Search

This report describes an assessment of environmental impact potential arising from the possible disposal of hypersaline brines into the ocean as part of reservoir pressure management for Carbon Capture and Storage. We have used sophisticated high-resolution hydrodynamic models to assess a number of guided scenarios. Although the characteristics of some brines in their undiluted form would have a high environmental impact potential, we find that dispersion in a hydrodynamically active region like the North Sea acts to dilute disposed brine rapidly, such that the potential impact footprint (area exposed to environmentally damaging salinity or temperature) is small, generally measured in 10’s of meters depending on scenario and in-situ conditions. Contaminants within the released brines may have more impact potential, depending on concentration. We recommend consideration of brine release height to further limit impact potential.

In a previous project, a silicate based sealant was developed and applied to the case of a clayey sandstone formation with the objectives of plugging the surroundings of a well typically within a radius of 1 m. Here, we report experiments conducted at the Mont Terri Underground Research Laboratory (MT-URL) focusing on the mitigation of pressure leakages associated with CO2 containment in near wellbore injection well systems. This work was performed under the auspices of the CO2 Capture Project (CCP), a three-company collaboration comprising Chevron, BP and Petrobras. The CCP effort is directed to develop more cost effective and efficient processes for CO2 concentration, capture and sequestration applied to the energy, refining, chemical and power generation industries in order to reduce greenhouse gas emissions. The experimental set-up installed at the underground test site mimics an injection well with the objectives of testing various sealants able to contain losses associated with delaminations that may occur at various well boundaries such as cement to casing and cement to caprock. Cement and caprock may also be micro-fractured. The tested sealant takes advantage of the properties of alkaline silicate solutions forming a gel after addition of an acid in appropriate strength and quantity. With a viscosity close to water, it can easily be injected in a liquid state and does not need to be activated after injection. The gelation time can be adjusted and is mostly sensitive to temperature. We tested two formulations of the sealant in a 1 m interval of the well system. The sealing capacity is evaluated by comparing flowrates at constant imposed pressure before and after injection of the sealant. Typically, a decrease by a factor of 10 of these flowrates is an indication of a good sealing performance. The first formulation proved to be efficient only for a limited time smaller than 1 month. The second improved formulation proved to be efficient for a period larger than one month.

The CO2 Capture Project (CCP) is a unique collaborative technology development program initiated in 2000 with participants from corporations, academia, governments, research institutions, policy makers and individual contractors who came together to advance development of new approaches to capture and store CO2 and improve efficiencies of existing technologies. The overall objectives have been to deliver major cost reductions for carbon capture and demonstrate that geological storage is safe, measurable, and verifiable. Since 2000, the CCP partners and cost-sharing governments have invested over $90 million to support a wide-ranging portfolio of projects to advance the understanding and development of capture and storage technologies, the economic analysis of the cost base of CCS together with analysis of regulatory and policy frameworks and a dedicated communications programme with key stakeholders. In this paper, we reflect upon the highlights and lessons learnt from twenty years of investment in technology development and the implications for the future deployment of CCS.

Wellbore integrity is a critical subject in oil and gas production and CO2 storage. Successful subsurface deposition of various fluids, such as CO2, depends on the integrity of the storage site. In a storage site, injection wells and pre-existing wells might leak due to over-pressurization, mechanical/chemical degradation, and/or a poor cement job, thus reducing the sealing capacity of the site. Wells that leak due to microannuli or cement fractures on the order of microns are difficult to seal with typical workover techniques. We tested a novel polymer gelant, originally developed for near borehole isolation, in a pilot experiment at Mont Terri, Switzerland to evaluate its performance in the aforementioned scenario. The polymer gel sealant was injected to seal a leaky wellbore drilled in the Opalinus Clay as a pilot test. The success of the pH-triggered polymer gel (sealant) in sealing cement fractures was previously demonstrated in laboratory coreflood experiments [1-3]. pH-sensitive microgels viscosify upon neutralization in contact with alkaline cement to become highly swollen gels with substantial yield stress that can block fluid flow. The leaky wellbore setup was prepared by heating-cooling cycles to induce leakage pathways in the cased and cemented wellbore. The leakage pathways are a combination of fractures in the cement and microannuli at the cement-formation interface. The exact nature of these leakage pathways can be determined by over-coring at the end of the experiment life. We used polyacrylic acid polymer (sealant) to seal these intervals. The process comprises of three stages: (1) injection of a chelating agent as the preflush to ensure a favorable environment for the polymer gel, (2) injection of polymer solution, and (3) shut-in for the polymer gelation. Then, we evaluated the short-/long-term performance of the sealant in withholding the injected fluids (formation brine and CO2 gas). The novel sealant was successfully deployed to seal the small aperture pathways of the borehole at the pilot test. We conducted performance tests using formation brine and CO2 gas to put differential pressure on the polymer gel seal. Pressure and flow rate at the specific interval were monitored during and after injection of brine and CO2. Results of performance tests after polymer injection were compared against those in the absence of the sealant. Several short-term (4 min) constant-pressure tests at different pressure levels were performed using formation brine, and no significant injection flow rate (rates were below 0.3 ml/min) was observed. The result shows more than a ten-fold drop in the injection rate compared to the case without the sealant. The polymer gel showed compressible behavior at the beginning of the short-term performance tests. Our long-term (1-week) test shows even less injectivity (~ 0.15 ml/min) after polymer gelation. The CO2 performance test shows only 3 bar pressure dissipation overnight after injection compared to an abrupt loss of CO2 pressure in the absence of polymer gel. Sealant shows good performance even in the presence of CO2 gas with high diffusivity and acidity. Pilot test of our novel sealant proves its competency to mitigate wellbore leakage through fractured cement or debonded microannuli, where other remedy techniques are seldom effective. The effectiveness of the sealing process was successfully tested in the high-alkaline wellbore environment of formation brine in contact with cement. The results to date are encouraging and will be further analyzed once over-coring of the wellbore containing the cemented annulus occurs. The results are useful to understand the complexities of the cement/wellbore interface and adjust the sealant/process to sustain the dynamic geochemical environment of the wellbore.

Carbon capture and storage underground (CCS) is now regarded as a vital and significant means to achieve 3 of the 4 IPCC pathways necessary to limit global warming to 1.5degC. Our internal analysis indicates the number of wells required to facilitate the levels of CO2 capture to meet these objectives are numerous over the next 30 years. An understanding of containment is essential for CO2 storage, but few options exist to monitor a CO2 plume growth 100's of metres away from a well. Gravity is a direct measurement of density, through substitution of water by CO2. The gravity measurement detects changes in mass in the subsurface, such that time-lapse wireline-based surveys may be taken to build up a picture of fluid movements at 100’s of meters from the wellbore. By measuring gravity in all three-axis it is possible to determine directional information about the spatial movement of fluid, even when acquired from just a single borehole. We present emerging 3-axis borehole gravity technology that enables the recording of gravitational acceleration at very high sensitivity (targeted at ≈ 5 µGal) using an innovation in resonant Microelectromechanical system (MEMS) vibrating beam technology with the aim of making small, cheap, but highly stable and highly sensitive field and borehole-deployable relative gravimeters. The vibrating beam gravimeter consists of a suspended mass connected to a vibrating beam, such that the inertial force experienced by the mass in gravitational field is communicated as an axial load on the beam. The technology is currently undergoing field trials as part of the CCP* and we show the results of a feasibility study aimed at monitoring CO2 in a deep storage reservoir in Canada which shows the gravity variation likely to be seen due to density changes during a period of CO2 injection. The displacement and substitution of the aquifer water at the storage site over time is referred to as a 4D gravity survey. The cost effectiveness of a 4D wireline gravity survey compared to 4D seismic survey is highly attractive in smaller carbon storage programs. Where the project size or complexity allow both to be run, the complementary nature of the measurements has been noted by several operators. Survey feasibility modelling and a workflow are presented that together provide important information for planning and acquiring a successful gravity survey, as well as the best time interval (given the planned injection rate), and which well location is most suitable to use. The workflow for conducting borehole gravity simulations from time-lapse reservoir models starts with a 3D model of reservoir porosity, saturation and fluid constituent density, which is used to generate a time-lapse density model from the provided set of reservoir simulation data. Vector gravity anomaly responses (gz, gx, and gy) along the wellbore in a variety of well locations are then predicted through forward modelling. The density changes due to fluid substitution are measured by the vertical, gz, gravity anomaly with respect to the reference gravity field. The fluid front progress through the field is assessed through the horizontal gravity anomalies (gx, and gy). Modelling shows plume growth is detectable even over a period of 1 year (Figure 1) and with MEMS technology lifetime monitoring is possible. We conclude that this emerging technology has the potential to provide a solution for long term monitoring of CO2 plume growth within the likely numerous wells that may be needed to fill the CO2 storage requirements resulting from the IPCC pathway scenarios to 1.5degC.

To ensure storage security, it is vital we understand, and can effectively model, the physical and chemical trapping mechanisms for CO2 storage. A key trapping mechanism underpinning storage security and immobilising a significant proportion of the CO2 plume is capillary trapping. Capillary trapping is considered to be responsible for 90% of the storage capacity in saline aquifers in the US, the largest potential CO2 storage resource. The ability to model and predict capillary trapping over large spatial scales in complex geological systems is essential to minimise risks and evaluate capacity. This paper investigates the effect of natural rock heterogeneities on capillary trapping across spatial scales in the Captain D Sandstone, from the Goldeneye formation, North Sea. That is, how heterogeneities affect CO2 saturation and distribution within rock core samples, and how those effects manifest, as a pseudo residual trapping, when upscaled to the field. A comprehensive dataset of 48 core plugs over a 65m interval have been studied. The location has industrial application as a target injection site for the discontinued Peterhead CCS project, with the aim to store 10 Mt CO2 over 10 years. These results are also applicable to other storage sites of similar geology. We have carried out steady-state core flooding experiments using medical x-ray CT, providing a detailed characterisation of continuum multiphase flow properties, including residual trapping characteristics, over cm scales. The results show that individual core plugs exhibit a large range in apparent residual trapping at the centimetre scale which averages out over scales of 10s of cm’s or greater. The average Land trapping value at the deca-centimetre scale is 1.7, however, at the cm scale, it varies between 0.8 and 2.8, representing a very large variation in locally trapped CO2. Consequently, at the plug scale for large initial saturations, approaching 1, the apparent residual saturation may vary between 0.2 and 0.5, given the variations in Land trapping parameter. At lower initial saturations, the variations are not as great in absolute terms, but the relative variation is just as large. Continuum numerical models are constructed from observations of residual trapping in heterogeneous rock cores using characterisation methods developed by Jackson et al. (2018, 2020). The trapping stage of a CO2 injection and migration project is simulated over a 65m region, while retaining the impact of heterogeneities at the cm-scale. Results from these models indicate that great care should be taken when upscaling the Land trapping parameter for use in field simulations, to estimate the long-term trapping of CO2 by capillary heterogeneities. Through quantifying the proportion of trapping resulting from capillary heterogeneities, the implications of modelling the system with the average and maximum experimental Land trapping parameter are evaluated. Modelling the system with the maximum experimental core plug Land trapping parameter results in the proportion of trapping caused by capillary heterogeneities to approximately double compared to that obtained using the average experimental core plug Land trapping parameter.

Leakage in carbon storage and hydrocarbon wells continues to be an area of concern in the development and abandonment of reservoirs. Industry need for a leakage remediation sealant that can perform in systems beyond the capability of cement squeezes has driven the development of a CO2/pH activated "smart" gel. Exploratory laboratory tests and a mock field scale well test were performed to determine the effectiveness of the smart gel. Control of the smart gel particle size distribution was demonstrated through batch synthesis experiments. Microfluidic experiments show some of the mechanisms leading to the successful sealing of an engineered fracture system. Initial and subsequent testing of the deployed smart gel in a leaky mock well completion proves the effective scale up of the smart gel sealing capability and can further drive wider adoption of this unique technology.

The Mont Terri Underground Research Laboratory (MT-URL) and Consortia affords member organizations the opportunity to bridge the gap between bench and large field scale experiments. At this underground test site, CCP4 (CO 2 Capture Project Phase 4) partners, a four company collaboration that includes BP, Chevron, Petrobras and Suncor, along with the Swiss Topographic Survey (swisstopo) who operates the laboratory, are conducting 1) an experiment that focuses on the mitigation of pressure leakages associated with CO 2 containment in near wellbore injection well systems using novel sealants and, if resources are available, 2) a fractured caprock breach sealing experiment. The mock well system experiment for CO 2 breach mitigation is of immediate interest. This experiment, designated CS-A, is operational with equipment installation accomplished late 2 nd quarter 2015 and experimental protocols that commenced late December 2015 scheduled to run through the summer of 2017. Sealant testing is scheduled to begin in late 2016. The objective is to assess the ability to characterize and seal induced leaks at micro annular interfaces (casing, cement and country rock) using novel sealants with determination of the long term sealing integrity. The 2 nd experiment is in an earlier stage of development, having been scoped in 2014 for costing and resource alignment. This second project requires additional participants to spread costs before the final design is set.

Wellbore integrity is a critical subject in oil and gas production, and CO2 storage. Successful subsurface deposition of various fluids, such as CO2, depends on the integrity of the storage site. In a storage site, injection wells and pre-existing wells might leak due to over-pressurization, mechanical/chemical degradation, and/or a poor cement job, thus reducing the sealing capacity of the site. Wells that leak due to microannuli or cement fractures on the order of microns are difficult to seal with typical workover techniques. We tested a novel polymer gelant, originally developed for near borehole isolation, in a pilot experiment at Mont Terri, Switzerland to evaluate its performance in the aforementioned scenario.The polymer gel sealant was injected to seal a leaky wellbore drilled in the Opalinus Clay as a pilot test. The success of the pH-triggered polymer gel (sealant) in sealing cement fractures was previously demonstrated in laboratory coreflood experiments (Ho et al. 2016, Tavassoli et al. 2018). pH-sensitive microgels viscosify upon neutralization in contact with alkaline cement to become highly swollen gels with substantial yield stress that can block fluid flow. The leaky wellbore setup was prepared by heating-cooling cycles to induce leakage pathways in the cased and cemented wellbore. The leakage pathways are a combination of fractures in the cement and microannuli at the cement-formation interface. The exact nature of these leakage pathways can be determined by over-coring at the end of the experiment life. We used polyacrylic acid polymer (sealant) to seal these intervals. The process comprises of three stages: (1) injection of a chelating agent as the preflush to ensure a favorable environment for the polymer gel, (2) injection of polymer solution, and (3) shut-in for the polymer gelation. Then, we evaluated the short-/long-term performance of the sealant in withholding the injected fluids (formation brine and CO2 gas).The novel sealant was successfully deployed to seal the small aperture pathways of the borehole at the pilot test. We conducted performance tests using formation brine and CO2 gas to put differential pressure on the polymer gel seal. Pressure and flow rate at the specific interval were monitored during and after injection of brine and CO2. Results of performance tests after polymer injection were compared against those in the absence of the sealant.Several short-term (4 min) constant-pressure tests at different pressure levels were performed using formation brine, and no significant injection flow rate (rates were below 0.3 ml/min) was observed. The result shows more than a ten-fold drop in the injection rate compared to the case without the sealant. The polymer gel showed compressible behavior at the beginning of the short-term performance tests. Our long-term (1-week) test shows even less injectivity (~0.15 ml/min) after polymer gelation. The CO2 performance test shows only 3 bar pressure dissipation overnight after injection compared to abrupt loss of CO2 pressure in the absence of polymer gel. Sealant shows good performance even in the presence of CO2 gas with high diffusivity and acidity.Pilot test of our novel sealant proves its competency to mitigate wellbore leakage through fractured cement or debonded microannuli, where other remedy techniques are seldom effective. The effectiveness of the sealing process was successfully tested in the high-alkaline wellbore environment of formation brine in contact with cement. The results to date are encouraging and will be further analyzed once over-coring of the wellbore containing the cemented annulus occurs. The results are useful to understand the complexities of cement/wellbore interface and adjust the sealant/process to sustain the dynamic geochemical environment of the wellbore.

The CO2 Capture Project, currently in its fourth phase (CCP4), is a unique collaborative technology development program initiated in 2000 with participants from corporations, academia, governments, research institutions, policy makers and individual contractors who have come together to advance development of new approaches to capture and store CO2 and improve efficiencies of existing technologies. The overall objectives are to deliver major cost reductions for carbon capture and demonstrate that geological storage is safe, measurable, and verifiable. The 3rd phase of CCP, CCP3, was recognised with a CSLF Global Achievement Award, reflecting CCP’s role as an exemplary model of science-based research, development and demonstration. CCP4 (2015-20) continues to support work in capture and storage at multiple levels of development, spanning concept development to demonstration. CCP4-SMV (storage monitoring and verification) has built on its prior phases in developing CO2 storage assurance technology from modelling / simulation and experiments to field-scale tests. Its current focus is on integrated field tests of cost-effective surveillance technology and evaluating effective responses to unanticipated fluid / pressure migration events (“contingencies”).

Two concepts have been very influential in aiding the evolving understanding of CO 2 storage systems. The first of these was the trapping diagram that first appeared in the IPCC Special Report on CCS (2007). This shows the evolution of the balance of trapping processes – physical seals, capillary trapping, dissolution and reactive trapping - over time. This clearly demonstrated the need to move beyond simplistic estimates of storage capacity to understanding the interplay between the trapping processes. The second was a conceptual model of the evolution of risk through the life of a CO 2 storage site presented by Benson at GHGT-8. This showed risk rising to a peak during injection and then declining back to a low level as the site stabilised post injection. Both of these concepts were presented in diagrammatic form and have been the subject of considerable discussion ever since. As an illustration, opinion remains divided as to whether storage risk peaks and declines or whether it continues to rise as buoyant migration causes the plume to contact an ever increasing area of seal. In this study we use a simplified model based upon vertical equilibrium concepts to develop analytically derived versions of both the IPCC trapping diagram and to explore the risk of seal failure in the post-closure period.

Three locations in the midwestern US were evaluated for saline reservoir sequestration of CO2 transported from refineries and chemical plants along existing pipeline rights-of-way. Based on formation volume calculations, the potential storage capacity in a single formation (the Mt. Simon Sandstone) is in the range of several billion tons. Compositional reservoir simulations using single-well radial models were completed to predict the formation pressures, CO2 spreading, and dissolution following injection. Injectivity at all sites appears to be sufficient for more than 1 Mt/year/well of CO2 without exceeding the fracture pressure limits, and no leakage of CO2 into shallower horizons was predicted. A horizontal injection well scenario showed a smaller increase in reservoir pressure than vertical wells. The geochemical evaluation included a summary of the brine chemistry and mineralogy of the reservoir and caprock formations. Equilibrium geochemical simulations for several scenarios did not indicate any adverse reactions as a result of CO2 injection. A preliminary economic and engineering assessment of several injection scenarios showed that the cost of CO2 dehydration, compression, transport, and injection is nearly $ 20/t, excluding capture costs. The largest capital cost is compression and pipeline systems, and the largest operational cost is compression. System costs may be reduced by optimizing the location of storage reservoirs closer to the emission sources or through development of a regional shared transport network and storage site.

[1] Sequestration of carbon dioxide in deep saline aquifers has been proposed and investigated as a viable solution to help mitigate carbon emissions from fossil fuels. Much research has been directed at understanding the transitions of supercritical CO2 from being a mobile fluid phase to being trapped by capillarity or dissolved in groundwater; such transitions lead to a reduction in mobility of CO2 and hence in the risk of leakage to the surface. Following injection, buoyant plumes of CO2 migrate updip towards structural traps in the geological strata; however, some of this CO2 may be capillary trapped in pore spaces or dissolved in groundwater en route. Since CO2 saturated groundwater only has a small CO2 concentration, the dissolution of any large, structurally trapped plumes of CO2 may be controlled by the availability of unsaturated groundwater. In an aquifer of finite vertical extent, this may be rate limited by a combination of (i) the background hydrological flow coupled with (ii) the slow lateral exchange of relatively dense, CO2saturated groundwater with unsaturated groundwater. In an inclined aquifer, this may be controlled by the slow along-aquifer component of gravity. Structurally trapped plumes of CO2 may therefore persist for many thousands of years, and, since they are potentially highly mobile, may represent an important contribution to the long term risks associated with CO2 sequestration at particular sites.

Abstract A range of techniques have been developed to improve the recovery efficiency of oil reservoirs. Of these, gas injection is currently the second most common EOR process after thermal methods that is practiced on a material scale with some 250 mbd directly attributable. Initial exploration of gas injection focused on use of a hydrocarbon injectant. However, competitive sales markets for hydrocarbon gas led to the identification of CO2 as a potential injectant. There is now over thirty years experience with the injection of CO2 for Enhanced Oil Recovery. Although initially developed as a means to improve oil recovery, there is renewed interest in the potential for CO2 EOR as an option to reduce global emissions of Greenhouse Gases. This may lead both to a significant expansion in the level of application as well as to some significant changes in the way in which CO2 EOR is applied. Introduction Many areas of the world are actively implementing gas injection to maximise the potential of extensive oil reserves. A successful gas flood requires two key criteria be satisfied. Firstly, the injected gas must be able to mobilise additional oil. Secondly, the flood must be able to sweep the mobilised oil to producers. Additional oil may be mobilized in two ways. Firstly, gas may be able to access parts of the reservoir that have been bypassed by water. Second, gas may enable some incremental recovery from those parts of the reservoir already swept by water by virtue of the fact that the residual oil saturation to gas is usually somewhat lower than for water. Many of the current gas injection schemes operate near to miscibility conditions to mobilise the maximum amount of incremental oil. The injected gas is often used in combination with water in order to get the joint benefits of mobilising oil with the miscible gas while using water to sweep mobilized oil to producing wells.

Publisher Summary Risk assessment should be actively used at all stages, before, during and after injection. It is used to identify the key risks that require specific attention for all sites and to inform monitoring strategy. During site selection and evaluation, well and 3D seismic data must be considered essential, and more new data acquisition will normally be required for aquifer options. Understanding the processes and potential leakage mechanisms is vital in developing the framework for managing geological storage. In considering performance criteria, it is important to recognize that the amount of mobile CO2, with potential for leakage as a separate phase diminishes after injection, thereby reducing the risk of leakage. Leakage mechanisms are fairly well understood, although the kinetics and quantification require further research. The local risk of high flux leakage and release is primarily from wells, faults, and possible local overburden accumulators. Seal presence, trap integrity and fault presence and the risk from old wells need to be rigorously assessed in the site selection phase.

Publisher Summary A structured approach to risk mitigation requires a systematic method for identification of scenarios that can lead to risk. There are two approaches to this. The first relies on experience to identify key risks. An alternative approach is being investigated by some groups. This borrows the concept from the nuclear industry of a database of Performance Factors (Features, Events, and Processes in the jargon of the nuclear industry) relevant to the possible release of CO2 from storage. Once Peer Review has identified the relevant Performance Factors, scenarios can be created by inspection and experience.

Publisher Summary This chapter provides an update on the in Salah gas (ISG) project and the accompanying CO2 storage assurance project, which it is proposed and managed under the umbrella of a joint industry project (JIP). It consists of project management, establishing a project baseline, imaging CO2 migration, well based monitoring, rock/fluid interactions, detecting surface (geologic) seepage, integration and risk assessment, and communications. This CO2 project differs significantly in geological character and storage process from the existing Sleipner and Weyburn monitoring projects and offers an ideal opportunity to gain important additional information on the permanence and safety of CO2 geologic storage. The ISG project provides an important opportunity to study a gas field development project where geological storage at a field scale is employed to mitigate the environmental impact of the produced CO2 stream, which represents—60% of the projects emissions footprint.

Publisher Summary This chapter describes the process of geologic storage of CO2 from refineries and chemical plants in the midwestem United States. Three locations in the midwestem United States were evaluated for saline reservoir sequestration of CO2 transported from refineries and chemical plants along existing pipeline rights of way. Based on formation volume calculations, the potential storage capacity in a single formation, the Mt. Simon Sandstone, is in the range of several billion tons. Compositional reservoir simulations were completed to predict the formation pressures, CO2 spreading, and dissolution following injection. Injectivity at all sites was sufficient for more than 1 mt/year/well of CO2 without exceeding the fracture pressure limits, and no leakage of CO2 into shallower horizons was predicted. A horizontal injection well scenario showed a smaller increase in reservoir pressure than vertical wells. The geochemical evaluation included a summary of the brine chemistry and mineralogy of the reservoir and caprock formations. Equilibrium geochemical simulations for several scenarios did not indicate any adverse reactions as a result of CO2 injection. A preliminary economic and engineering assessment of several injection scenarios showed that the cost of CO2 dehydration, compression, transport, and injection is nearly $20 per ton, excluding any capture costs. The largest capital cost is in compression and pipeline systems, and the largest operational cost is that of compression. System costs may be reduced by optimizing the location of storage reservoirs closer to the emission sources or through development of a regional shared transport network and storage site.

The COACH project was an EU-China collaboration funded by the EU’s FP7 R&D programme to assess the potential for a CCS demonstration project in China.The Jing-Jin-Ji Region of North-Eastern China is a major contributor to China’s CO2 emissions profile with large stationary sources currently contributing annual emissions of nearly 350 million tonnes CO2 per year, of which approximately 300 million tonnes CO2 has the potential to be captured and stored annually. Two scenarios for a CCS demonstration project located in the onshore section of the Bohai Bay region in Shandong Province in the North East of China were assessed in this study.Capture studies considered a polygeneration scenario while scoping studies were performed of storage potential within the onshore Bohai Bay area. Size scales of 1Mtonnes/year (c. 100 million tonnes storage capacity) were considered.Introductory screening was performed for four areas to review their potential for development for CO2 storage. These included two oilfield provinces, a regional saline formation and a coal mining area. A preliminary risk assessment was prepared covering both technical and non-technical issues.Order of magnitude costs likely to be incurred in implementing a CCS demonstration project were assessed. These included estimates of the cost of capture and conditioning of the CO2, transportation to a storage site and the storage of the CO2 in a geological formation. The cost of capture was expressed relative to a reference case comprising an IGCC without CCS. A single product, electricity, was considered. Storage costs were assumed to arise from appraisal (saline formations and coal mining areas), wells (new CO2 injectors and remediation or upgrading for existing wells) and monitoring.

The COACH project (Cooperation Action Within CCS China-EU11EC/FP6 Contract #038966, co-ordinated by F. Kalaydjian, IFP Energies nouvelles, France.) was launched on November 1st 2006 for a period of 3 years, as part of the 6th framework programme of the European Commission22The French Agency for Development (AFD) is gratefully acknowledged for its financial support to the dissemination, knowledge sharing and capacity building activities developed in COACH.. Gathering 20 partners comprising 8 Chinese partners and 12 European partners, the COACH project was conceived as contributing to the first phase of the Near Zero Emission Coal fired power plants (NZEC) programme, a 3-phase programme developed between the European Union and China, aiming at combating climate change by enabling the deployment in China of thermal power plants equipped with CO2 capture and storage (CCS) facilities.The objective of the COACH project was to establish the basis for the large-scale use of coal for polygeneration in China with pre-combustion capture, transport and geological storage of CO2. Main efforts were place on a future CCS demonstration operated on an Integrated Gasification Combined Cycle (IGCC) thermal power plant fully equipped for converting and splitting the produced syngas into a hydrogen-rich fuel gas and CO2, and with a subsequent storage of CO2 in either mature hydrocarbon reservoirs (Dagang or Shengli oil provinces), deep saline formations or unmineable coal seams. Focus was made on the emission sources and storage sites located in the part of the Bohai Basin in the Shandong Province.The paper will present the main outcomes of the project as follows : •Structuring the China-EU COACH venture: In order to enabling the sharing of knowledge between European and Chinese COACH partners and building capacity a survey of CCS activities was performed, workshops were organised in EU and China, a cooperative website was created and two one-week long CCS schools were organised in China gathering more than 100 students 2/3 thereof coming from China and the remaining from Europe;•Technical actions and challenges relating to CCS, gasification and polygeneration: A generic IGCC concept implemented with CO2 capture was defined and compared against a plain IGCC based on the GreenGen Phase I system without CO2 capture. A detailed analysis of technologies needed for implementing an option for CO2 capture in an IGCC process with provision for production of electricity and methanol was carried out as well as a cost analysis of both CO2 capture and transport;•Geological assessment and storage sites mapping: A quantitative assessment of the potential storage sites (the Dagang and Shengli oil provinces, the deep saline aquifers nearby and the Kailuan coal mining area) was performed along with a mapping of the possible transport infrastructure (by pipelines or ships) that could be developed to connect CO2 sources to CO2 sites; with regards to storage capacity, the main capacity was found to reside in the deep saline aquifers (several giga tonnes) but would require further geological investigation for delivering definite values. The storage potential in oil fields was found to be much smaller (less than one giga tonne) but could provide opportunities for enhanced oil recovery. Finally, the coals of Kailuan mining area exhibit a high ability to adsorb CO2 and provide enhanced coalbed methane recovery, but their injectivity remains to be verified.•Case studies and recommendations for CCS demonstration in China: By integrating results obtained in the previous tasks dealing with CO2 capture and CO2 storage, two scenarios (one small scale–from 0.1 to 1 million tonnes of CO2 per year, one large scale–2 to 3 million tonnes of CO2 per year) were designed to screen options for a possible CCS demonstration project. These alternative CO2 streams are both considered captured from the GreenGen IGCC power plant in Tianjin and transported to one or more geological formations in the Bohai Bay geological basin for permanent disposal. Storage for the smaller scale scenario could be accommodated in the Dagang or Shengli oilfields. Storage for the larger scale scenario (2–3 million tonnes a year) could be accommodated in the Shengli oilfield province (in a number of fields) or potentially in the saline formations that can be found in the Huimin sub-basin area. For each of these options, a preliminary risk assessment was performed. A thorough cost analysis was performed. Policy and regulation issues pertaining to a shift towards CCS in China. The 3-year targeted cooperative actions under the COACH project have mobilised capacities in China and Europe and paved the ground for subsequent CCS demonstrations in China. The next phase of the China-EU NZEC programme should start in 2010 and deliver FEED studies which should allow starting operating a CCS demonstration in China by 2015.

Summary Geophysical monitoring of underground CO2 injection forms an important component of a carbon capture and storage program. Until recently, seismic methods were used to map the spreading of CO2 plume and are the dominant technique used for monitoring. However, there is a disadvantage in use of seismic whose relationship with fluid saturation are interpreted based on the empirical rock physics models using effective medium theory and often only known by statistical methods with large error bars. Gravity measurements have a unique advantage among many geophysical methods that the mass density change being detected by the gravity within a reservoir is directly and uniquely related to the dynamic fluid redistribution. In this paper the status of a program to develop a wireline deployable three-axis borehole gravity sensor with a target sensitivity of ~ 5 μ Gal is firstly introduced, using a resonant MEMS (Microelectromechanical systems) vibrating beam technology innovation. Followed by a feasibility study for monitoring of CO2 in a deep reservoir at the Aquistore storage site in Canada. We model and predict the gravity variation due to density changes during a period of CO2 injection. This study demonstrates the pre-survey feasibility modelling of the emerging field of timelapse gravity monitoring.