Assessment of Engineered Integrity

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1 Project Title: Kingsnorth Carbon Capture & Storage Project Page 1 of 20 Table of Contents Executive Summary... 4 Nomenclature Introduction Scope Related Project Documents Leakage Pathways and Risk Risk of Leakage to Surface Well Leakage Mechanisms Diffusion Darcy Flow through the Cement Degradation of the Cement Corrosion of Tubulars Combination of Mechanisms Risk Levels for Different Well Types Well Integrity Statements Well Integrity Statement for Injection Wells Well Integrity Statement for Existing Production Wells without Access Issues Well Integrity Statement for Existing Wells with Access Issues Well Integrity Statement for Exploration Wells Conclusions Recommendations Mandatory References Supporting References Conversion Factors... 20

2 Project Title: Kingsnorth Carbon Capture & Storage Project Page 2 of 20 Table of Figures Figure 2-1: Comparative Risk of Leakage Over Time For CO 2 Storage... 7 Figure 2-2: Impact of Micro Annulus Width on Permeability Around a Casing... 9 Figure 2-3: Impact of Gas Channel Radius on Permeability in a Cement Sheath... 9 Figure 2-4: Impact of Fracture Width on Permeability in a Cement Sheath... 10

3 Project Title: Kingsnorth Carbon Capture & Storage Project Page 3 of 20 Table of Tables Table 2-1: Corrosion Rates for Casings Used in Wells Table 2-2: Order of Magnitude of Corrosion Times For 9 5/8 Casing Table 3-1: Safety and Environmental Risk Criteria and Categories Table 3-2: Risk Levels For Different Well Types... 13

4 Project Title: Kingsnorth Carbon Capture & Storage Project Page 4 of 20 Executive Summary This report is a review of work already done in other reports and risk assessments as part of the EON carbon capture project. It assesses the engineered integrity of the existing wells and the new wells which penetrate the Bunter reservoir of the Hewett field. Qualitative methods to estimate the order of magnitude of any leakage of CO 2 have been described and discussed. Because these are subject to multiple uncertainties and assumptions, the results are valid only in this very narrow qualified context and should not be used for quantification. It is recommended that work is done to investigate long term (hundreds of years) degradation rate of different types of cement in the presence of CO 2. Design risk assessments already done have been summarised, and the residual risk results used to develop integrity statements for each type of well. The residual risk of migration of CO 2 between formations, and to surface, remains medium (risk) for the 4 legs of the existing production wells which have access issues, and high (risk) for the 5 exploration wells.

5 Project Title: Kingsnorth Carbon Capture & Storage Project Page 5 of 20 Nomenclature Variable Meaning Feet Inch API American Petroleum Institute Atm Atmosphere bara Bar absolute bbl Billion barrels BHIP Bottomhole Injection Pressure BHIT Bottomhole Injection Temperature Bscf Billions of standard cubic feet CCS Carbon Capture Storage CMG Computer Modelling Group Ltd. CO 2 Carbon dioxide Cr Chrome Csg Casing deg Degrees EMW Equivalent Mud Weight ft Feet ID Inside Diameter ISO International Organization for Standardization K Permeability KO Kick Off lb Pound m Metres md millidarcies MD Measured Depth MM Millions OBM Oil Based Mud POOH Pulling out of hole ppg Pounds per gallon psi Pounds per square inch psia Pounds per square inch absolute psig Pounds per square inch gauge SSSV Subsurface Safety Valve TD Total Depth TOC Top Of Cement TOL Top Of Liner TRSSV Tubing Retrievable Subsurface Safety Valve TVDss True Vertical Depth Subsea (MSL or LAT) WBHIT Well Bottomhole Injection Temperature WHIP Wellhead Injection Pressure w/ with

6 Project Title: Kingsnorth Carbon Capture & Storage Project Page 6 of Introduction This report reviews and assesses how the integrity of the CO 2 storage site and storage complex has been engineered, as described in other related reports Scope The scope of the study was to: Develop a Well Integrity Statement for Injection Wells Develop a Well Integrity Statement for Existing Wells Incorporate material selection philosophy into Well Integrity Statements Explore mitigation methods for potential leakage 1.2. Related Project Documents Interdependent project reports are as follows: KCP-RDS-CWE-REP-1007 Existing Wells Assessment [M1] KCP-RDS-CWE-REP-1009 Well Abandonment [M2] KCP-RDS-CWE-REP-1004 Specify Initial Well Design [M3] KCP-RDS-CWE-REP-1000 Establish CO 2 Supply Properties [M4] KCP-RDS-CRE-REP-1009 Risk Assessment and Remediation Options [M5]

7 Initial Pr = 2.69 bara RELATIVE RISK Pressure (bara) Final Pr = 117 bara KCP-RDS-CRE-REP-1008 Project Title: Kingsnorth Carbon Capture & Storage Project Page 7 of Leakage Pathways and Risk In order for leakage of CO 2 to occur from the Lower or Upper Bunter, there is a requirement for two conditions to be met. Firstly, a leak path must exist through which the CO 2 can flow and secondly, a driver must exist which will induce flow through this path. This section attempts to qualitatively address some of the leakage rates that may be encountered Risk of Leakage to Surface The risk of leakage over the life of the Hewett Field as a geological CO 2 storage facility has been considered based on a requirement for storage for 10,000 years. This is nominally the time that it would take for the CO 2 to mineralise (in the presence of water), and thus no longer be able to leak to surface. Note that there is very little water in the Lower Bunter and that the mineralisation process may not occur fully over this time period. Figure 2-1 below shows how the leakage risk will vary for a variety of potential leak paths over time. The leak paths are: Leakage through abandoned gas production wells Leakage through CO 2 injection wells Diffusion processes (applicable to all of the above) Leakage through the caprock and leakage through faults are not covered by this report. 150 Hydrostatic bara Highest risk from abandoned wells once reservoir re-pressurised 125 Abandoned Well Leak Injection Well Leak Cap Rock / Fault Leak Risk of Diffusion Hydrostatic Pressure Reservoir Pressure Risk starts to reduce as storage mechanisms take effect Risk of leak from abandoned wells starts later but Increases more rapidly 50 Increasing risk of leak from new wells starts at injection Caprock / Fault Leak risk increases after injection Time (years) Figure 2-1: Comparative Risk of Leakage Over Time For CO 2 Storage Diffusion Lowest Risk 0

8 Project Title: Kingsnorth Carbon Capture & Storage Project Page 8 of 20 The figure shows how the risk of leakage through the injection wells increases steadily from the start of injection, reaching a peak when injection stops and the reservoir has reached its maximum pressure. After this the risk stays at an increased level for a significant time (although not as high as abandoned wells) before reducing as time tends towards 10,000 years. A similar scenario is anticipated with the abandoned wells except for two issues: There is no risk at initial injection as the CO 2 will take some time to reach the wells The peak risk at the end of injection is higher due to the nature of the wells (old cement) and, in the case of some wells, the challenges of abandonment (as opposed to the injection wells which will be designed for the CO 2 injection and subsequent abandonment). In terms of leakage through the caprock, the overriding factor will be the reservoir pressure and the point at which this exceeds the hydrostatic pressure. Although the formation pressure can exceed the hydrostatic pressure, the level to which this can be achieved is based on the capillary pressure which has a high level of uncertainty associated with it. As a result, the highest risk is encountered after the reservoir pressure crosses the hydrostatic pressure. For this reason, the re-pressurisation of the reservoir by CO 2 injection will be limited to hydrostatic pressure as a maximum. Note that over time this pressure will further increase as aquifer influx continues, until there is pressure equalisation at the base of the reservoir, which means the top of the reservoir is over-pressured. This is expected to be a slow process in the Lower Bunter, but much quicker in the Upper Bunter. The risk of diffusion is initially a lower risk than leakage through wells and the caprock but follows a different trend to wells leakage, increasing with increasing reservoir pressure and further increasing over time. (Several possible assumptions may be made which will change the slope of this trend) Well Leakage Mechanisms The mechanism by which the wells will leak will be dependent to some extent on the leak path but are broadly split into four categories: Diffusion Diffusion Flow (Darcy Flow) through the cement Degradation of the cement, resulting in increased Darcy flow Corrosion of tubulars, resulting in Darcy flow Diffusion of CO2 as a leak mechanism will be an extremely slow process in a well leakage scenario. Analysis has been carried out [S1] which suggests a range of migration rates for CO2 along cement annuli may vary from 0.4 to 0.01 m/year. This range is dependent on the models utilised in the calculation and whether they include lateral diffusion and thermodynamic and chemical reactions. However, it is also noted that no upward flow through the cement will occur as a result of diffusion until the capillary entry pressure has been exceeded Darcy Flow through the Cement In the event that micro annuli, gas channels or fractures are encountered within the cement sheath, CO2 may flow more rapidly (than in the diffusion case) along the well path. One of the issues in quantifying the rate of flow along micro annuli etc. is determining the equivalent permeability of such a channel and utilising Darcy s equation in order to determine the rate. Analysis by N. J. Huerta et al [S2] has identified the range of permeabilities associated with the

9 Project Title: Kingsnorth Carbon Capture & Storage Project Page 9 of 20 size of these types of leakage pathways and they are shown in Figure 2-2 to Figure 2-4. From these graphs, the equivalent permeability of the particular feature is considered only from md to 100 md. Figure 2-2: Impact of Micro Annulus Width on Permeability Around a Casing Figure 2-3: Impact of Gas Channel Radius on Permeability in a Cement Sheath

10 Project Title: Kingsnorth Carbon Capture & Storage Project Page 10 of 20 Figure 2-4: Impact of Fracture Width on Permeability in a Cement Sheath In order to estimate the potential flow rate of CO 2 along the cement in the well annuli (in a simple manner) the Darcy equation could be applied, using the permeabilities of the cement features shown above. The viscosity of the CO 2 is derived from the final conditions of the reservoir. Using the pressure differential between the reservoir and the seabed, and the depth of the reservoir, a rough estimation of the flow rates to surface can be made. The results would show low volumes of CO 2 leakage to surface, of the order of tens of cubic metres, over a time period of 10,000 years. However, these values should not be used, because of the significant assumptions and uncertainties in the method: The form of the Darcy equation used is its most basic form for horizontal flow through a porous media. The effects of gravity have not been included, nor has the constant expansion of the CO 2 as it moves through the cement sheath. The impact of changing temperature and pressure on the CO 2 properties has not been taken into account. However, hydrostatic from overlying formations may stop flow. It is assumed that the flow channel is of constant geometry from the formation to surface. This would not be the case in reality. The width of the flow channel may also increase with time. Horizontal diffusion into adjacent formations is not taken into account. The impact of dissolution and subsequent increase in density is also not accounted for. This may result in a drop of the CO 2 into lower formations. The impact of flow due to pressure differential from the Bunter to deeper reservoirs is also not accounted for. This could occur if the Zechsteinkalk and/or the Leman sandstone is at any time in the future depleted to a pore pressure lower than that of the recharged Bunter. In reality, the volumes could be under-estimated by as much as 2-3 orders of magnitude. This is based on observations from leaking annuli of hydrocarbon gas wells with surface wellheads; significant volumes of gas can be bled off on a regular basis to prevent annular pressure build-up. This is generally due to poor isolation of gas bearing zones in the annulus. The cement, designed to provide the required isolation, is typically subject to one of the faults

11 Project Title: Kingsnorth Carbon Capture & Storage Project Page 11 of 20 described in Figure 2-2 or Figure 2-3 above. Often, this can be remediated with a cement squeeze Degradation of the Cement The degradation of the cement has not been accounted for in the consideration of Darcy flow. This would increase the rate of leakage by increasing the aperture through which flow was occurring. However, the potential for carbonate precipitation in the cement which may further reduce equivalent permeability of the micro annuli, fractures etc. has also not been accounted for [S5] This tends to be a cyclic phenomenon [S5], but it may reduce the cumulative rate of leakage. The rate of degradation in the long term has not been measured or estimated, but it is clear from experimental results carried out over periods of weeks to months [S5][S6] that the effects are porosity increase, permeability increase, and reduction of compressive strength. The critical safety factor in the leaking well scenario is the magnitude of the increase of the (vertical) permeability in the well zone [S4]. It can therefore be considered that the Darcy flow calculations described above could be used to estimate a flowrate through cement degraded by exposure to CO 2, by increasing the permeability to a suitable value. More work is required to investigate this Corrosion of Tubulars The existing wells have carbon steel casing throughout. The injection wells are planned to have carbon steel casing except where formation fluids contact the casing, where 13 Cr will be used. Therefore the lower part of the 9 5/8 casing in the injection wells will be 13 Cr, and the upper part will be carbon steel. Indicative corrosion rates for these materials in the presence of CO2 are shown in Table 2-1 below. Corrosion rates (mm/ year) 13 cr Carbon steel 5 degrees C (seabed) not applicable 5 mm/year 25 degrees C (mid way in well) mm/year 9 mm/year 52 degrees C (Lower Bunter) 0.08 mm/year 17 mm/year Table 2-1: Corrosion Rates for Casings Used in Wells On a very high level, it is therefore possible to evaluate the order of magnitude of the time taken to provide a channel to seabed via corrosion of the 9 5/8 casing. The nominal wall thickness of the casing is 24mm. The distance from the Lower Bunter to seabed is 1199m. Results are shown in Table 2-2.

12 Project Title: Kingsnorth Carbon Capture & Storage Project Page 12 of 20 Corrosion times (years) 13 cr (lower section of injection wells) Carbon steel (existing wells and upper section of injection wells) 1mm diameter hole in wall at 25 degrees C (mid way in well) 1mm diameter hole in wall at 52 degrees C (Lower Bunter) 960 years 2.7 years 300 years 1.4 years 1mm diameter channel from Lower Bunter to surface (mid depth temperatures as average) 48,000,000 years (not realistic*) 133,000 years (not realistic*) *not realistic because this considers corrosion in isolation. Corrosion of the casing will open up other paths for the CO 2. Table 2-2: Order of Magnitude of Corrosion Times For 9 5/8 Casing It is important to note some significant assumptions made in these calculations: The patterns of corrosion will not be regular, or singular, as used here for calculation. It is probable that multiple holes and/or channels would form, thus reducing the above corrosion times. Temperatures have been averaged to account for unknown depths of corrosion initiation. Rates are based on a ph of 3.2, this may change in field life. Corrosion of any metallurgy requires the presence of liquid water. There is very little water in the Lower Bunter, but there is some water in the Upper Bunter and some of the shallower formations. So the water availability is different at different depths in the well Combination of Mechanisms None of the mechanisms described above will work in isolation, and they cannot be considered as additive. Unless stopped by appropriate methods, the CO 2 will find its own path through the wellbore

13 Project Title: Kingsnorth Carbon Capture & Storage Project Page 13 of Risk Levels for Different Well Types Design risk assessments have been carried out for the different well types [M5], using safety and environmental criteria supplied by EON. The criteria and risk categories are shown in Table 3-1. A summary of the residual risks is shown in Table 3-2. Probability Severity (Safety) Severity (environmental) highly unlikely no injury contained on site unlikely minor injury contained on site, minor impact possible medical treatment moderate short term impact, offsite 4 likely reportable LTI (lost time incident) major impact, serious but reversible 5 certain major injury/ fatality major impact, long term damage to habitats/ species Risk rating = PXS (probability x severity); Low = 1 to 4, Medium = 5 to 11, High = 12 to 25 Table 3-1: Safety and Environmental Risk Criteria and Categories Annular Cement Material Annular Cement Placement Casing Material Abandonment Plugs and Method- Migration of CO 2 Tubing and Elastomer Material Operations (stresses, failure of DHSV or control line, temperature cycles) Seismic Activity New Injection Wells Existing Wells; no access issues Existing Wells; access issues Exploration Wells low low medium low low medium low medium medium medium low N/A N/A low medium medium medium medium N/A N/A low medium medium medium high N/A N/A low Table 3-2: Risk Levels For Different Well Types

14 Project Title: Kingsnorth Carbon Capture & Storage Project Page 14 of 20 For new injection wells, the casing, tubing and cement are all designed to be fit for purpose. Risks of loss of integrity are therefore generally low, except for casing material and operations. Although the rate of corrosion of the casing material can be slowed by material selection, as shown in Table 2-2 above, it can never be stopped. It can be seen however that the order of magnitude is greatly reduced. Medium risks also remain for operations, which include: tubing mechanical failure because of operational procedures exceeding design envelope casing mechanical failure because of operational procedures exceeding design envelope cement mechanical damage because of operational procedures exceeding design envelope operational error unplanned introduction of chemicals liquid CO 2 slugs in pipeline arriving at wellhead interference from external hydrocarbon production/ storage activities The mitigation for these operational residual risks is control, by processes, policies and procedures. For existing wells with no access issues, there will be no tubing or elastomers in the well, and operations do not apply. The material used for casing is liable to corrode at a much faster rate than the casing in the new injection wells, but the residual risk is reduced to medium because of the abandonment plug plans which are designed to cut off the leak path along the corroded casing. The annular cement material and placement are known to be susceptible to both Darcy flow and cement degradation, as described in and above, but again the residual risk is reduced to medium by the abandonment plans. For existing wells with access issues, i.e. 48/29-B11, 52/5-A13 and 52/5-A14, the difference is that there are legs of wells where it is difficult to put the abandonment plug plans in place, leaving a medium risk of migration of CO 2 between formations in these legs. For the 5 exploration wells, which are cut off below the seabed, access may not be possible to carry out the abandonment plug plans. The residual risk of migration of CO 2 between formations remains high. It is recommended that the status of these wells is established, and re-entry possibilities investigated. Any proposed re-entry procedures would need to be assessed for environmental benefits against environmental and operational risks.

15 Project Title: Kingsnorth Carbon Capture & Storage Project Page 15 of Well Integrity Statements 4.1. Well Integrity Statement for Injection Wells The CO 2 injection wells will be designed as fit for purpose. The materials recommended to be used in construction are considered to be low-corrosive and low- or non-degradable in their working environment, including the presence of CO 2. [M3] At the end of their working lives, the wells will be abandoned according to the recommended abandonment design [M2], using cement or other materials which are non-degradable in the presence of CO 2. The residual risks to integrity for these wells are the casing corrosion rate, which is never zero, and their operation. The mitigation is that operations during injection should be controlled by processes, policies and procedures Well Integrity Statement for Existing Production Wells without Access Issues The existing production wells will not be used for injection operations. These wells have been constructed with cement and casing materials which were not designed for CO 2 integrity. The cement placement technology was not developed to today s standards, which may have resulted in leak paths. The existing production wells will be abandoned according to the recommended abandonment design [M2], using cement or other materials which are considered to be non-degradable in the presence of CO 2. The residual risks to integrity for these wells are the cement material and placement, and the casing material. The mitigation for these is the abandonment plug design, which cuts off the potential leak paths Well Integrity Statement for Existing Wells with Access Issues The existing production wells will not be used for injection operations. These wells have been constructed with cement and casing materials which were not designed for CO 2 integrity. The cement placement technology was not developed to today s standards, which may have resulted in leak paths. The architecture of these 3 wells has been altered such that access is difficult to one or more legs to carry out the abandonment plug plans. The legs which can be accessed will be abandoned according to the recommended abandonment design [M2], using cement or other materials which are considered to be non-degradable in the presence of CO 2. The residual risks to integrity for these wells are the cement material and placement, and the casing material. The mitigation for the 3 accessible legs is the abandonment plug design, which cuts off the potential leak paths. For the 4 inaccessible legs, the residual risk of migration of CO 2 between formations remains at medium. The mitigation is to engineer a method of access which will not make the environmental risk worse. If this can be done, the mitigation will be application of the abandonment plug plans. But it is not straightforward, and may be partial only; therefore this remains a medium risk Well Integrity Statement for Exploration Wells The exploration wells will not be used for injection operations. These wells have been constructed with cement and casing materials which were not designed for CO 2 integrity. The cement placement technology was not developed to today s standards, which may have resulted in leak paths. The architecture of these 5 wells has been altered such that access is difficult or impossible to carry out the abandonment plug plans. The residual risks to integrity for these wells are the cement material and placement, the casing material, and migration of CO 2 between formations. The mitigation is to engineer a method of access, if possible, which will not make the environmental risk worse. If this can be done, the mitigation will be application of the abandonment plug plans. However, because of the severe difficulty of access, this remains a high risk.

16 Project Title: Kingsnorth Carbon Capture & Storage Project Page 16 of Conclusions 1. Throughout the life of the project, the wells have a higher risk of leakage, compared to the cap rock or faults. 2. The leakage mechanisms of diffusion, Darcy flow, and corrosion can be shown qualitatively for all wells. However, the results cannot be relied upon because of significant assumptions and uncertainties. 3. The leakage rate for corrosion of the casing can be shown qualitatively to be slower for the new injection wells than for the existing wells. 4. The leakage rate by cement degradation by CO 2 is unknown in the long term (hundreds of years). 5. None of the mechanisms described will work in isolation, and they cannot be considered as additive. Unless stopped by appropriate methods, the CO 2 will find its own path through the wellbore, by a combination of all or some of these methods. 6. Based on work done in previous reports, and on the qualitative results in this report, integrity statements have been developed for all types of wells penetrating the Bunter reservoir of the Hewett field. 7. The residual risk of migration of CO 2 between formations, and to surface, remains medium for the 4 legs of the existing production wells which have access issues. 8. The residual risk of migration of CO 2 between formations, and to surface, remains high for the 5 exploration wells.

17 Project Title: Kingsnorth Carbon Capture & Storage Project Page 17 of Recommendations 1. More work is required to investigate long term (hundreds of years) degradation rate of different types of cement in the presence of CO Operations during injection should be controlled by policies, processes and procedures, to ensure that the wells are operated within their designed operating window. 3. Re-entry procedures should be investigated for the existing production wells which have access issues. 4. The possibility/ feasibility of re-entry of the exploration wells should be investigated. 5. Any proposed re-entry methods need to be assessed for environmental benefits against environmental and operational risks.

18 Project Title: Kingsnorth Carbon Capture & Storage Project Page 18 of Mandatory References [M1] Baker RDS; Existing Wells Assessment, KCP-RDS-CWE-REP-1007 [M2] Baker RDS; Well Abandonment, KCP-RDS-CWE-REP-1009 [M3] Baker RDS; Specify Initial Well Design, KCP-RDS-CWE-REP-1004 [M4] Baker RDS; Establish CO 2 Supply Properties, KCP-RDS-CWE-REP-1000 [M5] Baker RDS; Risk Assessment and Remediation Options, KCP-RDS-CRE-REP-1009

19 Project Title: Kingsnorth Carbon Capture & Storage Project Page 19 of Supporting References [S1] [S2] [S3] [S4] [S5] [S6] Ennis-King J; CSRIO Reactive Transport Modelling of the Effect of Transport Parameters on the Breakthrough Time for Vertical Migration of CO 2 in a Micro-annulus of a Cement Plug, 4 th IES Wellbore Integrity Workshop (19 th March 2008) Huerta NJ, Bryant SL, Minkoff SE, Oldenburg CM, University of Texas; Well leakage pathways and their importance to CO 2 /cement reactions: Analysis of long-term cement competence as part of a certification framework for CO 2 sequestration projects, 6 th Annual Conference on Carbon Capture and Sequestration (7-10 th May 2007) Lombardi S, Altunina LK, Beaubien SE, NATO Public Diplomacy Division; Advances in the Geological Storage of CO 2, Springer Publishing Chadwick A. et al; Best Practices for the Storage of CO 2 in Saline Aquifers, SACS and CO2Store Report (2007) Duguid A; The Effect of Carbonic Acid on Well Cements through Lab and Field Studies, SPE (2008) Bartlet- Gouedard, V. et al; Mitigation Strategies for the Risk of CO 2 Migration Through Wellbores, SPE (2006)

20 Project Title: Kingsnorth Carbon Capture & Storage Project Page 20 of Conversion Factors Dimension Multiply By To Obtain Comments Length Area Volume Pressure Temperature Mass Density inches metres feet metres sq inches sq metres sq feet sq metres cubic inches cubic metres cubic feet cubic metres gallon cubic metres barrel cubic metres barrel = 42 US gallons psi bar a - relative to atmosphere g - relative to gauge deg Fahrenheit (T f -32) / 1.8 deg Celsius T f Temperature in deg F lb kilogram lb tonne lb/ft kg/m 3 Derived Value ppg kg/m 3 ppg = pounds per gallon in US units ppg 0.12 Specific Gravity Energy BTU 1, Joule Power BTU/hour Watt Flowrate Thermal Conductivity Specific Enthalpy scf/day m 3 /day scf/day Tonnes/day For CO 2 only bbls/day m 3 /day bbls = barrels = 42 US gallons BTU-ft/hour/ft 2 /degf W/m/K BTU/lb 2, J/kg