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Abstract: In the environment of HTHP and high H2S, the sour gas enters into the annulus as a result of various factors, leading to annulus pressure and inducing the risk of the stress corrosion cracking in the oil string or the upper casing. To solve the problem, the environmental fracture toughness of C110 high strength casing steel was tested in the NACE A solution and the wellbore protection fluid in simulated conditions in the CORTEST pressure testing system and homemade HTHP autoclave using NACE DCB method in this paper. Wellbore protection fluid is a corrosion inhibitor for steel in oil pipe and annulus. The results indicate that the environmental fracture toughness KISSC of C110 casing steel is 22.78 MPa•m1 / 2, showing strong environmental cracking sensitivity in the standard NACE A solution. In the wellbore protection fluid under the simulated down hole conditions, where the partial pressure of H2S is 1MPa, the partial pressure of CO2 is 0.6MPa, the total pressure is 48Mpa and the temperature is 110°C, it has good resistance to stress corrosion cracking. It can be concluded that excellent wellbore protection fluid greatly increases the resistance of the material properties to environmental cracking. Research results in the paper provide a reference to the safe operation and management to the annulus pressure well in high sour gas fields. [Copyright &y& Elsevier]

Abstract: Sebei gas field is featured with the characteristics of the shallow-buried gas reservoir, long gas containing well ection, multilayer gas reservoirs beds, the complicated gas/water contact distribution, the water produced obviously, sands produced frequently from the gas wells and the multi-layers gas reservoir extracted unbalancedly in the developing process. For these reasons, the paper proposed the method that interlayer interference coefficients are defined with statistical function. Combined with the data of the sand-layer''s profile test, the effects of the numbers of different sand-lays, the perforated thickness, the perforated interval length and permeability contrast on the interlayer interference are evaluated and these permeability parameters are optimized. [Copyright &y& Elsevier]

Abstract: Rubber sleeve is sealing component of underground packers, the rubber will occur corrosion or failure under the acid medium environment, which causes gas leak and leads to the security problems of wellbore. In the paper, corrosion testing was carried out to AFLAS rubber using HTHP autoclave in the harsh environment with the pressure 60MPa, temperature 175°C, test period 7 days and the compositions of the gas phase are 20vol% H2S, 5vol% CO2, 75vol% CH4. Comparing and analyzing the changes of properties in gas and liquid phase before and after testing, such as quality, volume, tensile properties, hardness, permanent deformation, etc. The experimental results show that AFLAS rubber in gas and liquid phase has no dissolution phenomenon; moreover, tensile properties were weakened, hardness decreased and permanent deformation increased. While bubbling of AFLAS rubber in gas phase was more serious than in liquid phase, the swelling was on the contrary. Although AFLAS rubber is a good kind of anti-acid medium rubber, its mechanical properties is weakened in harsh environment. Therefore, in order to improve the effective seal life of packers in corroded environment, the corrosion influence on packer rubber should be considered when it is designed and used in high sour gas fields. [Copyright &y& Elsevier]

Abstract: Shell CO2 Storage B.V. (SCS) is planning to inject up to 10 million tonnes of CO2 in two depleted gas fields: Barendrecht (BRT) and Barendrecht-Ziedewij (BRTZ). This paper describes the process of selecting an optimised commercial value chain design for capture, transportation, injection and marketing of the CO2, requiring a helicopter view of the full system from source to sink over the 30 year injection life cycle of the project. The commercial concepts considered, selection criteria used and the selected concept will be discussed. Second, the economic modelling criteria for the main value drivers of the project will be discussed and the main differences with traditional petroleum economics will be indicated. Although the project is not pursued for financial profit, the use of the evaluation methodology described below has resulted in an optimal value proposition and value chain for Government, project, sub-contractors and society. The analysis showed that the project differed significantly from other CCS projects due to the relative weight of the transportation value component. The risk and uncertainty approach for the economic modelling of the key value drivers of the projects has resulted in a robust economic model to assist decision making for any changes to the project in a rapidly changing political environment. [Copyright &y& Elsevier]

Abstract: The onshore Barendrecht CO2 storage project in the densely populated West of the Netherlands is designed to prevent CO2 to migrate out of the deep underground through geological formations and outside of wells. Achieving maximum safe containment is facilitated by selecting depleted gas fields as CO2 storages having stored natural gas over millions of years. This also allows choosing a final storage pressure that is lower than the ambient natural pressure in the surrounding rock formations. The inverse pressure gradient prohibits potential outflow from the storage reservoir. Additional proven safety barriers are the existence of sealing caprocks and large saline aquifers that overlie the storage reservoir. These saline aquifers alone have the capacity to sequester multitudes of the CO2 volumes that are planned to be stored in the depleted gas reservoirs. It is widely accepted that wells hold the main potential of forming a migration path. In the case of Barendrecht this would mainly mean potential migration of reservoir fluids of overlying formations into the CO2 storage reservoir as pressure equalization–returning to a natural equilibrium as existed prior to start of gas production without any overpressures–is not expected to occur before hundreds to thousands of years. Nevertheless assessing the evolution of current and future well integrity with CO2 injection is crucial for ensuring containment of the injected CO2 during injection and in the long term. The Barendrecht fields have respectively two and three drilled and completed wells penetrating the CO2 storage reservoir. This paper describes the most relevant subsurface related highlights from various studies that were carried out in connection with the Barendrecht CO2 storage project. [Copyright &y& Elsevier]

Abstract: High- CO2 gas fields serve as important analogues for understanding various processes related to CO2 injection and storage. The chemical signatures, both within the fluids and the solid phases, are especially useful for elucidating preferred gas migration pathways and also for assessing the relative importance of mineral precipitation and/or solution trapping efficiency. In this paper, we present a high resolution study focused on the Gorgon gas field and associated Rankin Trend gases on Australia’s North West Shelf. The gas data we present here display clear trends for CO2 abundance (mole %) and δ13C CO2 both areally and vertically. The strong spatial variation of CO2 content and δ13C and the interrelationship between the two suggests that processes were active to alter the two in tandem. We propose that these variations were driven by the precipitation of a carbonate phase, namely siderite, which is observed as a common late stage mineral. This conclusion is based on Rayleigh distillation modeling together with bulk rock isotopic analyses of core, which indicates that the late stage carbonate cements are related to the CO2 in the natural gases. The results suggest that a certain amount of CO2 may be sequestered in mineral form over short migration distances of the plume. [Copyright &y& Elsevier]

Abstract: In 2006, the CO2ReMoVe project funded by the European Commission was launched with the objectives of developing new and common methodologies and technologies to improve site based R&D for the monitoring, measurement and verification of the injection and storage of CO2 at multiple sites. The In Salah Gas Krechba Field Joint Industry Project has been in operation since 2004 when gas from several fields was put on production. To comply with export regulations, the high content of carbon dioxide (CO2), 1–10% in the produced gas is removed and re-injected down dip from the producing gas horizon, through three horizontal injection wells at approximately 1800 m below surface. Within the framework of CO2ReMoVe, this paper discusses the site characterization and the short term system performance for the In Salah Krechba field. Prior to the injection, the reservoir unit and the seals were characterized. The resulting geological (static) model is consistent with the information obtained from the drilling activities in 2004 and 2005 and from the reprocessed 3D seismic done by Compagnie Générale de Géophysique (CGG) in 2006. A fracture study carried out on information obtained from resistivity and acoustic images available on the Krechba field had shown the existence of an open fracture network oriented along the NE-SW direction parallel to the maximum stress direction. Typically, monitoring data serves as a calibration yardstick for the static model. It was therefore valuable information to detect the CO2 breakthrough at KB-5, a suspended well located 1.7 km away from the KB-502 injector well. Tracer analysis confirmed the CO2 detected at KB-5 came from KB-502. A multi-phase, multi-component compositional simulator specially designed for CO2 sequestration (ECLIPSE 1 [1] Mark of Schlumberger. 300 with the CO2SOL option) was used to simulate and predict the properties of the injected carbon dioxide as well as that of the gas in place (mainly methane) and of the saline aquifer. History matching was used to calibrate the dynamic model by iteratively modifying parameters until a satisfactory match between model results and field measurements was obtained. The resulting dynamic model is used for short term predictions of the behaviour of injected CO2. The history matching parameters are the fracture porosity, permeability and matrix permeability (difficult to measure permeability in a fractured medium). In each iteration, the simulated bottomhole pressures, gas (CO2) injection rates were compared against field data as well as the CO2 breakthrough time at KB-5. Iterations were repeated until a good match was obtained. Predictive simulation results indicate that CO2 would reach the northern part of the gas field in 2010 and would spread out over an area including production wells in 2015, both in the northern (KB-502, KB-503) and the eastern part (KB-501) of the gas field. Although a good match has been obtained in the history matching process, some observed discrepancies could still not be explained only by fluid dynamics. Possibly, the application of coupled fluid flow and geomechanical simulations would aid in explaining the remaining discrepancies. [Copyright &y& Elsevier]

Abstract: In this paper we present a new concept developed to improve the abandonment procedure of wellbores in depleted hydrocarbon fields, amongst others in Enhanced Gas Recovery (EGR) operations. The sealing concept is designed for the long-term containment of CO2 and considers the creep ability of deep Permian Zechstein salt formations in about 3,000 m depth. It is designed to amend the current standard abandonment procedure and consists of (a) an expansive gel filling in the reservoir formation, (b) a sealing element with cement extending to the impermeable caprock and (c) a salt plug as the major long-term sealing component, compatible in its composition and property to the surrounding caprock (halite). The focus of the project work described here is to develop and to model the last-mentioned long-term salt sealing element. Numerical results show that the creep ability of the mentioned salt formations can close a formerly reamed well section and hence recover the geological salt barrier with or even without using a crushed salt backfill. A field test is conducted in the North German Altmark Rotliegend gas field (Sachsen Anhalt) in order to study the technical feasibility for recovering the initial caprock integrity, to verify numerical models and to proof the sealing capability and therefore the sealing concept. [Copyright &y& Elsevier]

Abstract: Carbon capture and storage (CCS) is widely accepted as one of main solutions to mitigate global warming in the world. However, the still-high cost of CCS is one of the major concerns, in particular in developing China. In the other hand, emission control of H2S and SO2 has already become the urgent need, and the reduction target has been set in the 11th Five-Year Plan of China. Therefore, co-storage of CO2+SO2 or CO2+H2S may be an effective way to reduce CCS cost, e.g. due to saving the de-sulphur device, and enable CCS to has an earlier deployment opportunity. In this paper, we try to, at first, reveal some key problems, i.e., trapping mechanism, injectivity and leakage risk, for co-injection and co-storage of CO2 and the strong acid SO2 into subsurface spaces in a certain gas field in China. The output of this gas field includes about 6.8% H2S and 4.6% CO2. Then, we want to insight into the possibilities and potentials of co-storage of CO2+SO2 by numerical studies. After widely referring all opened and published scientifical and technical literature, we develop a model to study a porous media system associated with the thermo-hydro-chemical coupling interactions. The hydrogeology and mineralogy of the injected formation are extracted from the historical materials of the gas field. We have performed several numerical simulations with consideration of a sandstone-clay sequence under acid-gas injection conditions. The clay formation is supposed as a sealed cap rock for the co-storage disposal system. The study examines the impact of SO2 co-injection on the pH of formation brine. Co-injection of CO2 with SO2 results in a larger and more strongly acidified zone, and alteration differs substantially from that caused by the injection of CO2 alone. The mineral alteration induced by injection of CO2 with SO2 leads to corresponding changes in porosity. Significant increases in porosity occur in the acidified zones where mineral dissolution dominates. [Copyright &y& Elsevier]

Abstract: In the paper we share our operational experience gained from three sites: Sleipner (14 years of injection), In Salah (6 years) and Snøhvit (2 years). Together, these three sites have disposed 16 Mt of CO2 by 2010. In highly variable reservoirs, with permeability ranging from a few milliDarcy to more than one Darcy, single wells have injected several hundred Kt of CO2 per year. In the reservoirs, the actual CO2 plume development has been strongly controlled by geological factors that we learned about during injection. Geophysical monitoring methods (especially seismic, gravity, and satellite data) have, at each site, revealed some of these unpredicted geological factors. Thus monitoring methods are as valuable for reservoir characterisation as they are for monitoring fluid saturation and pressure changes. Current scientific debates that address CO2 storage capacity mainly focus on the utilization of the pore space (efficiency) and the rate of pressure dissipation in response to injection (pressure limits). We add to this that detailed CO2 site characterisation and monitoring is needed to prove significant practical CO2 storage capacity–on a case by case basis. As this specific site experience and knowledge develops more general conclusions on storage capacity, injectivity and efficiency may be possible. [Copyright &y& Elsevier]

Abstract: TOTAL conducts the first French pilot to demonstrate the technical feasibility and reliability of an integrated CO2 capture, transportation, injection and storage scheme from a boiler at a 1/10th reduced scale of an industrial project. This pilot entails the conversion of an existing steam boiler into an oxy-fuel combustion unit, oxygen being used for combustion rather than air to obtain a more concentrated CO2 stream easier to capture. Then, CO2 stream is compressed and conveyed via pipeline to the Rousse depleted gas field, 30 kilometers away, where it is injected into a deep carbonate reservoir. CO2 injection has started early 2010 as all the proper official authorizations have been given. Those authorizations concern two years of injection and three years of post injection observation. An appropriate monitoring plan was designed to check the integrity of the site, to compare the CO2 behavior as it is planned and to get information to calibrate tools and models. This paper details the monitoring program: continuous measurements through permanent sensors, such as microseismicity or reservoir behavior with pressure and temperature data, and periodic surveys mainly for environmental purposes such as the groundwater quality and the surface water quality within the injection site catchment area and the fauna and the flora biodiversity. [Copyright &y& Elsevier]

Abstract: The Santos Basin Pre-salt reservoirs are located in deepwater offshore Brazil and although the oil has a good quality, their CO2 concentrations are higher than those generally found in other Brazilian fields. PETROBRAS and its partners established that they will not vent the CO2 produced in the Pre-salt layer to the atmosphere so a CO2 injection scenario is a potential alternative to improve the oil recovery. An extensive monitoring program is being considered in order to ensure the Carbon Capture and Geological Storage (CCGS) projects efficiency. However, there are several challenges to be confronted concerning the CO2 monitoring in such adverse conditions as the Pre-salt reservoirs. Among the existing techniques for monitoring offshore storage sites, some of them have already technological maturity and applicability to the Pre-salt environment but other methods must rely on some development or methodology adaptation to the specific features of these fields and they will be initiatives of the PRO- CO2 technological program of PETROBRAS Research Center. This paper addresses the main technological challenges for PETROBRAS and its partners related to the methods applicability for the CO2 storage monitoring in the Santos Basin Pre-salt Cluster and also exposes the strategies found to solve the problems. [Copyright &y& Elsevier]

Abstract: Successful large-scale deployment of CCS will require the build-up of commensurate infrastructure to transport CO2 from sources - e.g. power plants - to sinks - e.g. mature oil and gas fields. Research so far has mostly dealt with the techno-economic assessment of pre-defined CO2 value chains, which are typically country-specific and each connect a limited set of sources to a limited set of sinks. By contrast, our paper presents the JRC’s InfraCCS model, a tool that is capable of finding the optimal pipeline-based CO2 transmission network for a given set of sources and sinks. The InfraCCS model is herein applied to the case of CCS in Europe, in order to estimate the strategic benefits of joint optimisation at pan-European level compared to optimisation at the level of individual countries. [Copyright &y& Elsevier]

Abstract: The pilot study at the Ketzin site close to Berlin (Germany) aims at in-situ testing of geological storage of CO2 in a saline aquifer. Following site characterization and the drilling of one injection well and two observation wells, the in-situ field laboratory has been fully in use since CO2 injection started in June 2008. After two years of operation, about 36,000 tons of CO2 have been injected. This paper presents the key results from the second year of injection and the interdisciplinary monitoring concept in the frame of the European project CO2SINK (CO2 Storage by Injection into a Natural Saline Aquifer at Ketzin) and accompanying projects. [Copyright &y& Elsevier]

Abstract: This paper presents an overview of some recent CO2 storage capacity assessments in the Songliao and Subei Basins in China, and a discussion of some of the specific challenges that must be addressed to further assess the feasibility of CO2 storage in China. Geological CO2 storage associated with CO2-EOR is of significant interest in these basins as it offers potential to increase oil production and provide additional fuel to meet China’s increasing energy consumption. Although some CO2 is stored during such flooding projects, the greatest storage potential is only realised at the end of a field’s productive life, when a depleted field can be used as a dedicated CO2 storage reservoir. The Songliao Basin, in North-eastern China has been the largest oil and gas producing province in China. The oilfields of the Daqing and Jilin oil provinces are estimated to have effective CO2 storage capacities of 593 Mt and 71.2 Mt respectively. Extrapolation of data from around the oilfields to the whole basin suggests that the most promising saline aquifer in the basin has a theoretical storage capacity of 692 Mt CO2: Its effective storage capacity (which cannot be estimated due to lack of data) is likely to be considerably smaller however. Limited data availability means the estimate of storage capacity in this saline aquifer is based on gross simplifications and extrapolation across large areas (e.g. basin-scale) but could provide a basis for comparison with the potential for CO2 storage in other regions in China, or to help prioritise more detailed analysis. Although smaller, the onshore oilfields of the Subei-Yellow Sea Basin were also assessed, as the presence of mature oil and gas fields and natural CO2 accumulations, suggest suitable targets for storage may be found. The total effective storage capacity of the 108 hydrocarbon fields in this basin are estimated to be only 21 Mt CO2. While small, these fields may offer niche storage options for smaller industrial CO2 sources, but if CCS is to contribute to reducing China’s growing CO2 emissions, then further evaluation and development of storage in saline aquifers is likely to be needed at the same time as storage in oil or gas fields. [Copyright &y& Elsevier]

Abstract: At the request of the Dutch government Shell has been preparing for a possible CO2 storage project in the town of Barendrecht since 2007. The project involves transport and storage of pure CO2 produced at the Shell Pernis refinery (a by-product from hydrogen production) through 20 km of pipeline and into two depleted gas fields. Because this is a densely populated area public acceptance was recognised from the start as the key challenge for the project. This paper will describe the key elements of a comprehensive public acceptance strategy, and also a frank analysis of what went well and what didn’t go well on the Barendrecht project. [Copyright &y& Elsevier]

Abstract: CO2 storage in depleted gas fields is attractive but gas fields are unequally distributed geographically and can be utilized only within a restricted window of opportunity. Therefore, CO2 storage in saline aquifers can be expected to become an important element of CO2 capture and storage (CCS) systems. CO2 storage in saline aquifers is studied in the European DYNAMIS project, where special attention was paid to the relation between the geological structure, geological properties and achievable injection rates. This paper presents the results from simulations of CO2 storage in two aquifer structures. One aquifer structure is located in the English sector of the Southern North Sea and one aquifer structure located in Northern Germany. The geological model of the Southern North Sea structure was built using existing knowledge of facies geometry and distribution from literature and well logs and the overall geometry from interpreted horizons. The distributions of properties like lithology, net-to-gross ratios, porosity and permeability were stochastically modelled to represent the braided and meandering river and fan systems within the Bunter Sandstone Formation. High-porosity and high-permeability zones model fluvial channels running through the reservoir. A different approach was chosen for the North German structure. Because there is no information on the facies or petrophysical parameter distribution of the aquifer, three different model scenarios were generated. One model was created with homogeneous properties throughout the aquifer. Two other model scenarios were generated allowing the porosity and permeability to vary within certain ranges. This was done using a sequential Gaussian simulation with the known mean, minimum and maximum values of porosity and permeability, respectively. Due to the size of the aquifer structures and computing limits, up-scaling of the geological model of the Southern North Sea was required. The up-scaling was aimed to retain as much as possible of the modelled geological features such as braided river and fan systems. Several reservoir simulations were carried out in collaboration between TNO and IFP to assess CO2 injection. Given the injection rate constraints, the aim of the injection simulations was to: [•] assess the achievable rate of injection; [•] study the migration and behavior of the CO2 in the reservoir; [•] assess the most appropriate location(s) for the CO2 injection wells using alternate injection strategies. The injection strategy is relevant especially for the Southern North Sea structure, where river and fan systems may results in high-permeability zones through the reservoir. Accessing such systems may significantly improve a reservoir’s value for CO2 storage. The effect of such systems on the injection rates is demonstrated. The reservoir simulations also demonstrate the injection rates that can be achieved in tight reservoirs as in the North Germany case, and the effect of spatial variability of geological parameters. This will show whether it is reasonable to assume spatial geological homogeneity, when data on the reservoir formation are scarce. [Copyright &y& Elsevier]

Abstract: This paper summarises the modelling approach and lessons learnt at the CO2CRC Otway Project Pilot Site and how uncertainties were significantly reduced by utilising a new CO2 injection well for multi-disciplinary formation evaluation. From subsequent data analysis porosity/permeability relationships were better constrained by a depositional facies model. With a better informed geological model, the dynamic simulation results produced an excellent history match with pre and post production data from the depleted gas field. Further more, prediction of the CO2 plume direction and shape, and arrival times of the CO2 at the monitoring well, may now be regarded with a higher degree of confidence. [Copyright &y& Elsevier]

Abstract: It is recognized that most of the available geological storage capacity for CO2 is in saline aquifers. The best aquifers are likely to be in sedimentary basins (and in many cases near to fossil energy sources). However, unless the formations have been explored for hydrocarbon potential, it is likely that little data exists so significant work will be required to evaluate the realistic storage potential. Depleted gas fields offer more limited capacity but are better characterized, have seals that have successfully retained hydrocarbon gas for millions of years, and may offer a shorter route to practical implementation for early projects. Estimates indicate that depleted offshore gas fields in UK waters have the potential to store around 3.8 billion tonnes of CO2. This is a significant capacity and an inviting target particularly if existing infrastructure and wells can be reused. This paper explores the issues around injecting and storing CO2 in highly depleted gas fields using a case study based on the characteristics of a Southern North Sea gas field. The study shows that assessing and managing the flow control aspects of CO2 injection, particularly initially when the reservoirs are at very low pressure is going to be a major technical challenge. The challenges include a requirement for a high -tech flow control device at the base of the tubing to allow the dense phase CO2 to be expanded in a controlled manner. Also the requirement for CO2-specific well flow performance software as conventional software, designed to model the flow of hydrocarbons, is not necessarily suffciently rigorous when modeling a complex fluid like CO2, particularly the thermodynamics aspects. Understanding and mitigating Joule Thomson effects is necessary to avoid the possible formation of ice and gas hydrates. Without a comprehensive understanding of CO2 flow systems and accurate modeling of the thermodynamic effects it may not be possible to realize the potential that gas field storage offers. [Copyright &y& Elsevier]

Abstract: This paper describes the development and application of an methodology to screen and rank Dutch reservoirs suitable for longterm large scale CO2 storage. The screening is focused on off- and on-shore individual aquifers, gas and oil fields. In total 177 storage reservoirs have been taken into consideration (139 gas fields, 4 oil fields and 34 aquifers, with a total storage potential of about 3200 Mt CO2). These reservoirs have been selected from over five hundred potentially suitable CO2 storage reservoirs. The total number of storage reservoirs has been reduced by applying preconditions with associated threshold values. Nevertheless, the number of reservoirs is still significant and limits the possibility to use any pair-wise comparison method (e.g. Multi-Criteria programs such as Bosda or Naiade). Therefore, a excel tool has been developed based on linear aggregation. The tool screens the reservoirs based on three criteria: storage potentials, costs and effort needed to manage risk. [Copyright &y& Elsevier]

Abstract: The creation of a robust Baseline, Monitoring, and Verification (BMV) plan is key to assuring containment integrity in CO2 geological storage projects. A BMV plan has three main aims: Monitor CO2 movement in the subsurface, Calibrate dynamic earth models and finally, Verify volume of stored CO2. Wide ranges of potential BMV technologies available are currently tested in CCS pilots and industrial scale projects. This paper describes how to optimize the BMV plan design by adopting a risk-based approach and how the value of information (VOI) of specific monitoring technologies needs to be assessed to meet program objectives. [Copyright &y& Elsevier]

Abstract: The Krechba field is one of several gas fields located in the Algerian Sahara desert, and was set in operation in August 2004 as part of a joint venture with BP, Sonatrach and StatoilHydro. The natural gas in the fields contains up to 10% CO2, which has to be reduced to 0.3% before the gas is sold, resulting in the production of around 1 million tonnes/year CO2. Rather than vent the CO2 to the atmosphere (business as usual), it is re-injected into the water leg of the Krechba Carboniferous Sandstone gas producing reservoir (20 m thick) via three horizontal wells at a depth of around 1,900 metres. CO2 injection started in August 2004 and to date nearly 2.5 million tonnes of CO2 have been injected, amounting to approximately 25% of the gas extracted from the Krechba field over the same period. A number of key technologies to monitor the injection, and the subsurface movement and storage of CO2 have been, and will continue to be, deployed to provide long term assurance of sequestration. Time lapse satellite images (using PSInSARTM Technology) which measure ground deformation to assess the movement of CO2 in the subsurface have proven to be much more successful than initially thought, despite the depth of injection and the low voidage replacement rate (25%). Satellite images collected since start of injection show clear increases in ground elevation of up to 30mm around the three injectors while subsidence is also apparent in the area of maximum gas production. The images have also confirmed the CO2 is moving in the direction of preferred fracture orientation at reservoir level. Recent downhole pressure measurements in one of the injectors also indicates that the CO2 is being contained within the injection horizon. Work is ongoing to integrate the satellite images with geomechanical and seismic data to better understand how these images can be used for monitoring of CO2 movement in the subsurface. A key part of the forward monitoring programme will be the acquistion of time-lapse 3D seismic, deployment of tiltmeters and GPS to confirm and calibrate the satellite imagery data, microseismic detectors in shallow boreholes to assess the degree of rock strain and use of shallow wells to monitor the water chemistry in the vadose zone. These will supplement the ongoing tracer, wellhead sampling and satellite imagery data acquistion. This paper shares the latest results of the ongoing CO2 monitoring project. [Copyright &y& Elsevier]