO 2 -rich environment, Portland cement i known to be thermodynamically untable. It tend to trongly degrade once expoed to uch acid gae, by reacting with calcium hydroxide formed from hydrated calcium ilicate phae. An EOR ite where cement and caing were expoed to carbon dioxide for 17 year (Sacroc reervoir) howed that cement can retain integrity for ome decade (Carey, 2005). It hould be noted that the temperature in the Sacroc reervoir wa only ~50 C. In another imulation of downhole condition for both wet upercritical CO 2 and CO 2 - aturated water, an alteration of 100mm after 20 year of CO 2 attack i poible in Portland cement. Non-Portland baed cement (calcium phophate cement - Thermalock TM ) which contain aluminum hydrate, calcium phophate hydrate and mica-like aluminoilicate are now ued a alternative in carbon dioxide injection well, our-ga dipoal well and geothermal well with high carbon dioxide content. An alternative i to ue fortified Portland cement where reitance i increaed by adding a latex diluent of a pecific particle ize and adding a non-tandard, high alumina cement to reduce the amount of Portland cement. Thi ha been ued in the well completion deign for acid ga (65% hydrogen ulfide, 35% carbon dioxide) injection over a 50-year period in Labarge area, Wyoming (Benge, 2005). Relevant cement additive that help to maintain well integrity include hydrazine which i ued to control corroion of the caing and radioactive tracer to ae where the cement ha been placed. (Barlet-Gouedard et al, 2006). Beide the cementing material, the placement of cement i alo important in maintaining the wellbore integrity. It i very important to do a thorough clean out of the well prior to cementing in order to prevent mud mixed into the cement cauing cavitie or channel. Thi will not only degrade the trength of the cement, but can alo create leakage pathway for CO 2. Well deviation can affect cement a cement et differently in deviated well and vertical well. Drilling mud i firt circulated in the hole to enure that cutting and borehole wall caving have been removed before running the caing. The mill varnih i alo removed from the urface of the caing to enure that the cement will bond to the teel urface. Centralizer are then ued to enure that the caing i placed in the center of the borehole. For under-reamed or wahed out hole, bow pring centralizer are ued. After the cement lurry i pumped downhole, a lighter drilling mud follow. In H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\17\

18 thi way, the caing i under compreion from a higher differential preure on the outide of the caing. Thu, when the cement et and drilling or production operation continue, the caing will alway have an elatic load on the cement-caing interface. Thi elatic load i conidered eential for maintenance of the cement-caing bond and to prevent leakage between the cement and caing. Sixty to eventy percent of the well in the Gulf of Mexico are affected by utained caing preure (SCP). The main caue i believed to be ga flow through the cement matrix. Thi could be due to ga flow through unet cement and due to cement hrinkage after completion. Remediation which included injection of high denity brine in the annulu and pumping of high denity fluid into the caing have little ucce (Crow, 2006). Thi problem ha alo been oberved after routine well preure tet. In ummary, the cementing problem that could caue SCP include: (1) micro annuli caued by caing contraction and/or expanion (2) channel caued by improper mud removal prior to and during cementing (3) lot circulation of cement into fractured formation during cementing (4) flow after cementing by failure to maintain an overbalance preure (5) mud cake leak (6) tenile crack in cement caued by temperature and preure cycle (Sweatman, 2006) Completion A tudy of a CO 2 injection well at the K-12B ga field in the Dutch ector of the North Sea howed that 25% of the tubular are degraded. The pitting increaed ignificantly in the year of the CO 2 injection and could therefore be the reult of corroion or eroion (Mulder, 2006). Aide from thi, experience from converion of a mature oilfield in Wet Texa into a carbon dioxide injection field howed that recovered metal liner have extenive corroion (prior to carbon dioxide injection) poibly due to chlorine baed attack from the formation water (Power, 2006). Thi emphaie the importance of material election when deigning well completion. Tubing movement which include piton, ballooning, helical buckling and thermal effect hould alo be etimated conidering the different well operation throughout the operating life of the well. Collape and burt preure hould alo be etimated. When deigning for burt, collape and axial load, the following load cae hall be conidered (NORSOK, 2004): Leak teting of the completion tring Leak teting annulu Shut in of well Dynamic flowing condition Shut in of well by cloing SCSSV Tubing collape a a function of minimum tubing preure (plugged perforation or low tet eparator preure) at the ame time a a high operating annulu (maximum allowable) preure i preent Injection Overpull Firing of TCP gun H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\18\

19 Artificial lift requirement For HPHT well, emphai hould be placed on (NORSOK, 2004): Dimenional tability of well a a function of temperature and preure Sealing capacity of metal to metal eal a a function of wellbore fluid, preure and temperature Stability of exploive and chemical perforating charge a function of temperature/preure expoure time Clearance and tolerance a function of temperature and differential preure expoure Deterioration of elatomer eal and component a function of temperature/preure expoure time and wellbore fluid Common failure occurrence in the North Slope of Alaka are eroion, well ubidence, leaking elatomer and external corroion. Concluion from the BP experience in the North Sea and North Slope of Alaka include (Ander, 2006): Elatomer problem and caing corroion problem occur after well completion Tubing need to be replaced at 5-20 year interval and after 3 replacement the well hould be plugged and abandoned Production Reervoir preure depletion due to production can induce formation compaction. Formation compaction can caue caing damage. Caing deformation occur due to axial buckling in the reervoir or ub horizontal hear in the overburden. Figure 4.2 how the ditribution of caing failure for the Belridge diatomite field. The peak zone of failure are at the boundary between the diatomite reervoir and the overlying and or within the and itelf. At the Belridge diatomite field in California, nearly 1000 well had evere caing damage by depletion-induced compaction (Fredrich et al., 2000). In the North Sea chalk bain, more than 90 caing failure had been oberved, which were related to the increae of axial and radial load on the wellbore caued by compaction of the high-poroity chalk during reervoir depletion (de Silva et al., 1990). H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\19\

20 Figure 4.2 The location and incidence of caing failure at the Belridge field from 1984 to 1994 (Nagel, 2001). Several effort to combat caing deformation include water injection (Dale et al., 1996). Telecoping joint have alo been employed in the reervoir ection in order to reduce the build up of axial train (Eriken et al., 1998). In the overburden, the wellbore i underreamed in order to allow additional hear movement before the rock trata impinge on the caing (Bickley and Curry, 1992). Aide from caing damage due to reervoir ubidence, and production could alo caue caing damage a oberved in Canada heavy oil and (Wagg et al., 1999). In the ame manner, in China Daqing oilfiled, the caing damage reached 6860 after 40 year which i 16% of the total well in the field (Lan et al., 2000). In the Gudao reervoir of Shengli oilfield, forty oil production and water injection well were recently abandoned due to caing failure (Peng, et al, 2007). Due to the everity of the conequence, and production hould be continuouly monitored. Maximum allowable and production and maximum allowable equipment wear lo hould be etablihed. 4.2 Method to acertain well integrity prior to hand-over Prior to converting a well for CO 2 injection, the well hould undergo teting to enure it integrity under preure. Even if oil production well have no leakage during their operating life, it i till poible that thee well could leak during ga injection. It i therefore neceary to conduct a preure tet uing ga (e.g. CO 2 ) for a period of time before commencing actual CO 2 injection. For well which formerly ued artificial lift, it i important to enure that the valve are intact prior to ue of the well a a CO 2 injector. It i alo important to eal the valve prior to ue of the tubing tring for CO 2 injection. Suburface afety valve hould be H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\20\

21 checked and cleaned from depoit. They mut alo be checked for compatibility with ga injection. In the following ubection, the different routine methodologie ued to acertain wellbore integrity are dicued in detail. Thi cover method which deal with hole tability, caing and cement integrity Hole Stability and formation propertie Information regarding formation propertie could give an indication of the poible leakage pathway from the formation to the wellbore. Thi require identification of formation interval where there i leakage rik uch a weak formation. While untable/weak formation i in itelf a poible leakage pathway, it can alo affect borehole tability hence caing integrity. Wellbore wall failure reult in enlarged and elliptical borehole. Thi irregularity could be a problem during caing tring cementing and could potentially reult in failed cement job. Wellbore intability could be due to complex geological condition uch a interval with different propertie (e.g. weak, brittle, fractured, chemically reactive). The manifetation of wellbore intability include hole pack off, exceive reaming, overpull, torque and drag or tuck pipe. Figure 4.3 i an example of an open-hole caliper log howing wellbore wall upport poible and mud invaion. A mud weight increaed from 70 PCF to 76 PCF, wellbore wall tabilization i oberved. However, a it i increaed to more than 76 PCF, hole ize i increaed in certain location. Thi i poibly due to mud invaion (Mohiuddin, et al. 2006). Figure 4.3 Open hole caliper log howing mud invaion and wellbore wall upport (Mohiuddin, et al. 2006). Production-induced ubidence/compaction of the formation i alo a function of the formation propertie. Thi phenomenon could reult in caing damage (e.g. Bolivar Coatal Field, Venezuela; South Pa Block 24 & 27, Gulf of Mexico; South Belridge H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\21\

22 Field, California). In Ekofik Field, it wa oberved that caing deformation align with high poroity interval contributing mot to production. Compaction of chalk wa upected to induce buckling (Schwall et. al. 1996) Preure and formation permeability Review of the formation preure data, permeability and in-itu tree could alo help identify interval which are potential leakage pathway. Etimate of pore preure and permeability could be obtained from well tet. Horizontal in-itu tre magnitude and formation breakdown preure could be etimated from leak-off or fracturing tet (e.g. mini frac) which may be calibrated by laboratory teting of core ample. A typical bottomhole preure profile during fracturing i a hown in Figure 4.4. Figure 4.4 Idealized curve bottomhole preure v time during injection with contant flow rate (Schechter 1992). The Figure how the following important point (Schechter 1992): Breakdown preure: the preure required to break down the formation from the wellbore, and initiate the fracture. Propagation preure: the preure required to continually enlarge the fracture. Intantaneou hut-in preure: the preure that i required to jut hold the fracture open after the injection i topped. Vertical tre magnitude on the other hand could be etimated from denity log or eimic data while elatic modulu of the formation could be obtained from laboratory H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\22\

23 rock mechanical teting. Knowledge of the rock mechanical propertie (e.g. tree, formation breakdown preure, etc.) i ignificant epecially if it i planned to reue abandoned well a carbon dioxide injection point. For intance, fracturing the formation could be avoided by injecting below the formation breakdown preure. If during injection, fracturing the pay zone i inevitable, the fracture treatment could be deigned in uch a way that the reulting fracture will not breach the bounding trata. Another important ue of information on reervoir propertie i to enable etimation of production-induced tre change and reervoir compaction/ubidence. Thi entail coupling of geomechanical with production model. Beide the rock mechanical propertie and reervoir propertie, production hitory data i neceary to calibrate the reervoir imulation model. Rik of damage to the caing tring due to thi phenomenon could then be evaluated. Preferential orientation of borehole trajectory for borehole tability i primarily baed on the orientation of the principal in-itu tree. If the well trajectory i not preferentially oriented, wellbore intability could be a problem. Knowledge of the direction of the in-itu tree i therefore required for planning a well. Direction of horizontal force are invetigated by conducting a borehole breakout analyi. Borehole breakout (Figure 4.5) will orient themelve in the direction of the minimum horizontal tre, and hence can be ued to determine thi direction. There are everal tool ued to conduct breakout analyi. Some of the common tool ued for thi analyi include borehole televiewer log (BHTV), dip-meter log, and caliper log. H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\23\

24 Figure 4.5 Example of different type of borehole cro-ection elongation a oberved from a ix-arm dipmeter log (after Jaroinki, 2005) Mud log Mudlog interpreted lithology decription hould alo be checked in relation to caing tability. For intance, unconolidated formation are particularly vulnerable to intability and poibly looe and grain could erode the uncemented portion of the caing. In addition, certain lithologie are particularly uitable a caing eat. Clean hale for example i the ideal caing eat formation. In the field, however, the formation elected for the eat i uually the bet compromie between the ideal and what i poible. Interval which poe leakage rik could alo be identified from mud loe/gain oberved during drilling. Drilling dynamic information from mud log data indicate mud inflow/outflow. Daily drilling report (DDR) hould alo be reviewed and interval where mud loe/gain are experienced hould be noted a poible conduit for fluid. DDR give detail of event and action taken for the duration of the drilling operation. H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\24\

25 Caing integrity tet Corroion and cement bond log are amongt the mot common technique ued to evaluate caing mechanical damage. Wireline tool available for caing obervation range from the imple mechanical device (e.g. caliper) to ultraonic meaurement technique deigned pecifically for teel caing and the cement environment. However, conventional device normally meaure caing parameter, uch a internal radiu, in a 2D horizontal plane within the wellbore. The ultraonic borehole televiewer on the other hand i able to image the caing accurately in three dimenion. Figure 4.6 how a 3D caing image and the longitudinal ection in a production well. It can be een from the figure that the caing i deformed by hearing. In (b), the center line i the original caing axi. The line to the left and right of the center axi how the deformed caing outline (Peng et. al., 2007). Variou type of caing damage captured by the borehole televiewer are hown in Figure 4.7, Figure 4.8, Figure 4.9, Figure 4.10 (Peng et al., 2007). Figure 4.6 Caing damage oberved from an ultraonic borehole televiewer (a) 3D view (b) longitudinal ection of the caing (Peng et al., 2007). H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\25\

26 Figure 4.7 Caing enlargement captured by ultraonic borehole televiewer. Left: 3D view; Right: longitudinal outline (Peng et al., 2007). Figure 4.8 Caing failure induced at perforation. Left: 3D view; Middle: longitudinal view; Right: cro ection (Peng et al., 2007) H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\26\

27 Figure 4.9 Broken caing. Left: 3D view; Middle: longitudinal view; Right: cro ection (Peng et al., 2007) Figure 4.10 Cracked caing. Left: 3D view; Middle: longitudinal view; Right: cro ection (Peng et al., 2007) Field obervation in the Gudao reervoir in China how that caing damage i mainly caued by caing buckling and fracturing. The location of the caing damage i concentrated on the unconolidated andtone around the perforated area. Cavitie were produced around the caing in the unconolidated andtone due to and production. The caing loe lateral contraint in the location of the cavitie, inducing non-uniform preure around the caing and cauing buckling and hear failure (Peng et al., 2007) Caing evaluation Caing inpection prior to landing hould include viual inpection regarding corroion, mechanical coupling, micro annulu formation and other caing failure. It i alo imperative to make ure that the caing material i reitant to CO 2 -brine environment. H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\27\

28 It hould alo be noted that the weaket point in the caing tring i the coupling where three type of failure could occur at the joint: jumpout, fracture, or thread hear. When jumpout failure occur the pin and box eparate with little or no damage to the thread element. In a compreion failure, the pin move further into the box while in fracturing the pin-threaded ection eparate from the pipe body or axial plitting of the coupling occur. Thread hear on the other hand refer to the tripping off of thread from the pin and/or box. The caing joint mut alo provide an effective eal to prevent leakage of the fluid or gae. Thi require large interface preure between the mating thread in a joint. Thi i done by ue of thread interference, metal-to-metal eal, reilient ring or combination eal Caing deign Caing deign report which include load calculation (e.g. thermal, buckling, piton etc.) hould be reviewed and compared with the well hitory. Difference in the deign and the actual well event hould be noted a the elected caing may have been underdeigned and could fail earlier than expected. Preure tet report hould alo be reviewed and checked for irregularitie. The caing i expoed to different loading condition during variou well operation (landing, cementing, drilling, production). It ha to be deigned to withtand tenile, burt and collape load. However, it i impoible to predict the magnitude of thee load during the life of the caing. Therefore the deign i baed on the wort cae cenario. The caing rating alo deteriorate with time (wear and tear). Thu afety factor are ued to make ure that the caing could withtand expected loading condition. Collape preure i mainly due to the fluid preure outide the caing. Thi could be drilling fluid or cement lurry. Overpreure zone could alo ubject the caing to high collape preure. The caing critical collape trength i a function of it length, diameter, wall thickne and phyical propertie (e.g. yield point, elatic limit, Poion ratio, etc.). Burt loading on the other hand i due to the fluid preure inide the caing. Severe burt preure occur if there i a kick during drilling operation. The tenile tre on the other hand originate from pipe weight, bending load and hock load. The axial force due to pipe weight i it weight in air le the buoyancy force (Archimede principle). Bending force reult when the caing i run in deviated well where the upper portion of the caing i in tenion wherea the lower part i in compreion. Shock load on the other hand i generated by etting of the lip and application of hoiting brake. The udden toppage when caing i run generate tre wave along the caing tring. In addition to the three loading condition decribed above, caing deign hould alo conider the likelihood of buckling, piton and thermal effect. Buckling reult when the caing i untable (e.g. partially cemented). The caing tring will exhibit a helical configuration below the neutral point. Thi reult in rapid wear at thi point which can eventually lead to caing failure. Piton force on the other hand i due to the H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\28\

29 hydrotatic preure acting on the internal and external houlder of the caing tring while thermal effect refer to the expanion or hortening of the caing due to increae or decreae in temperature Caing leak Reported well leak during the operating life of the well and the correponding remedial action taken hould be examined. Detail of workover operation (e.g. queeze cementing) hould be invetigated to determine whether well integrity ha been adequately retored. Radioactive (RA) tracer can be ued to locate leakage in caing or packer. The RA tracer could be ued both in injection and production well. It only ue a mall amount of radioactive material relative to the amount of the other fluid therefore there i no meaurable urface radiation. There i no health rik in a tracer urvey but alternatively puled neutron tool could be ued if there i concern for releae or torage of radioactive material (Johnon et. al, 2002). Ultraonic leak detector could alo be ued to detect caing leak. The frequency pectrum that a leak produce i a function of differential preure, leak magnitude, and leak geometry. Thee propertie determine whether the frequency i audible in the ultraonic pectrum. The ultraonic logging tool make ue of a enor that detect the frequency pectrum produced by leak. The tool can be run inide the tubing and could detect leak from (Tecwel, 2007): 1) production packer 2) expanion joint, or any other ubaembly 3) tubing 4) Downhole Safety Valve (DHSV) 5) control line to the DHSV 6) any of the caing in the well 7) wellhead H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\29\

30 Figure 4.11 Poible leakage ource that ultraonic tool can detect (Tecwel, 2007). Other conventional leak detection log (LDL) include temperature, preure and caing collar locator (CCL) onde. In 1995, ditributed temperature ening (DTS) wa introduced giving real-time thermal profile of the wellbore. An example i hown in Figure 4.12 (Julian et al, 2007). H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\30\

31 Figure 4.12 Comparion of conventional wireline temperature, memory temperature and DTS log howing leak (Julian et al, 2007) Corroion and Eroion The implet method to meaure downhole corroion and eroion i through the ue of multi-finger caliper. Electromagnetic thickne meaurement tool (ee Figure 4.13) could alo be ued to meaure downhole corroion/eroion. Typically, a low frequency electromagnetic wave i tranmitted from a tranmitter element inide the tool body. The electromagnetic wave travel radially through the well-fluid before going through the tubing wall and traveling along the length of the tubular. It then re-enter the pipe where it i intercepted by the enor. The wall thickne can be etimated from the tranmitter-enor tranit time and the amplitude of the electromagnetic wave (Readgroup, 2007). H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\31\

32 Figure 4.13 Typical electromagnetic thickne meaurement tool (Readgroup, 2007). Downhole video camera (See Figure 4.14) are alo ueful in imaging downhole corroion. Centralizer are ued to poition the camera within the wellbore to provide an even pread of light from the LED light ource. Typical image captured by downhole video camera are hown in Figure 4.6, Figure 4.7, Figure 4.8, Figure 4.9 and Figure Figure 4.14 Downhole camera (Readgroup, 2007) Cement Evaluation In thi ection, we review pot cementing evaluation tool Temperature meaurement Temperature urvey could alo be ued to locate cement top. Temperature urvey hould be run a few hour after mixing, when the heat of the etting cement i ditinct. H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\32\

33 Cement Bond Log (CBL) Bond log may alo be ued to determine cement top a well a the quality of the cement-to-caing bond. In ome cement job, preure i held on the caing until the cement et. When the preure i releaed, the caing contract and break the cement bond. Thi reult in creation of microannulu gap between caing and cement. Thi annular pace between cement and caing caue the CBL to repond a if the cement had channeled. If thi i the cae, the CBL can be run with a preurized caing. The microannulu cloe when the caing expand and the CBL will indicate good bonding if the cement job i otherwie ucceful. In ome cae, poor centralization of the logging tool could alo make the cement appear to have good bonding (Figure 4.15). Figure 4.15 Example of cement bond log with ultraonic imaging tool and variable denity log (after Boyd et al, 2006) Preure teting It i cutomary to preure tet the hoe after drilling out the cement hoe on the urface and intermediate caing tring. Thi involve preuring up inide the caing until the preure at the hoe exceed the maximum hydrotatic preure expected at that point during ubequent drilling operation. Failure of cement around the hoe i uually due to contamination, either from the original drilling mud or from the diplacement fluid. It i the reult of poor cement technique rather than poor quality material a hard-et neat cement ha ufficient trength to withtand preure tet. H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\33\

34 Maintenance of well integrity of injection well A number of tandard technologie are available for monitoring the integrity of active injection well. Some of which have already been decribed in Section 4.2. Proper maintenance of CO 2 injection well i neceary to avoid leakage and well failure. Practical procedure that can be ued to reduce probabilitie of CO 2 blow-out (uncontrolled flow) and mitigate the advere effect if one hould occur include periodic well integrity urvey, improved blow-out prevention (BOP) maintenance, improved crew awarene, contingency planning and emergency repone training. During injection, the operating preure hould be kept to a minimum to reduce the rik of leakage. Thi maximum allowable injection preure i alo contrained by reervoir propertie and urface facilitie. The preure in the annulu can alo be monitored during injection to enure the integrity of the packer, caing and the injection pipe. Change in preure or ga compoition in the annulu hould alert the operator to poible leakage. H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\34\

35 Permanent abandonment of CO 2 well In thi Chapter, procedure to carry out permanent abandonment of well for CO 2 torage i decribed (Carlen and Abdollahi, 2007). The propoed procedure are then compared with exiting NORSOK guideline on permanent abandonment of oil and ga well. The purpoe of which i to ee the gap between the current guideline and the minimum requirement for CO 2 torage. Bridging thi gap will enure that the integrity of abandoned well i intact and allow for future ue of depleted hydrocarbon field for CO 2 injection. 5.1 Propoed abandonment procedure for CO 2 well (Carlen and Abdollahi, 2007) Generally, the well hould preferably be placed at the flank of the torage anticline for diplacement of the CO 2 away from the vicinity of the well and avoiding early expoure. Sealing plug can be mechanical, cement or a combination. A cemented caing with mechanical plug will not be ufficient. Caing corroion may create channelling and poible leakage. Shrinkage or expanion of both caing and the cement may create micro-channel in the cement bonding and leakage. The ealing element hould provide comply with the following requirement: 1) Multiple preure barrier 2) Avoiding underground cro-flow between layer 3) Zero tranmiibility 4) Chemically inert 5) Provide ufficient bonding trength Figure 5.1 chematically illutrate a typical CO 2 injection well before abandonment in the cret of the torage reervoir. Special care hould be taken when contructing thee well. The procedure i a follow: 1) Set production caing in the middle of cap rock 2) Minimize liner overlap length 3) Ue pecialized cement and caing material H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\35\

36 Before abandonment Wellhead and X-ma tree Surface caing Intermediate caing Impermeable cap rock Production caing Perforation Liner Figure 5.1 CO 2 torage well before abandonment It i aumed that the ealing qualitie of the caprock are generally maintained with zero permeability to ga or injectivity to well fluid or cement. The production caing and the liner penetrating the cap rock hould be milled out with a caing cutter a potential corroion of the teel may create leakage channel. Figure 5.2 chematically illutrate the well after abandonment. The operational procedure are a follow: 1) Remove tubing and packer 2) Set cement plug at the bottom of the well (ub-barrier) 3) Mill out caing from liner lap to end of perforation 4) Inject cement in perforation and cement the open hole interval 5) Squeeze cement in the lower and upper cap rock formation 6) Set mechanical bridge plug 7) Remove upper free-cement caing 8) Mill out intermediate caing and queeze cement 9) Remove wellhead and mill out urface caing and queeze cement H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\36\

37 After abandonment Surface barrier Extra barrier Potential econdary impermeable geology layer Non corroive completion fluid Bridge plug Main barrier Impermeable cap rock Perforation Fluhed zone Sub-barrier Figure 5.2 CO 2 torage well after abandonment The cement plug will act a the main future CO 2 barrier. The major concern i related to the ealing quality of the cement plug and the bonding quality to the penetrated caprock. Micro channel created near the wellbore by the drilling or milling operation i believed to be cloed by queezed cement. A poible fluid could alo poible be fluhed into the torage reervoir to diplace the CO 2 and help to improve the cementing quality and bonding to the ealing cap rock. A mechanical bridge plug i et inide the well and the well hould be filled with a non-corroive completion fluid. An extra cement barrier hould be made higher up in the well. The caing hould be milled out alo here to eal off potential caing corroion, bridge plug leakage and poible CO 2 migration through the cement to the lower part of the well. If a econdary geological ealing layer i preent thi barrier hould be poitioned here a indicated. At the urface, the wellhead hould be removed, the caing tring cut and a lat cement plug put in place. Figure 5.3 illutrate a flow chart of the well barrier now in place inide and outide the well. It i poible that other type of material uch a polymer or rein that are inert to CO 2 mut be pumped into the near bore well area to prevent direct expoure of cement to CO 2. One example of uch a material i ThermaSet developed by WellCem AS that i H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\37\

38 claimed to be inert to CO 2. Any uch material hould however be teted in upercritical CO 2 before approved/deployed. Surface barrier Surface barrier Extra barrier Extra barrier Bridge plug Main barrier Main barrier Sub-barrier Outide the well Inide the well CO2 migration Figure 5.3 Well barrier after abandonment Caing protective material and alternative caing material, a for example compoite, hould poibly alo be evaluated for poible and alternative abandonment procedure. 5.2 Comparion of propoed abandonment procedure for CO 2 well with NORSOK guideline for oil and ga well Fundamentally, the NORSOK tandard for permanent abandonment of well could erve a a bai for etting guideline for CO 2 torage well. However, more tringent requirement hould be et in ome area for CO 2 application Material election NORSOK tandard require that permanent barrier for abandoned well are impermeable, have long term integrity, non-hrinking, ductile, reitant to different ubtance and have ufficient bonding to the caing. The material requirement decribed by the NORSOK tandard i general and do not provide any pecific detail (e.g. type of teel, cement, etc.). For CO 2 application where material election i very important, pecific material requirement hould be et in the guideline. Steel and cement quality hould be of higher grade o they can handle CO Well barrier In the NORSOK guideline, no cement plug i placed in the cap rock (Figure 5.4). Thi i inufficient for well expoed to CO 2. The caing will corrode at a much fater rate than that of well without CO 2. Thi will reult in micro channel allowing CO 2 H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\38\

39 migration from the reervoir ection upward. In which cae, it i good practice to millout the caing within the cap rock and place a cement plug in the milled out ection. A cement i more reitant to CO 2 than caing, thi will provide a much better eal than the cemented caing alone. Open hole to urface barrier: 1. Caing cement 2. Cement plug Secondary well barrier: 3. Caing cement 4. Cement plug Primary well barrier: 5. Caing cement 6. Cement plug Figure 5.4 Example cae (after NORSOK Standard D010, 2004) Completion tring According to the NORSOK tandard, the tubing can be left in place (Figure 5.5) when the well i to be permanently abandoned. For CO 2 application, however, thi i inadequate. When the tubing corrode, leakage pathway will be formed. Thi can be prevented by pulling out the tubing prior to etting the cement plug. An alternative i to mill out the tubing at the point where the cement plug i to be et. H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\39\

40 Open hole to urface barrier: 1. Caing cement 2. Cement plug Secondary well barrier: 5. Caing cement 6. Cement plug Primary well barrier: 3. Liner cement 4. Cement plug Figure 5.5 Cae on the right hand ide of the axi where tubing could be left inide the well (NORSOK Standard D010, 2004) Temporary well abandonment By NORSOK tandard, temporary well abandonment i not regulated to a certain time frame. Thi hould be done if the well i expoed to CO 2 a there i higher rik of corroion. The duration of temporary well abandonment hould be evaluated baed on the well fluid compoition, the type of completion a well a completion material ued Monitoring of permanently abandoned well NORSOK do not precribe guideline for monitoring permanently abandoned well. For CO 2 application, it i important that alo permanently abandoned well are monitored for potential leak. Different monitoring technique are decribed in Chapter 6. H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\40\

41 Well Monitoring 6.1 Preure and temperature The implet way to detect leak i by preure monitoring. Conventionally, preure enor at the wellhead and downhole provide real-time preure readout in the tubing and in the different annuli. Leakage through any of the barrier can be eaily detected from the wellhead preure reading. Leak could be between the different volume (e.g. between the tubing and annulu A) a hown in Figure 6.1. In ome cae leak can alo occur within one volume a acro the afety valve (e.g. acro the annular afety valve of annulu A). See Figure 6.2. Tubing Annulu A Annulu B Figure 6.1 Leak between different volume. Tubing Annulu A Annulu B Figure 6.2 Leak within one volume. H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\41\

42 The preence of a CO 2 cap in the aquifer will influence the formation preure. A cap of 10 m i etimated to increae the preure with 0.3 bar. Figure 6.3 indicate that a permanently intalled preure enor with 10 bar full meaurement range typically will drift off ± 0.01bar over a life pan of 20 year. Such enor will oon be available off-the-helf and ready for intallation, - demontration are een via imilar enor available for other application. The main challenge i to protect the relatively oft membrane needed for 10 bar meaurement range during intallation. The drift of enor are normally a portion of full range (<1% for the enor referenced above), o 10 bar full range eem to be a maximum with today enor. Preure monitoring (combined with temperature), or differential preure monitoring between top and bottom of cap, can be utilized for CO 2 monitoring purpoe. A preure change may be difficult to interpret. An oberved preure reduction may be due to enor drift, leak into cap-rock or CO 2 olubility in brine. The meaurement hould thu be combined with other obervation. 0.2 Preure enor characteritic No leak Drift <1% over 20 year. 10bar Full Scale Future enor: Improved drift characteritic, extended life pan? Preure (bar) 0.1 Leakout in 100 year Time (year) Figure 6.3 Permanent preure enor and the uncertainty due to drift in output ignal. The drift characteritic are derived from a one month tet on permanent well enor from Weatherford (preliminary data). 6.2 Reitivity The formation water in the formation ha alinity comparable to ea water. CO 2 in the formation ha iolating electrical propertie. Reitivity or conductivity meaurement H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\42\

43 are thu well uited for etimation of CO 2 aturation in the formation (when the poroity i known). Saturation model commonly applied in wire-line logging for etimation of hydrocarbon aturation (i.e.archie equation) can be directly applied. Permanently intalled enor have the capability of monitoring time developing trend with high reolution. Two baic enor principle are available, electrode in galvanic coupling to the formation or induction enor. A conducting caing will dramatically influence formation electrical meaurement from a borehole. The patial reolution and detection range depend on enor geometry and frequency. When calibrated againt wireline log the aturation etimate will have an accuracy within 5%. An array of 8 enor node, carefully ditributed in the well would probably give ufficient lateral reolution. Expected lifetime of a permanent enor ytem i typically 5 year. 6.3 Geochemical method and tracer Geochemical tracer uch a perfluorocarbon tracer (PFT) can be ued to etimate CO 2 leakage rate. Thi technology ha been applied in a pilot equetration tudy ite in the Wet Pearl Queen depleted oil formation in SE New Mexico. PFT were added a three 12 h lug at about one week interval during CO 2 injection. Leakage wa monitored uing 40 capillary adorbent tube left in the oil for period ranging from day to month. The tracer were analyed uing thermal deorption and ga chromatography with electron capture detection. In thi tudy, the CO 2 leak rate wa etimated at about % of the total CO 2 equetered per annum. Moreover, CO 2 appear to have emanated from the vicinity of the injection well in a radial pattern to about 100 m and in directional pattern to 300 m (Well et al., 2007). Chemical tracer uch a SF 6, CH 3 F and CH 2 F 2 can be analyed by laer photothermal pectrocopy or by ga chromatography with electron capture or ma pectrometric detector. Radiological tracer on the other hand, uch a 14 CO 2, 42 Ar and 39 Ar could be detected by a cintillating grid radiometric ga enor (Saripalli et al., 2006). Small amount of noble ga iotope can alo be diolved into the CO 2 being injected for torage and ued a tracer to monitor CO 2 movement. Noble gae are chemically inert, environmentally afe and are table in the environment. The unique iotopic compoition that can be imparted to the CO 2 can be unambiguouly identified during monitoring. Among the noble gae, xenon iotope have commercial cot and availability uitable for ue in large CO 2 torage operation. Multiple batche of injected CO 2 at the ame ite could be imparted with different xenon iotopic compoition o that they can be identified with only a ingle xenon analyi. Thee characteritic are believed to make xenon a uperior tracer to other option uch a SF 6 and 14 CO 2 (Nimz and Hudon, 2005). H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\43\

44 Fluid ample can alo be analyzed for major ion, ph, alkalinity, table iotope and gae. Standard analytical method are available to monitor all of thee parameter, including the poibility of continuou real-time monitoring for ome geochemical parameter. 6.4 Well log Different well logging technique a decribed previouly could be routinely ued to monitor CO 2 leakage in caing and cement. 6.5 Geophyical monitoring Time-lape eimic urveying ha been found to be a highly uitable geophyical technique for monitoring CO 2 injection into a aline aquifer. The effect of the CO 2 on the eimic data are large in term of eimic amplitude and in oberved velocity puhdown effect (Art et al. 2004). See Figure 6.4. Figure 6.4 An inline through the injection area in Sleipner for the 1994, 1999 and 2001 urvey (Art et al, 2004). 6.6 Fibre optic Development of fibre optic to ue for well monitoring i championed by BP, but mot oil companie are teting/developing the technology. According to Wright JP: Thi technology, already in ue to meaure temperature ditribution in landbaed well, can alo be ued to monitor continuou pipeline temperature from the well to the platform. Thi can provide early warning of waxing or hydrate formation, or monitoring of pipeline temperature change during a hut in. Optical fiber offer the next major tep change in enor technology for the ubea and downhole arena. Optical fiber enor can be ued to meaure H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\44\

45 effect a divere a: (1) Poition and movement with fiber gyrocope. (2) Acoutic with fiber hydrophone. (3) Strain in mart tructure. (4) Chemical and reaction. (5) Electrical upply characteritic. Fiber will be ued to provide high bandwidth, electrical noie (EMI) immune, environmentally table communication with multiplexed ophiticated ubea and downhole equipment. Optical fiber will alo provide communication to a range of dicrete paive optical enor head, meauring temperature, preure, flow, and vibration. The fiber itelf, can be ued a a ditributed enor, uing either the Brillouin or Raman cattering effect, inherent in all fiber, to meaure temperature and train over fiber length of up to 30 km. Thi length will extend, a more enitive detection ytem become available. Fibre optic may be ued in the future to detect internal or external leakage and be able to accurately localie the leakage in the well. It can then be ued a a permanent monitoring tool. H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\45\

46 Remediation of leakage Material that can be ued to remediate SCP include micro fine cement and low olid denity ealant (polymer, gel, rein). Gel can be ued to remediate cement bond failure, tubing and caing leak. Rein can be ued to eal caing leak and SCP a well a for hutting off ga for abandonment. Expandable tubular can alo be ued (run in a maller ID pipe and expand againt exiting well). Ue of different technique i ituation-dependent and motly for hort term application only. 7.1 Expandable tubular Caing leak or corroded ection can be iolated without running a liner hanger uing expandable tubular. A metal-to-metal eal i formed, and the wellbore ID i not reduced ignificantly a with conventional liner. Thi technology ha been uccefully teted in Wyoming and Texa to remedy leak due to corroion (Ander and Winter, 2005). Expandable ytem can be ued externally or internally. In cae where it i more economical to replace the caing above or below the damaged ection than run everal caing patche, expandable external caing patch (tie-back) connection could effectively provide a hydraulic and ga-tight connection between the new caing joint and the old caing tub. The connection principle i baed on the elatic/platic expanion and ubequent relaxation of metal. An example i hown in Figure 7.1 where a 9 5/8 caing i cut below the corroion and leak ite and the upper caing removed. The new completion aembly i run coniting of 9 5/8 by 13 3/8 packer aembly, a hort ection of 9 5/8 caing and the patch (Readgroup, 2007). H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\46\

47 Figure 7.1 External expandable caing patch (Readgroup, 2007). Expandable tubular could alo be ued internally. The expandable metal leeve maybe attached to a CT/wireline/tubing-conveyed expanion tool. The patch i platically expanded uing hydraulic preure. The patch will conform to the inide urface of the caing/liner/tubing wall reulting in a metal-to-metal eal. Thi can be uccefully ued to repair leaking caing or reinforce corroded liner. Thi technology ha been uccefully ued to iolate a caing leak in a 7 3/4 oil well caing which failed the preure tet in the Gulf of Mexico (Chutz et al., 2005). H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\47\

48 Figure 7.2 Internal caing patch (Readgroup, 2007). 7.2 Squeeze cementing, polymer gel etc. Squeeze cementing can alo be ued to repair caing leak (e.g. joint leak, plit caing, parted caing, corroded caing). In general, queeze cementing operation force the cement lurry into caing perforation/leak under low preure. Heitation method of applying preure (intermittent application of preure eparated by a period of preure leak-off) i applicable to low preure cementing. In ome circumtance, polymer gel can alo be ued a an alternative to cement. The type of polymer depend on the location and everity of the leak and whether or not the polymer will be required to hold a preure or imply hut-off water production. Acrylic monomer grout are uitable for tight caing leak and preure leak-off ituation. High concentration low molecular weight polymer are uitable for a variety of leak uch a tight preure leak-off ituation to moderate leak. For channeling behind pipe and for lot circulation application, high molecular weight polymer are effective. Cement/polymer combination queeze on the other hand i uitable for evere caing leak. In here, the polymer act a a filler/buffer of larger void, coat formation urface and prevent water lo and cement contamination by formation fluid (Polymergel, 2007). H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\48\

49 Safety apect of CO 2 well CO 2 well are different from normal ga well due to the nature of CO 2. CO 2 lead to a very corroive environment which eaily can lead to lo of integrity. Not only internal well integrity can be lot, but alo external which i much harder to top. In the US a lot of CO 2 well have been running for decade. A new problem i CO 2 blowout in thee old well a they looe integrity. An excellent overview of the pecific problem related to CO 2 blowout wa written by Skinner, L (2003): Repone meaure to afely handle CO 2 blowout require an awarene that thee blowout are not the ame a ga well or oil well blowout. With proper training and planning, and a firm knowledge about the peculiaritie of upercritical CO 2, the indutry can repond to thee event and, hopefully, prevent the recent increae in CO 2 blowout frequency from becoming an epidemic. When preure containment i lot, two procee occur imultaneouly. 1. The CO 2 (and a fraction of micible product) convert from a upercritical fluid to a vapour with ignificant expanion. Thi vapour continue to expand with decreaing confining preure a it move up the wellbore. Flow velocitie increae accordingly. Any mud or other fluid in the well i expelled quickly leaving little hydrotatic preure to reit influx from the reervoir. The reult i that more upercritical CO 2 flow into the wellbore expanding a it doe. Thi flow behavior i almot exploive in it violence. One experienced well control pecialit compared the flow from a CO 2 blowout to a BLEVE (boiling liquid/expanding vapour exploion). The violence of the urface flow i uually not expected by field worker. Often, only a mall volume of upercritical liquid CO 2 in the wellbore i enough to trigger the proce cauing the well to blowout in a matter of econd. Reaction time i minimal and ome equipment, particularly manual BOP and tab-in afety valve, cannot be intalled and cloed fat enough to avoid complete expulion of all liquid from the well and total lo of preure control. 2. Rapid cooling of the wellbore and fluid tream occur due to expanion. Once the CO 2 tream fall below the triple point temperature and preure of -63 F and 76 pi, repectively, olid dry ice particle can form quickly. Several pecial problem reult from the unique CO 2 phae behavior: 1. High flow rate complicate urface intervention work and expoe worker to ga moving at high velocitie, which can injure expoed kin due to high rate blow-by (i.e., eddy current and friction). H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\49\

50 CO 2 and produced fluid form hydrate that can collect in blowout preventer, the wellhead and other urface equipment and around the wellhead complicating well control intervention method. 3. The cold CO 2 condene water in the atmophere reulting in reduced viibility in the white cloud around the wellbore. The plume i alo a cold hazard for worker near the well. 4. Free oil and condened micible fluid wept out of the near-wellbore area can collect on the urface creating a ground-fire hazard. 5. Dry ice formation often reult in pea- to marble-ize projectile that are expelled from the well at very high velocitie, ufficient to injure worker on location. Once it collect on the ground, and before it ublime to gaeou CO 2, dry ice can alo be a ignificant cold hazard. In one CO 2 blowout, a worker got too near the plume and reported bruiing on the inide of hi calve due to hi coverall leg whipping in the induced flow tream near the plume. Thi high rate ga flow can rapidly cut groove in tubular good, damage rubber ealing element and trip paint off equipment. Both SINTEF and Petroleum Safety Authoritie Norway, ha done well integrity tudie on the Norwegian Continental Shelf (NCS). Injector were found to be much more prone to well integrity failure, ee Figure 8.1. Injector are 2 to 3 time more likely to leak than producer well. The two tudie were conducted on different field with only limited overlap. Two important reaon for the high number of leakage can be: (1) Large cycling load on the injector well due to injection of cold fluid. Thi can caue leakage if the well i not deigned to manage thee load. (2) Injector have low tatu compared to producer. Figure 8.1 Percent leakage in Producer and Injector on the NCS H:\tilyn på nettet\!!deember07\luttrapport_brønnintegritet_co2\web_luttrapport bronnintegritet_co2.doc\h\50\