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CO 2 Capture and Storage: Contributing to Sustainable World Growth A.A. Espie, BP Exploration

Copyright 2005, International Petroleum Technology Conference

This paper was prepared for presentation at the International Petroleum TechnologyConference held in Doha, Qatar, 21–23 November 2005.

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AbstractThe potential to exacerbate or accelerate climate change as aconsequence of burning fossil fuels has receivedconsiderable international attention in recent years. TheKyoto Protocol emerged as one response to initiate firststeps towards stabilisation of atmospheric concentrations ofCO 2. It is clear that there is no one single technology thatcan lead to stabilisation in the timeframe that appears to berequired. Large-scale implementation of capture andstorage of CO 2 is being considered as a potential option thatcould make a material contribution to a portfolio of optionsfor the stabilisation of atmospheric concentrations.

A number of hurdles require to be overcome before thistechnology will be widely applied. These include i)significant reductions in the cost of capture of CO 2 fromcombustion processes, ii) acceptance that geological storagecan be a safe and effective mitigation option, iii) thedevelopment of commercial mechanisms that enable viable

projects to emerge and iv) clarification of a number ofregulatory and legal issues.

IntroductionThe Intergovernmental Panel on Climate Change (IPCC)was jointly established in 1988, by the WorldMeteorological Organization (WMO) and the United

Nations Environment Programme (UNEP). Its present termsof reference are to:

• Assess available information on the science, theimpacts, and the economics of - and the options formitigating and/ or adapting to - climate change.

• To provide, on request, scientific/technical/socio-economic advice to the Conference of the Parties(COP) to the United Nations FrameworkConvention on Climate Change (UNFCCC).

The Third Assessment Report from the IPCC [1] was published in 2001. This detailed review of the scientific,technical and socio-economic aspects of climate changeconcluded that there is clear evidence to show that globalclimate has changed over the last 100 years and that asignificant proportion of that change could be attributed to

the release of anthropogenic CO 2 into the atmosphere duringthe combustion of fossil fuels.

The change in the average global surface temperature ofthe earth over the last 145 years as presented in the ThirdAssessment Report is shown in Figure 1a below. Thechange in average surface temperature for the NorthernHemisphere where the changes tend to be most pronouncedis shown over the last thousand years in Figure 1b [1].

Figure 1 : Changes in Average Surface TemperatureSource : IPCC Third Assessment Report (2001)

Article 2 of the UN Framework Convention on ClimateChange (UNFCCC) identifies the ultimate objective of theConvention as the stabilisation of greenhouse gasconcentrations in the atmosphere at a level that would

prevent dangerous anthropogenic interference with theclimate system.

Evaluating the consequences of climate changeoutcomes to determine those that may be considered“dangerous” is a complex undertaking, involving substantial



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uncertainties as well as value judgments. This involves anumber of steps. First the means is needed to predict theresponse of the climate to a range of future CO 2 levels. Themain tool for this has been large simulation models orGlobal Climate Models (GCMs) that have been developed

by a number of groups around the world. To drive themodels, a set of input conditions are required. These areusually based upon a set of scenarios that relate to humanresponse in managing the amount of CO 2 and otherGreenhouse gases entering the atmosphere.

The Third Assessment Report presented predictions offuture temperature rise from a set of GCMs for an agreed setof scenarios. These indicate a range of possible rises inglobal average temperature of between 1.4 - 5.8C with thelargest impact arising from the choice of scenario. The finalstep in the process and perhaps the least well defined is torelate the temperature rise predicted by the GCMs to theimpact on the global ecosystem and hence to assess thedegree of danger that might represent.

In February 2005, at the request of the Prime Minister,the United Kingdom hosted an international conference (theExeter Conference) to review the scientific data relating toclimate change including the impact on the globalecosystem [12]. There now appears to be a generalconsensus that an average temperature rise of 2C should beconsidered as an upper limit to avoid dangerous impacts onthe global ecosystem.

There is still sufficient uncertainty in the linkage between CO 2 concentration in the atmosphere andtemperature rise for there to be a fairly broad distribution inthe estimated concentration that would enable theatmosphere to stabilize with a maximum 2C increase intemperature. However, the centre of the distribution appearsto lie in the range 500 – 550 ppm with some suggestionsfrom the Exeter conference that an even lower value might

be required.

Outlook for Future Energy UseCombustion of fossil fuels to supply energy for heat, powerand transportation is the largest factor in the increase inGreenhouse Gas concentrations in the atmosphere.

Fig 2 : Global Energy Sources Since 1970. Source IEA

In the period 1970 – 2005, International Energy Agencydata show that fossil fuel use increased by some 42%globally. However, over the next 25 years, developmentand industrialisation, particulary in the Asian economiessuch as China and India, is forecast to drive a furtherincrease in fossil fuel utilisation of some 70%.

All current indications suggest that fossil fuels willcontinue to drive the development of the global economy forseveral decades to come. Renewable sources of energy areforecast to continue to grow at a significant rate. However,they start from such a low level that they are not able tomake the reductions in emissions required.

Stabilising Global ClimateThe Carbon Mitigation Initiative (CMI) at PrincetonUniversity has provided a key analysis of potentialapproaches to the stabilisation of CO 2 concentrations in theatmosphere [11]. The conclusions of this analysis are that i)no single technology is likely to provide a ‘magic bullet‘ tostabilisation and hence that a portfolio approach will benecessary and that ii) the component technologies of a

portfolio of options capable of delivering stabilisation ofCO 2 concentrations in the atmosphere already exist or areunder development.

Figure 4 : Princeton Slices Analysis

The CMI analysis recognises the necessity to makeglobal reductions of approximately 7,000 milliontonnes/year of carbon emissions (25,700 million tonnes/yearCO 2) globally by 2050 in order to achieve stabilisation.Improvements in energy efficiency and capture and storageof CO 2 are both recognised as technologies capable ofcontributing 1,000 million tonnes/year of carbon (3.7million tonnes/year CO 2) emissions reductions within thistimeframe. It is clear that both of these options will berequired in addition to renewables in the portfolio in order tomeet a stabilisation target of 500 - 550 ppm in the desiredtimescale.

Storing CO 2 in Geological FormationsThere are several choices when it comes to selection ofgeological formations for storage of CO 2. The initialchoices are likely to be determined by a number of factorsincluding the relative siting of major sources of CO 2 andsecure storage sites and the availability of existingredundant infrastructure. It is likely that operating ordepleted hydrocarbon reservoirs will be primary initialtargets because of the security of storage that is implied bythe ability of the formation to hold gas for extended periodsof time.



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Oil Fields. When CO 2 contacts reservoir oil in the porespaces, it makes the oil more mobile by two mechanisms.Firstly it reduces the viscosity of the oil and secondly itswells the oil, increasing its saturation and increasing itsrelative permeability. The density of CO 2 at reservoirconditions is usually greater than that of the reservoir oil andless than that of water such that gravity tends to improvevertical sweep to CO 2. CO 2 is also more viscous than leangas so viscous fingering is reduced. These properties andthe unique phase behaviour of CO 2 make it an ideal fluid forenhanced oil recovery.

The pressure at which the CO 2 contacts oil plays animportant role in its ability to recover the oil. As the

pressure is increased, oil recovery is also increased untilsome 90% or greater of the oil in place is recovered. The

point at which the recovery vs. pressure curve flattens iscalled the Minimum Miscibility Pressure (MMP).

The MMP is affected by a number of factors, primarilythe composition of the oil and the injectant stream. Gasessuch as nitrogen and methane increase the MMP whileheavier hydrocarbons such as propane and butane reduce it.If the MMP is above the pressure of the reservoir of interest,natural gas liquids can be added to reduce it. The quantityof enrichment necessary to reduce the MMP to reservoir

pressure is called the Minimum Enrichment for Miscibilityor MME.

Since the NGLs are valuable components, it is morecommon to use CO 2 unenriched. This leads to a simpleminimum depth criterion when screening reservoirs forsuitability. CO 2 has significant benefits over the use ofhydrocarbon gas in that it behaves more like C 2 thanmethane and can therefore achieve miscibility at lower

pressures.However, achieving miscibility may not give the whole

picture. It is true that increasing enrichment or pressure tothe point where miscibility is attained will increasedisplacement efficiency but operating the flood below MMPmay increase sweep efficiency due to the competition ofmixed phases for the pore space. Which mechanismdominates depends primarily on the compositions of the oiland Injectant.

In practical CO 2 sequestration projects where CO 2 iscaptured from flue gas or natural gas, there is a trade-off

between the cost of separation and the effectiveness of theEOR Injectant. Both nitrogen and methane raise the MMPof CO 2 and removing these can be a very expensive matter.The impact of impurities depends on the process to be usedto sequester the CO 2. There are four potential processes:

• Miscible Displacement• Immiscible Displacement• Immiscible Gravity Drainage• Reservoir Storage/Sequestration

For miscible displacement to be successful, the pressurein the reservoir needs to be in the vicinity of the MMP or the

pressure must be raised to that level. Impurities such asmethane and nitrogen raise the MMP so for impure streams,the reservoir pressure must be even higher. However, if this

process is carried out successfully, very high recoveries can

be obtained.Immiscible displacement is not very sensitive toimpurities. The only effects have to do with lower swellingthat would take place with nitrogen or methane as comparedto CO 2. Reservoir pressure can be low and in some caseshigh recoveries can be obtained.

Immiscible gravity drainage can be used when there issignificant vertical permeability and relief. If the oil film iscontinuous, injecting gas removes the buoyancy forces thathold the oil in place and allow it to drain to an oil leg thatcan be produced. Effects of impurities are the same as withimmiscible flooding and reservoir pressure can be quite low.

Storage involves the injection of the gas mixture into atrap such that it remains there for geological time. Thisdepends on the integrity of the seal and the success of the

process will be influenced by regional fluid movement.Sequestration involves the reaction of the CO 2 with someelement of the reservoir rock or fluids. Generally this wouldonly occur in the presence of basic materials such as

potassium feldspars. There are few reservoirs that havesufficient reactivity to CO 2 to sequester significantquantities of the gas. For both storage and sequestration, the

principle effect of impurities in the gas is due to increasedcompression cost to inject the impure fraction.

Gas Fields. The storage of CO 2 in gas fields is both viableand material in potential storage volume.

The most obvious application is to convert depleted gasfields for long term storage at the end of economichydrocarbon production. The alterations required toinfrastructure are generally small and it may even be

possible to utilize the previous gas export line for CO 2 import.

However, although this option has the great advantagethat initial capital costs are likely to be small, it suffers fromthe disadvantage that it generates no income stream in theabsence of carbon trading credits or fiscal incentives. It willnevertheless offer a cheap disposal option when CO 2 transportation costs are low.

An alternative option that may offer the opportunity togenerate an incremental income stream is Enhanced GasRecovery or EGR. This is the injection of CO 2 back into the

base of a producing gas reservoir.The properties of CO 2 are such that its density will be

greater than virtually all hydrocarbon gases under normalreservoir conditions while its viscosity will be less than thatof hydrocarbon gas. This means that the potential exists fora gravity stable gas / gas displacement. Hence, CO 2 injection could not only maintain pressure and well

performance but also increase ultimate recovery.The key issue is of course the degree of mixing between

the injected CO 2 and the displaced hydrocarbon gas. Thereis some evidence to suggest that at a small scale the rate ofmixing is limited to diffusion, which is small. The key riskis therefore that of reservoir heterogeneity such that high

permeability streaks might sufficiently destabilize thegravity stable front to result in premature breakthrough ofCO 2.

Carbon Recycling For Enhanced Coalbed MethaneProduction . An increasing volume of gas production iscoming from coal deposits. Coal usually has a layer ofmethane adsorbed onto its surface. Where the coal

properties are suitable this can be produced throughdepletion. Amoco (now BP) developed a process toenhance the volume of methane recovered by injecting othergases that can preferentially displace the methane from thecoal surface. BP’s Tiffany field in Colorado is an examplewhere nitrogen was used as an injectant for EnhancedCoalbed methane recovery for several years.



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CO 2 has been seen in laboratory measurements todisplace about two volumes of methane for every volume ofCO 2 injected into core samples. However, field trials haveso far been limited and further data are being sought tosupport the case that a substantial increase in methane ratemight be expected as a result of CO 2 injection.

Some groups are now focusing attention on the use ofmixtures of CO 2 and nitrogen in order to couple thedemonstrated rate advantages of nitrogen with the potentialof CO 2 to increase ultimate recovery.

Storage in Saline Formations . Storage in brine filledformations represents the largest potential storage volumeworldwide. However, as many of the formations have not

been extensively explored nor appraised for CO 2 storage,they also have a large uncertainty. An early estimate by theIEA Greenhouse Gas R&D Programme gave the potentialfor storage in brine filled aquifers as 20 – 500% of thevolume required to reduce emissions from an IS92a profile

by 50% by 2050.Storage in brine filled formations involves immiscible

gravity dominated displacement by supercritical CO 2 withonly of order of 10% or less dissolving into the brine phase.However, over time, as CO 2 accumulates and spreads at thetop of the formation, the surface area between the brine andthe CO 2 increases, and increasing amounts of CO 2 willdissolve in the brine. The resulting CO 2 saturated brine will

be slightly heavier than unsaturated brine and will tend tosink to the bottom of the formation. Once dissolved into the

brine phase the CO 2 is in a very secure state.The downside of storage in brine filled formations is that

there may be relatively little infrastructure in place and theformations are likely to require significantly more appraisalthat producing or depleted hydrocarbon reservoirs.

Overview of Processes Involved in GeologicalStorageGeological storage combines an engineering process,injection, and induced processes in the underground systemresulting from introduction of CO 2. Underground CO 2 storage will mainly be in supercritical phase below ca 800m.It requires compression and injection at pressures exceedingthe formation pressure via injection wells. During injectionthe pressure builds up around the wellbore and the resultinggradient forces the CO 2 into the formation.

The injection phase is likely to be for 20-30 years, perhaps longer for large sites. At the point of injection, CO 2 is introduced into the pore space of the formation as aseparate phase in addition to the water and any oil and gas

phases present. The driving forces on the movement of theCO 2 are buoyancy, pressure and dissolution. Buoyancy willcause CO 2 to rise vertically through permeable formationsuntil low permeability sealing formations are reached whereit will migrate laterally and updip. Note that in producingoil and gas fields there are likely to be pressure gradientsinduced by production that will enhance the lateralmigration of CO 2 and result in breakthrough at producingwells.

The main processes that will enhance the trapping of theCO 2 underground are as follows :

Physical trapping of separate phase CO 2 (or CO 2 dissolved in oil) in geological traps is a leading concept forgeological storage. This involves CO 2 containment in thestorage reservoir by laterally continuous sealing formations

in structural and stratigraphic traps. Storage sites with physical traps include oil and gas reservoirs (active ordepleted) and mapped traps in saline aquifers. For oil andgas reservoirs, the presence of hydrocarbons proves theexistence and effectiveness of the trap and its seal for oil andgas typically on a timescale of millions of years. Naturallyoccurring CO 2 fields prove physical trapping of CO 2 for upto 100 million years [2]. For physical trapping projects,distinguishing the period of filling from the subsequentquiescent phase will be important. Based on analogues of oiland gas enhanced oil recovery and mathematicalsimulations, it is estimated that the injection period will beof the order of 20-30 years and that the pressure transientsand accumulation in the trap will occur in less than 100years depending primarily on the formation permeability.From that point forward, the CO 2 is only likely to move as aresult of disturbing the trap. Other processes can furtherreduce the tendency of CO 2 to migrate.

CO 2 dissolution in water is the second key process.Modelling studies have shown that up to 20-60% of injectedCO 2 could be dissolved with 1000 years [3,4]. At Sleipnerthe injected CO 2 (25 Mt) is predicted to completely dissolvein 4800 years, with 60% dissolution after 1000 years [4,5].This is significant for leakage risk assessment because oncedissolved, that portion of the CO 2 is unavailable for leakageas a discrete phase. The key issue here is that CO 2 as adiscrete phase is much more mobile than when dissolved inthe water phase. Solubility and the rate of dissolution arethus key parameters. For aquifer storage without physicaltraps, dissolution is the key process. This so-called solubilitytrapping is a process designed to contain the CO 2 in thesubsurface without physical trapping and it is enhanced bymigration and dissolution of CO 2 in large aquifers. CO 2 isalso highly soluble in oil and this will be important forstorage in oil reservoirs after abandonment of the oil

production.The significance of residual gas trapping, sometimes

called phase trapping, as a storage process has recently beenemphasised [3,6]. CO 2 becomes entrained in permeablereservoirs as dense phase residual saturation, occurringrapidly as the CO 2 moves through permeable formations.The rate and extent of trapping depends upon pore geometrycharacteristics and the water and gas saturations. Trappingcan only occur if there is sufficient mobile water present toenable wetting phase films to accumulate and bridge across

pore throats. This is significant in processes such as WAG but is not guaranteed in a simple drainage process such asaquifer filling. The residual saturation is strongly correlatedwith porosity in sandstone reservoirs systems. In physicaltraps in aquifers up to 20-40% of the CO 2 is effectivelylocked away via this process in a 25% porosity sandstoneonce the trap is filled. In modelling work by Holtz, morethan 60% of CO 2 is trapped by this process by the end of theinjection phase, rising to 70% after 1000 years[3]. Residualtrapped CO 2 can subsequently be dissolved in formationwater. When the CO 2 is trapped at residual saturation, theCO 2 is effectively immobile and will not migrate further orleak. Once CO

2 is trapped in this way the main release

mechanism is by faulting (or aquifer flow). However theonly CO 2 released by faulting would be that within the faultzone, i.e. only very small quantities.

Mineralisation occurs as CO 2 can react in solution withcertain minerals in the formation to form carbonates and



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alumino-silicates. The reaction rates vary between days forcarbonate minerals to hundreds of thousand of years forcertain silicate minerals. Both the rates of reaction and themagnitude of mineralization are highly dependant on themineralogy. It is estimated that the quantity of CO 2 that ismineralized by this mechanism is of the order of 1% formost clastic reservoirs [7].

CO 2 fixation by adsorption onto the surface of coals isthe main process for storage in coals. It involves acombination of physical and chemical processes that occursvery rapidly when CO 2 is injected, on a timescale of days.The nature of the fixation makes leakage processes differentand since the CO 2 is bound to the coal, the presence of a topseal may not be necessary. The main release mechanism is

by de-pressuring which could occur if water or coal bedmethane extraction takes place, or if uplift occurs after CO 2 storage.

The timescales involved for these processes range fromdays and years to millions of years. A challenge formodelling the geological storage is the wide range oftimeframes for these processes, and that the timeframerequired for storage duration is intermediate between them,in the range 500-1000 years.

Issues for Geological StorageAlthough the oil and gas industry is comfortable with theconcept of injecting and storaing gas in geologicalformations, this confidence is not generally held outside theindustry. The key issues for storage are :

• Providing the methodology and tools to enablecredible predictions of storage performance andassociated risk over extended periods of time.

• Developing appropriate legal and regulatoryframeworks for storage.

• Developing suitable long-term sstewradship processes.

Assurance of Storage IntegrityRelease of CO 2 from storage reservoirs could occur by anumber of mechanisms. Geological failure and wells are themain areas of risk relevant to long-term storage. There areother different but less common risks which could besignificant at individual sites, such as old mines. Thisshows the need for systematic risk assessment in all sites.

Methodology for Risk Analysis. A structured approachto risk mitigation requires a systematic method foridentification of scenarios that can lead to risk [10]. Thereare two approaches to this. The first relies on experience toidentify key risks. An alternative approach is beinginvestigated by some groups. This borrows the conceptfrom the nuclear industry of a database of PerformanceFactors (Features, Events and Processes in the jargon of thenuclear industry) relevant to the possible release of CO 2 from storage. Once Peer Review has identified the relevantPerformance Factors, scenarios can be created by inspectionand experience.

The next step in the process is the quantification of the

risk posed by key release scenarios. There is a significant body of work in progress in this area employing a variety ofdifferent tools. Prediction of performance over extended

periods (hundreds to thousands of years) requires estimationof three processes. These are fluid migration through

pressure gradients, buoyancy, hydrodynamic gradients or

diffusion, geochemical reactions between injected CO 2 andchemical species present in pore fluids and minerals in therock strata and the geo-mechanical interactions that mayoccur over time.

The oil and gas industry has well established tools formodelling sub-surface flow of fluids. These are generallyused at two different sets of length and time scales. At oneend of the spectrum, finely gridded models are used to

predict and optimise the movement of fluids duringreservoir production (t max of order decades, l max of order 10skm). At the other end of the spectrum, large scale, relativelycoarse models are used to estimate basin filling over periodsof hundreds of thousands to millions of years in order tohigh-grade the selection of exploration opportunities.However, the evaluation of CO 2 storage involves length andtime scales that are intermediate between these twoextremes. No work has yet been published comparing thestrengths and weaknesses of the available tools.

One key leakage scenario is relatively poorly defined at present. This is the potential for escape of CO 2 via failure ofa wellbore during filling or after sealing of the storage site.

In general, capturing all of the features of a sub-surfacesystem often requires a very large model that may be slow torun. For this reason, large detailed models are often run indeterministic mode using best estimates of parameters.Experience from the oil and gas industry indicates that thereis often a substantial degree of uncertainty about theappropriate properties to adequately model sub-surface flow.For this reason it is desirable to have probabilistic estimatesof performance where possible. The best ways to develop

probabilistic estimates for systems where some uncertaintiesand outcomes may be coupled has not yet beensystematically evaluated.

Geological Failure Mechanisms. Presence andeffectiveness of the trap, caprock and fault seal are keyissues for storage options involving physical and solubilitytrapping. It is essential to identify and predict the existenceof seal and an effective trap for the target storage site priorto injection. This is analogous to oil and gas explorationwhere finding seal and trap are key success factors.Experience in the gas storage industry by Perry [6] showsthat in the small number of failures, a key issue has been theinitial caprock characterisation. Seal identification requiresmore detailed evaluation for saline aquifer options as lessdata is usually available. Key aspects are described below.

Mapping the storage capacity and spill points of the siteis key activity especially for physical traps. This isdetermined by the sub-surface structure, by the porosity and

by the efficiency of filling. When the height of mobile CO 2 accumulates below the depth of the shallowest edge of theseal then the potential exists for CO 2 to spill into thesurrounding formation out of the storage site. Detailedmapping with 3D seismic and reservoir surveillance duringinjection are required to manage this risk.

Evaluating the seal involves geological studies of theseal properties and its lateral continuity across the site, aswell as the pressure conditions. Pressure sealing is a highlyeffective sealing mechanism for oil and gas. Pressure sealswork by having a higher water pressure in the sealing rocksabove a reservoir than in the reservoir itself, which sets up adownward pressure potential. For leakage to occur the

buoyancy of the CO 2 in the trap would have to overcome thedownward pressure gradient in addition to the capillary



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pressure. The capillary sealing capacity of a caprock isdetermined by the size of the largest connected pores acrossit, and the interfacial tension of the fluid wetting the pores.The pore system is normally water filled and non-wetting

phases like CO 2 must exceed the capillary entry pressure ofthe caprock to enter the pore system. Accumulating CO 2 exerts an upthrust on the overlying seal, and as the columnheight increases, CO 2 will be able to invade progressivelysmaller and smaller pores in the caprock until the criticalcapillary entry pressure is reached at which point CO 2 cancross the seal and leak into overlying formations. CO 2 mayalso react with some minerals that are found in caprocks,which can either increase or decrease sealing capacity. Thereaction rates vary enormously depending on the mineralogygiving rise to a need for site specific evaluations. Coupledmodelling can address this issue.

Faults and fractures need to be mapped in detail. Theirsignificance varies widely from acting as fluid conduits toacting as fluid barriers. Pre-injection assessment of theinitial conditions and risk whether faults are likely to besealing is needed. This is based on the containment of oiland gas, and detailing stratigraphic juxtaposition of sealversus non-sealing lithologies across faults using 3D seismicand fault modelling. In understanding the long termgeomechanical stability of fault and fractures, it is necessaryto understand the stress state that exists. Faults that areclose to a critical stress state will have the greatest tendencyto move in response to changes in stress induced by changesin the formation pressures, which will occur as result of CO 2 injection. These could result in small scale ‘micro-seismic’events, i.e. fracturing and fault movement. These are notconsidered significant in terms of posing a risk to theintegrity of the storage site but monitoring is required whererisks are identified.

Many oil and gas fields are underlain by active aquifersystems. The solubility of CO 2 in brine gives rise to the

possibility that CO 2 stored in physical traps could dissolveinto the brine and be transported outside the boundaries ofthe trap in the water phase. In such cases the relativevelocity and flux of the water becomes the key variable inassessing how much and how far CO 2 might migrate, butcase studies of North Sea oilfields in the NGCAS projectsuggest transport rates are likely to be slow [6].

The main geological features that could lead to high fluxrelease and leakage of CO 2 from storage sites to surface arefaults and inadequate seal. These require careful pre-storageevaluation, and ongoing risk assessment and monitoring.These mechanisms lead to risk of leakage into surroundingformations and the overburden. The risk of release to thesurface depends on whether the leakage paths connect withthe surface, which depends on the geological framework atthe particular site and whether cumulators and secondaryleakage conduits such as faults and wells pose additionalrisks.

Wells. Wells are required to inject CO 2 and may be presentfor other purposes. They can be designed to meet a widerange of conditions including the presence of CO 2. Two

potential hazards may result : these are unidentified and poorly abandoned wells and also the risk of degradation ofthe wellbore cement and materials.

Unidentified wells are a potential issue in some areas.Texas has ca. 1.5 million wells completed in various waysover more than a century. The techniques used to abandon

old wells may be a concern, as some may not provide robustseal. In addition, the locations of some long-abandonedwells is unknown, although there are techniques to findthose containing metal materials. An example of this hazardwas seen in Kansas in 2001 when gas leaking from a gasstorage facility migrated seven miles laterally beforesurfacing via century old dry uncapped water wells.Generally older wells were quite shallow and therefore theymay not penetrate deeper storage horizons. In modern oiland gas plays e.g. the North Sea, there are fewer wells, theirlocations are known and abandonment practises are morerobust.

The other main issue with wells is the potential forleakage due to degradation of cement and well materials inCO 2 rich environments as shown by Scherer [6]. A portionof the CO 2 will dissolve in the reservoir brine creatingcarbonic acid which is corrosive to both the materials andthe cement that creates a bond to the formation. Mostformation waters have a significant buffering capacity tokeep the pH from varying widely but the potential still existsfor cement degradation to take place. CO 2 interacts withmany minerals including those used to make the Portlandcement used in most well completions. The reactions andthe subsequent products can reduce the mechanical strengthand sealing characteristics of the cement. This can beexacerbated by some impurities (H 2S or SO 2).

To address this issue, the oil industry has developed CO 2 resistant cement formulations. These appear to haveacceptable performance for existing CO 2 EOR floods wherewellbore leakage due to cement degradation is seldomreported as an issue [6]. Studies are in progress to assess therate and extent of potential degradation. Industry experiencefrom EOR and natural CO 2 reservoirs has shown that

properly equipped wells can be used without significantleakage for periods of over 30 years.

Whilst satisfactory performance has been observed overa period of decades, it should be observed that the storage

period required will be 1 – 2 orders of magnitude longerwith essentially permanent storage being the objective. Thismay well lead to changes in the materials and processescurrently in use.

Leakage through wells is a key risk that needs to beevaluated for all storage sites, before, during and afterinjection. It is important because wells provide a local pointsource for potential leakage of CO 2 which could be atsignificant flux rates. Remediation procedures are availablenow to properly seal the wells and prevent further leakageand they can be applied in a period of months to preventsignificant quantities of CO 2 from entering the biosphere.The experience in Kuwait in the early 90’s shows what is

possible.

Conclusions1. The risk posed by global climate change as a

consequence of increasing levels of CO2 in theatmosphere continues to be a matter ofinternational concern.

2. The requirements for energy to supportdevelopment in many areas of the world mean thatfossil fuels will be the mainstay of the globaleconomy for decades to come.

3. Stabilisation of CO 2 levels in the atmosphere is theimmediate remediation measure under



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consideration to avoid potentially damagingclimate change

4. Capture and Storage in geological formationsappears increasingly likely to form part of the

portfolio of technologies that will be necessary inorder to be able to stabilize the concentration ofCO 2 in the atmosphere in the range 500 – 550 ppm

by 2050.5. A key issue for CCS is acceptance by public and

regulatory bodies that storage of CO 2 will haveadequate integrity to satisfy both local HSEconcerns and to meet the requirements forlongevity of storage.

6. The processes that are expected to control the performance of storage systems over extended periods of time are identified and amenable toanalysis.

7. A key activity for the next few years will be thedevelopment of a portfolio of intensively montored

projects that can be used to engage with regulatorsand the wider public in order to demonstrate thatacceptable assurance of long term storage integritycan be provided based upon short term monitoring.

AcknowledgementsThis paper is published with the kind permission of BPExploration Operating Company Ltd. The paper is basedupon the joint activities of the author, Bill Senior andCharles Christopher.

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