Reporting And Documentation

Guidelines for reporting emissions from geological storage:

Prior to the start of the geological storage operation, the national inventory compiler where storage takes place should obtain and archive the following:

• Report on the methods and results of the site characterization

• Report on the methods and results of modelling

• A description of the proposed monitoring programme including appropriate background measurements

• The year in which CO2 storage began or will begin

• The proposed sources of the CO2 and the infrastructure involved in the whole CCGS chain between source and storage reservoir

The same national inventory compiler should receive annually from each site:

• The mass of CO2 injected during the reporting year

• The mass of CO2 stored during the reporting year

• The cumulative mass of CO2 stored at the site

• The source (s) of the CO2 and the infrastructure involved in the whole CCGS chain between source and storage reservoir

• A report detailing the rationale, methodology, monitoring frequency and results of the monitoring programme - to include the mass of any fugitive emissions of CO2 and any other greenhouse gases to the atmosphere or sea bed from the storage site during the reporting year

• A report on any adjustment of the modelling and forward modelling of the site that was necessary in the light of the monitoring results

• The mass of any fugitive emissions of CO2 and any other greenhouse gases to the atmosphere or sea bed from the storage site during the reporting year

• Descriptions of the monitoring programmes and monitoring methods used, the monitoring frequency and their results

• Results of third party verification of the monitoring programme and methods

There may be additional reporting requirements at the project level where the site is part of an emissions trading scheme.

Reporting of cross-border CCS operations

CO2 may be captured in one country, Country A, and exported for storage in a different country, Country B. Under this scenario, Country A should report the amount of CO2 captured, any emissions from transport and/or temporary storage that takes place in Country A, and the amount of CO2 exported to Country B. Country B should report the amount of CO2 imported, any emissions from transport and/or temporary storage (that takes place in Country B), and any emissions from injection and geological storage sites.

If CO2 is injected in one country, Country A, and travels from the storage site and leaks in a different country, Country B, Country A is responsible for reporting the emissions from the geological storage site. If such leakage is anticipated based on site characterization and modelling, Country A should make an arrangement with Country B to ensure that appropriate standards for long-term storage and monitoring and/or estimation of emissions are applied (relevant regulatory bodies may have existing arrangements to address cross-border issues with regard to groundwater protection and/or oil and gas recovery).

If more than one country utilizes a common storage site, the country where the geological storage takes place is responsible for reporting emissions from that site. If the emissions occur outside of that country, they are still responsible for reporting those emissions as described above. In the case where a storage site occurs in more than one country, the countries concerned should make an arrangement whereby each reports an agreed fraction of the total emissions.

Annex 5.1 Summary description of potential monitoring technologies for geological CO2 storage sites

Introduction

Monitoring of the geological storage of CO2 requires the use of a range of techniques that can define the distribution, phase and mass of the injected CO2 anywhere along any path from the injection point in the geological storage reservoir to the ground surface or seabed. This will commonly require the application of several different techniques concurrently.

The geology of the storage site and its surrounding area should be characterized to identify features, events and processes that could lead to an escape of CO2 from the storage reservoir, and also to model potential CO2 transport routes and fluxes in case there should be an escape of CO2 from a storage reservoir, as this will not necessarily be on the injection site (Figure A1).

Figure A1 An illustration of the potential for leakage of CO2 from a geological storage reservoir to occur outside the storage site.

Policy Factors

If CO2 migrates from a storage reservoir (a) via an undetected fault into porous and permeable reservoir rock (b), it may be transported by buoyancy towards the ground surface at point (c). This may result in the emission of CO2 at the ground surface several kilometres from the site itself at an unknown time in the future. Characterization of the geology of the storage site and surrounding area and numerical modelling of potential leakage scenarios and processes can provide the information needed to correctly site surface and subsurface monitoring equipment during and after the injection process.

Tables A5.1 - A5.6 list the more common monitoring techniques and measurement tools that can be used for monitoring CO2 in the deep subsurface (here considered to be the zone approximately 200 metres to 5 000 metres below the ground surface or sea bed), the shallow subsurface (approximately the top 200 metres below the ground surface or sea bed) and the near surface (regions less than 10 metres above and below the ground surface or sea bed).

The techniques that will produce the most accurate results given the circumstances should be used. The appropriate techniques will usually be apparent to specialists, but different techniques can also be assessed for relative suitability. There are no sharply defined detection limits for most techniques. In the field, their ability to measure the distribution, phase and mass of CO2 in a subsurface reservoir will be site-specific. It will be determined as much by the geology of the site and surrounding area, and ambient conditions of temperature, pressure and water saturation underground as by the theoretical sensitivity of the techniques or measurement instruments themselves.

Similarly, the detection limits of surface monitoring techniques are determined by environmental parameters as well as the sensitivity of the monitoring instruments themselves. In near-surface systems on land, CO2 fluxes and concentrations are determined by uptake of CO2 by plants during photosynthesis, root respiration, microbial respiration in soil, deep outgassing of CO2 and exchange of CO2 between the soil and atmosphere [Oldenburg and Unger 2003]. Any outgassing of CO2 from a man-made CO2 storage reservoir needs to be distinguished from the variable natural background (Oldenburg and Unger 2003, Klusman 2003a, c). Analysis of stable and radiogenic carbon isotope ratios in detected CO2 can help this process.

Most techniques require calibration or comparison with baseline surveys made before injection starts, e.g. to determine background fluxes of CO2. Strategies for monitoring in the deep subsurface have been applied at the Weyburn oil field and Sleipner CO2 storage site (Wilson and and Monea 2005, Arts et al. 2003). Interpretation of 4D seismic surveys has been highly successful in both cases. In the Weyburn field, geochemical information obtained from some of the many wells has also proved extremely useful.

Strategies for monitoring the surface and near-surface onshore have been proposed (Oldenburg and Unger 2003) and applied (Klusman 2003a, c; Wilson and Monea 2005). Soil gas surveys and surface gas flux measurements have been used. To date there has been no application of shallow subsurface or seabed monitoring specifically for CO2 offshore. However, monitoring of natural gas seepage and its effects on the shallow subsurface and seabed has been undertaken and considered as an analogue for CO2 seepage [e.g., Schroot and Schuttenhelm 2003a, b].

Table A 5.1

Potential deep subsurface monitoring technologies and their likely application

Technique

Capabilities

Detection limits

Where applicable, costs

Limitations

Current technology status

2D, 3D and 4D (time-lapse) and multi-component seismic reflection surveys

Images geological structure of site and surrounding area; structure, distribution and thickness of the reservoir rock and cap rock; distribution (and with time-lapse surveys movement) of C02 in reservoir. May verify (within limits) mass of C02 in reservoir. Permanent seismic arrays can be installed (but are not necessary) for time-lapse (4D) acquisition.

Site-specific. Optimum depth of target commonly 500-3000 m. At Sleipner, which is close to optimum for the technique, detection limit in Utsira Sand is c. 2800 tonnes C02. At Weyburn, detection limit is c. 2500 - 7500 tonnes C02 (White et al. 2004). Likely that dispersed C02 in overlying strata could be detected - shallow natural gas pockets imaged as bright spots and dispersed methane in gas chimneys can be well imaged.

Onshore and offshore. Imaging poorer through karst, beneath salt, beneath gas, in general resolution decreases with depth

Cannot image dissolved C02 (insufficient impedance contrast between C02-saturated pore fluid and native pore fluid). Cannot image well in cases in which there is little impedance contrast between fluid and C02-saturated rock. These will be fairly common (Wang, 1997)

Highly developed with full commercial deployment in oil and gas industry

Crosshole seismic

Images velocity distribution between wells. Provides 2D information about rocks and their contained fluids.

Site specific. Resolution could be higher than surface seismic reflection surveys but coverage more restricted

Onshore and offshore

As above, and limited to area between wells

Highly developed with full commercial deployment in oil and gas industry

Vertical seismic profile

Image velocity distribution around a single well. Map fluid pressure distribution around well. Potential early warning of leakage around well.

Site specific

Onshore and offshore

As above and limited to small area around a single well

Highly developed with full commercial deployment in oil and gas industry

Table A 5.1 (continued) Potential deep subsurface monitoring technologies and their likely application

Technique

Capabilities

Detection limits

Where applicable, costs

Limitations

Current technology status

Microseismic monitoring

Detects and triangulates location of microfractures in the reservoir rock and surrounding strata. Provides an indication of location of injected fluid fronts. Assesses induced seismic hazard.

Site specific. Depends on background noise amongst other factors. More receivers in more wells provides greater accuracy in location of events

Onshore and offshore

Requires wells for deployment

Well developed with some commercial deployment

Monitoring wells

Many potential functions including measurement of C02 saturation, fluid pressure, temperature. Cement and or casing degradation or failure. Well logging. Tracer detection - fast-moving tracers might provide an opportunity to intervene in the leakage prevention by modifying operating parameters. Detection of geochemical changes in formation fluids. Physical sampling of rocks and fluids. In-well tilt meters for detecting ground movement caused by C02 injection. Monitoring formations overlying the storage reservoir for signs of leakage from the reservoir.

Downhole geochemical samples can be analyzed by Inductively Coupled Plasma Mass Spectrometer (has resolution of parts per billion). Perflourocarbon tracers can be detected in parts per 1012. Well logs provide accurate measurement of many parameters (porosity, resistivity, density, etc).

Onshore and offshore. More expensive to access offshore.

Certain functions can only be performed before the well is cased. Others require the perforation of certain intervals of the casing. Cost is a limitation, especially offshore

Monitoring wells deployed e.g. in natural gas storage industry. Many tools highly developed and routinely deployed in oil and gas industry, others under development

Wellhead pressure monitoring during injection, formation pressure testing

Injection pressure can be continuously monitored at the wellhead by meters (Wright & Majek 1998). Downhole pressure can be monitored with gauges. Injection pressure tests and production tests applied in well to determine permeability, presence of barriers in reservoir, ability of cap rocks to retain fluids.

Proven technology for oil and gas field reservoir engineering and reserves estimation. ICP-MS used to detect subtle changes in elemental composition due to C02 injection.

Onshore and offshore. More expensive offshore

Highly developed with full commercial deployment in oil and gas industry

Gravity surveys

Determine mass and approximate distribution of C02 injected from minute change in gravity caused by injected C02 displacing the original pore fluid from the reservoir. Can detect vertical C02 migration from repeat surveys, especially where phase change from supercritical fluid to gas is involved because of change in density. Detection limit is poor and site-specific.

Minimum amounts detectable in the order of hundreds of thousands to low millions of tonnes (Benson et al. 2004; Chadwick et al 2003). Actual amounts detectable are site -specific. The greater the porosity and the density contrast between the native pore fluid and the injected C02, the better the resolution

Onshore and offshore. Cheap onshore.

Cannot image dissolved CO, (insufficient density contrast with native pore fluid).

Highly developed with full commercial deployment in oil and gas industry. Widely used in geophysical research

Table A 5.2

Potential shallow subsurface monitoring technologies and their likely application

Technique

Capabilities

Detection limits

Where applicable, costs

Limitations

Current technology status

Sparker: Seismic source with central frequency around 0.1 to 1.2 kHz is towed generally at shallow depth.

Image (changes in) gas distribution in the shallow subsurface (typically represented by acoustic blanking, bright spots, reflector enhancement).

Generally free gas concentrations >2% identified by acoustic blanking. Vertical resolution >lm

Offshore

Greater penetration but less resolution than deep towed boomer

Gas quantification can be difficult when concentrations above 5%

Highly developed, widely deployed commercially, in sea bed and shallow seismic survey industry, also in marine research

Deep towed boomer: Seismic source generating a broad band sound pulse with a central frequency around 2.5 kHz is towed at depth.

Image (changes in) shallow gas distribution in sediments (typically represented by acoustic blanking, bright spots, etc.). Image the morphology of the sea bed. Image bubble streams in sea water

Generally free gas concentrations >2% identified by acoustic blanking. Resolution of sea bed morphology typically less than 1 metre. Penetration can be up to about 200 m below sea bed but generally less.

Offshore

Bubble streams more soluble than methane bubbles therefore may dissolve in relatively shallow water columns (approximately 50 m). Bubble streams may be intermittent and missed by a single survey. Accurate positioning of boomer is critical

Highly developed, widely deployed commercially, in sea bed and shallow seismic survey industry, also in marine research

Sidescan sonar

Image the morphology of the sea bed. Image bubble streams in sea water

Characterisation of sea bed lithology eg carbonate cementation

Optimum method for detecting gas bubbles.

Offshore

As above. Accurate positioning of side scan sonar fish is critical.

Highly developed, widely deployed commercially in sea bed survey industry, also in marine research

Multi-beam echo-sounding (Swath bathymetry)

Image the morphology of the sea bed. Repeat surveys allow quantification of morphological change. Sea bed lithology identified from backscatter.

Can identify changes in sea bed morphology of as little as 10 cm.

Offshore

As above. Greater coverage in shorter time

Widely deployed in marine research

Electrical methods

May detect change in resistivity due to replacement of native pore fluid with C02, especially when the C02 is supercritical. EM and electrical methods potentially could map the spread of C02 in a storage reservoir. Surface EM may have potential to map C02 saturation changes within the reservoir.

Relatively low cost and low resolution

Onshore and offshore surface EM capability demonstrated. Needs development for application in C02 storage

Resolution - Needs development and further demonstration

At research stage

Table A 5.3

technologies for determining fluxes from ground or water to atmosphere, and their likely application

Technique

Capabilities

Detection limits

Where applicable, costs

Limitations

Current technology status

Eddy covariance technique (Miles, Davis and Wyngaard 2005).

Measures C02 fluxes in air from a mathematically-defined footprint upwind of the detection equipment. Equipment is mounted on a platform or tower. Gas analysis data, usually from fixed open- or closed-path infra-red C02 detectors, is integrated with wind speed and direction to define footprint and calculate flux.

Realistic flux detectable in a biologically active area with hourly measurements =

4.4 x 10"7 kg m"2 s"1 = 138701 km"2/year (Miles, Davis and Wyngaard 2005)

Can only be used onshore. Proven technology. Relatively cheap. Potential to survey relatively large areas to determine fluxes and detect leaks. Once a leak is detected likely to require detailed (portable IR C02 detector or soil gas) survey of footprint to pinpoint it.

Several instrument towers may be needed to cover a whole site. With a detector mounted on a 10 m tower a footprint in the order of 104-106 nr is likely. Development may be desirable to automate measurement. Quantitative determination of fluxes may be limited to regions of flat terrain.

Deployed by research community

Accumulation chambers technique, using field IR or lab analysis of sampled gas to measure flux (Klusman 2003).

Accumulation chambers of known volume are placed on the ground and loosely connected to the ground surface, e.g. by building up soil around them, or placed on collars inserted into the ground. Gas in chambers is sampled periodically and analysed e.g. by portable IR gas detectors, and then returned to chamber to monitor build-up overtime,. Detects any fluxes through the soil.

Easily capable of detecting fluxes of 0.04g C02 m"2 day"1 = 14.6 t/knr/year (Klusman 2003a). Main issue is detection of genuine underground leak against varying biogenic background levels (potentially, tracers could help with this). Works better in winter because the seasonal variation in biological activity is suppressed during winter.

Technology proven at Rangely (Klusman 2003a, b, c). Powerful tool when used in combination with analysis of other gases and stable and radiogenic carbon isotope analysis -these help in identify the source of the collected C02. Tracer gases added to the injected C02 could also help with this - detection of fast-moving tracers might provide an opportunity to intervene in the leakage prevention by modifying operating parameters (i.e., avoid remediation).

Gaps between sample points allow theoretical possibility of undetected leaks. In oil and gas fields the possibility exists that C02 may be microbially oxidised CH4 rather than leaking C02 from a repository.

Deployed by research community

Groundwater and surface water gas analysis.

Samples and measures gas content of groundwater and surface water such as springs. Could:

a) Place a partial vacuum over the liquid and extract dissolved gases. Analyse for gases by gas chromatography, mass spectrometry etc.

b) For a fresh sample, analyse for bicarbonate content. This is essentially what was done at Weyburn in the field and at the well-head (Shevalier et al. 2004). As dissolved C02 and bicarbonate contents are linked, then analysis of bicarbonate can be directly related to dissolved C02 content (assuming equilibrium conditions).

Background levels likely to be in low ppm range. Detection limit for bicarbonate in <2 ppm range

Onshore. Should be used in combination with ground to atmosphere flux measurements as provides an alternative pathway for C02 emissions. Measurement techniques well developed and relatively straightforward (e.g. Evans et al., 2002) but care should be taken to account for rapid degassing of C02 from the water (Gambardella et al., 2004).

Should take account of varying water flux.

Commercially deployed

Table A 5.4

Technologies for detection of raised co2 levels in air and soil (Leakage detection)

Technique

Capabilities

Detection limits

Where applicable, costs

Limitations

Current technology status

Long open path infra-red laser gas analysis

Measures absorption by C02 in air of a specific part of the infra-red spectrum along the path of a laser beam, and thus C02 levels in air near ground level. It is possible to construct a tomographic map from the measurements but little track record of converting this to a flux through the ground.

Needs development but estimate potential at ±3% of ambient (c. 11 ppm) or better

Onshore. Probably has the best near-term potential to cover several km2 with one device, therefore whole fields with a few devices. Costs estimated at $1000's per unit, therefore potential to survey whole fields relatively cheaply. Once a leak is detected may require more detailed (portable IR C02 detector or soil gas) survey to pinpoint it.

Technology still under development. Measures C02 concentration over long path, so interpretation of tomography or more detailed survey necessary to locate leaks precisely. Difficult to calculate fluxes or detect low level leaks against relatively high and varying natural background.

At demonstration and development stage

Soil gas analysis

Establishment of the background flux from the ground surface and its variation is critical. Technique measures C02 levels and fluxes in soil using probes, commonly hammered into soil to a depth of 50-100 cm but can also sample from wells. Sampling usually on a grid. Lower part of probe or tube inserted in well is perforated and soil gas is drawn up for on-site analysis using a portable IR laser detector or into gas canisters for lab analysis.

Portable infra-red detectors used in soil gas surveys can resolve changes in C02 concentration down to at least ± 1-2 ppm. Absolute values of C02 in soil gas (0.2-4%) are higher than in air, but background flux variations are less below ground than above so low fluxes from underground are easier to detect. A range of gases may be measured - ratios of other gases and isotopes can provide clues to origin of co2.

Onshore. Technology proven at Weyburn and Rangely fields and volcanic/geothermal areas. LTseful for detailed measurements, especially around detected low flux leakage points.

Each measurement may take several minutes. Surveying large areas accurately is relatively costly and time consuming. In oil and gas fields the possibility exists that C02 may be microbially oxidised CH4 rather than leaking C02 from repository

Deployed by research community

Portable personal safety-oriented hand-held infrared gas analyzers

Measures C02 levels in air

Resolution of small hand-held devices for personal protection is typically c. 100 ppm.

Can be used onshore and on offshore infrastructure such as platforms. Proven technology. Small hand-held devices for personal protection typically <$1000 per unit. Could also be useful for pinpointing high-concentration leaks detected by wider search methods.

Not sufficiently accurate for monitoring C02 leakage

Widely deployed commercially

Airborne infra-red laser gas analysis

Helicopter or aeroplane-mounted open or closed-path infra-red laser gas detectors have potential to take measurements of C02 in air every ~10m.

Brantley and Koepenick (1995) quote a ± 1 ppm above ambient detection limit for the equipment used in airborne closed path technique. Less information is available on the open path technique, though it is likely to be ±1% or less.

Onshore. Proven technology for detecting methane leaks from pipelines and C02 from very large point sources. Possible application for detecting C02 leaks from pipelines and infrastructure or concentrated leaks from underground.

Measurements are made a minimum of hundred(s) metres above ground, and concentrations at ground level likely to be much higher than minimum detectable at these levels. C02 is heavier then air, so will hug the ground and not be so easily detectable as methane by airborne methods

Commercially deployed in natural gas pipeline applications, not in C02 detection applications

Notes: Data partly from Schuler & Tang (2005) included by permission of the C02 Capture Project.

Table A 5.5

Proxy measurements to detect leakage from geological co2 storage sites

Technique

Capabilities

Detection limits

Where applicable, costs

Limitations

Current technology status

Satellite or airborne hyperspectral imaging

Detects anomalous changes in the health of vegetation that could be due to leakage of C02 to ground surface. Can also detect subtle or hidden faults that may be pathways for gases emerging at the ground surface. LTses parts of visible and infra-red spectrum.

Spatial resolution of satellite and airborne images l-3m. Not calibrated in terms of flux or volume fraction of C02 in air or soil gas, but may give indications of areas that should be sampled in detail.

Onshore

Research required to determine levels of C02 in soil that will produce detectable changes in vegetation health and distribution. Many repeat surveys needed to establish (seasonal) responses to variations in weather. Not useful in arid areas

At research stage

Satellite interferometry

Repeated satellite radar surveys detect changes in ground surface elevation potentially caused by C02 injection, if absidence (ground uplift) occurs

InSAR (Interferometric Synthetic Aperture Radar) can detect millimetre-scale changes in elevation

Onshore

Changes in elevation may not occur, or may occur seasonally, e.g. due to freezing/thawing. Local atmospheric and topographic conditions may interfere.

At research stage, not yet deployed for C02 storage

Table A 5.6

Technologies for monitoring C02 levels in sea water and their likely application

Technique

Capabilities

Detection limits

Where applicable, costs

Limitations

Current technology status

Sediment gas analysis

Samples and, in laboratory, measure gas content of sea bed sediments.

Uncertain how measured gas contents relate to in situ gas contents.

Offshore. Ship time costly.

Pressure correction of data will be necessary unless pressurised sample is collected. ROV's and divers could be used for sampling if necessary. Ship time costly.

Deployed by research community for methane gas analysis offshore

Sea water gas analysis

Sample and, in laboratory, measure gas content of sea water. Protocols exist for analysis of sea water samples.

Detection limits of analytical equipment likely to be in low ppm range or better. Detection limit for bicarbonate in <2 ppm range. Ability to detect leaks in field unproven. Minimum size of leak that could be detected in practice unproven.

Offshore. Ship time costly.

As above

Deployed in near surface waters in research community, not widely used at depth.

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