Lars Ingolf EideIvano Miracca Scott Imbus

CO2 Capture Project Phase 2 Status mid-2008

Non-seismic Geophysical Monitoring Techniques - Inversion of gravity data indicating extent of CO2

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CO2Capture Project Phase 2 – status mid-2008

Lars Ingolf Eide1, Ivano Miracca2 and Scott Imbus3

1Eide Environmental, Stian Kristensens vei 33, N-1348 Rykkinn, Norway

2Saipem* S.p.A., Viale De Gasperi 16, I-20097 San Donato Milanese, Italy *A subsidiary of Eni S.p.A.

3CO2 Capture & Storage, Earth Sciences Division, Chevron Energy Technology Co 1500 Louisiana Street Houston, Texas 77002 USA

Abstract:The CO2Capture Project Phase 2 (CCP2) Programme began in 2005 and will be completed in 2009. The Programme includes development and/or studies of ten CO2 capture technologies and seven CO2 storage projects. This article summarizes the status of the Programme nine months before the completion of the technical work. For the completed technology studies and developments the main objectives and targets have been met.

INTRODUCTION

The CO2Capture Project Phase 2 (CCP2) Programme (2005-2009) continues the development of the most promising technologies for CO2 Capture and Storage (CCS) identified in the CCP1 Programme (2001-2004; Thomas (ed.), 2005; Benson (ed.), 2005). The CCP2 programme has two major technical focal points 1) Development of Capture technologies and 2) Storage, Monitoring and Verification (SMV) tools and processes. The programme also includes analysis of policies that support use of capture and storage methods, as well as efforts to communicate the advances in these areas of the programme. Phase 2 of the programme continues the most promising technologies from Phase 1, has identified and developed technologies not included in the first phase and is currently updating the cost evaluation. Most of the technology development activities will be concluded in 2008, with the remainder completed in early 2009. This paper provides an overview of the achievements that have been made in the last four years (Phase 2) in the technology programmes.

CAPTURE

Objectives The CCP2 Capture Programme is targeting the development of technologies with potential to reduce the costs of capturing CO2 by 50% for retrofits and by 75% for new-built plants from the baseline established in 2000. Scaling up technologies by one order of magnitude compared to the scale tested in CCP1 is the main objective of CCP2. Since most technologies achieved “proof-of-concept” in CCP1, the expected level of development by the end of CCP2 is “ready for pilot testing”. Some technologies may be ready for demonstration and others may not achieve the “ready for pilot” state by end of Phase 2 and will need further laboratory scale development before a pilot unit will be built.

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The CCP2 capture technology portfolio The CCP2 portfolio of capture technologies consists of seven pre-combustion technologies, two oxyfiring concepts and one post-combustion technology. Table 1 lists the technologies together with the involved R&D institutions and co-funding programmes. The technologies may be grouped as follows:

Technologies with completion date in 2008. These technologies receive a major part or all of the funding from CCP2.

Technologies with completion date in 2009. These technologies receive funding from CCP2, the EU and the technology providers.

Technology developments with completion date in 2008.

There are four technologies in this category. All will be completed in the third quarter of 2008 and three are continuations from CCP1.

Fluidized Catalytic Cracker Oxyfired Regenerator (FCC)

This technology is new to CCP2. The objective was to perform a feasibility study of the Fluidized Catalytic Cracker (FCC), which is the single largest emitter of CO2 in refineries, with its Regenerator operating in oxycombustion mode. CO2 is emitted through the regenerator exhaust, where coke deposited on the catalyst is burnt with air. Capturing CO2 from this post-combustion stream is likely to be very expensive due to low concentration and low pressure of flue gas stream. In the oxy-fired FCC catalyst regeneration concept, pure oxygen instead of air is used to burn the coke in the regenerator. The benefit is that the flue gas is mainly water and CO2, and is nearly nitrogen free. A CO2-rich stream suitable for sequestration can be obtained by compressing and cooling the flue gases and condensing out the water.

To prevent temperature runaways during the combustion reaction, recycled CO2 is used to dilute the oxygen stream to concentrations close to the normal concentration in air. An air separation unit (ASU) is required to produce the oxygen needed for the combustion of coke.

A study to develop a cost basis for the base case and the oxy-fired cases for CO2 sequestration from a FCC regenerator has been performed. The case considered retrofitting an existing unit operated by Petrobras at Landulpho Alves refinery. The capacity was 10,000 m3/d (cubic meters per day) and total CO2 production around 3500 t/d.

The process schemes shown in Fig. 1 were compared.

Each case requires a minimum CO2 purity of 95% and a minimum of 90% CO2 recovery. Optimization of the CO2 purity and recovery was not part of this study; however, the steam and electric consumption was minimized when possible.

The project was completed in Fall 2007 with the conclusion that the oxy-fired FCC concept is feasible. The technology is ready for a demonstration unit.

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Table 1. List of major capture projects developed or evaluated in phase II of CCP. Underscore indicates the lead technology partner.

Project Name Participating organizations Starting

Date

Duration

Oxy-firing Fluidized

Catalytic Cracker, FCC

Randall Gas Technologies

(ABB Lummus Global, Inc.)

Spring 2007

6 months

Best Integrated Technology, BIT

GE, Nexant June 2005

36 months

Chemical Looping Combustion, CLC

Chalmers University, Alstom Boilers , Consejo Superior Investigaciones Cientificas (CSIC), Shell, Technical

University of Vienna (TUV), Tallinn University

January 2006

30 months

Hydrogen membrane

reformer, HMR

StatoilHydro June 2005

36 months

Membrane Water Gas Shift,

MWGS, and Membrane Reforming

Energy research Centre of the Netherlands (ECN), Sintef,

University of Dalian, Process Design Center (PDC), Chevron, National Technical University

of Athens (NTUA), BP

April 2006

36 months

Sorption Enhanced Water

Gas Shift, SEWGS

BP, Air Products (GB), ConocoPhillips, ECN, NTUA,

PDC, Chevron.

April 2006

36 months

Chemical Looping Reforming, CLR

(two concepts)/One

Step Decarbonisation,

OSD

Chalmers, Alstom, CSIC, TUV, NTUA, PDC, BP, IFP, Shell,

EniTecnologie (now Eni - only OSD), Sintef.

April 2006

36 months

HyGenSys

(Steam, Methane Reformer and Gas

Turbine)

IFP, Technip, Siemens, NTUA, PDC, BP, Chevron.

April 2006

36 months

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Figure 1. FCC process schemes

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Best Integrated Technology, BIT

This is a follow-on work of a CCP1 technology (Choi et al., 2005). BIT is based on the integration of typical post-combustion amine washing, enhanced by the use of novel solvents, flue-gas recycle, and heat integration in a new-built gas-fired combined cycle power generation utility.

The CCP1 version of BIT included two assumptions that needed confirmation: (1) exhaust gas recycle (EGR) for the combined-cycle power plant of up to 40-50% will increase the CO2

concentration in the fluegas from the usual 4 vol. % to 7-10 vol. %; and (2) Integrating the Heat Recovery Steam Generator (HRSG) with the solvent reboilers helps eliminate some reboiler shells from the capture plant and reduces net steam extraction to the capture plant. The objective of the CCP2 study was to confirm these assumptions and update the overall process design and economics.

The typical process scheme for application to a natural gas combined cycle (NGCC) is shown Figure 2.

Figure 2. BIT process flow diagram

Following a more in-depth analysis confirming the feasibility of up to 40% EGR, laboratory testing with actual EGR was carried out to better define the potential of the approach. The tests were performed on a prototype combustion rig with ~1% thermal load of a full 9FB machine (1/6 can). The experimental setup included two combustors, water quenching, refiring in second stage, piping and preheating. A micro-turbine combustor was used as the CO2 generator and operated at 200 psia and 65.5 oC (150o F). The CO2-rich gases were quenched and then cooled to below water dew point by using a heat exchanger. Thereafter, most water was extracted from the cooled exhaust gas while still at pressure and the remainder was then mixed in a secondary vessel with preheated fresh air.

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This oxidizer mixture is representative of the EGR levels expected, including major (CO2, O2, N2) as well as minor (NOx and CO) gas components. The oxidizer is fed to the combustor nozzle of interest and its performance is measured in baseline (fresh air as oxidizer) and EGR mode, and compared respectively. To mimic EGR, oxygen depleted gas was fed to the second stage at 160 psia. The setup is shown in Figure 3.

The tests have demonstrated EGR up to 35 % under relevant conditions for up to 30 hours and the feasibility of deploying EGR on Dry Low-NOx (DLN) turbine, confirming good performance of the DLN nozzle. Modifications of existing equipment might allow demonstration of 40% EGR.

Figure 3. BIT - Test rig assembly (GE)

The largest consumer of energy in the CO2 absorption process is the amine re-boiler, where heat is required to regenerate the solvent and re-lease the CO2 for further dehydration and compression. Traditionally, all of this steam is extracted from the steam turbine of the NGCC plant.

The BIT plant uses an “integrated reboil cycle”, where a portion of the stripper bottoms is pumped to the HRSG. The bottoms are heated with the exhaust gas in a set of reboiler tubes and subsequently returned to the amine unit. This reduces the duty of the kettle reboiler and hence enables the operation of the amine plant with a single kettle reboiler shell, which once again translates into capital cost savings.

This has reduced a two-step heat transfer process (gas to steam and steam to amine) to a one-step process (gas to amine), so that the heat transfer is made more efficient and the heat required to boil the amine solution can be extracted from gas at a lower temperature, leaving the hotter gas for steam generation purposes. HRSG surface area has been reduced to 50% for a 109FB machine.

Further cost-saving features identified from CCP1 include the introduction of a new, proprietary type of structured packing for the absorber column and a steam eductor which compresses the water vapour obtained from the flashing of the lean amine solution before returning it to the stripper column, reducing the total steam extraction demand and cutting the reboiler duty by up to 30%, compared to a standard design. For the present work, these process features are present in all of the CO2-capture plant designs, with or without EGR. This is done to represent an evolution of the post-combustion base case over the one selected in CCP1.

BIT efficiency in a natural gas fired power combined cycle is estimated to be about 50%.

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The BIT concept has also been shown to be feasible on an aeroderivative like LMS100 CC.

BIT Phase 2 was completed in summer 2008. It is deemed ready for a full scale can Dry Low-NOx

(DLN) combustion test. Other remaining areas that may require further study are turbine compressor corrosion risks due to accumulation of sulfur compounds and operability at part-load conditions.

Chemical Looping Combustion, CLC

A follow-on study of the CCP Phase 1 technology, Chemical Looping Combustion (CLC, Hurst and Miracca. 2005), is being carried out to better understand scale-up challenges. CLC is an approach to oxy-firing that is based on a solid carrier able to chemically adsorb oxygen from air (oxidation) and release it in the presence of a gaseous fuel (reduction) with immediate complete combustion. Central to the technology is a two-reactor system with continuous circulation of solids, as schematically shown in Figure. 4.

Figure 4. CLC process scheme

CCP2 is continuing the development of the technology from CCP1 in its application to natural gas fired boilers under the project name CLCGASPOWER. The objectives are to assess the chemical and mechanical durability of the carrier and scale-up from 10 kW to at least 100 kW unit.

Construction of the pilot unit was completed by December 2007, and the unit will operate till the end of the Project. Main achievements are summarized below:

• 33 different formulations of the oxygen carrier material have been tested; spray dried particles of NiO in combination with aluminium/magnesium oxides perform best but hot, dry impregnation of NiO on alumina is a good alternative.

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• Building of 120 kW pilot plant has been completed and more than 100 hours of operation have been obtained by June 2008.

• A computer simulation programme has been developed and will be used to simulate the results of the pilot unit. Testing/tuning based on results from the 120 kW pilot plant will be carried out before the completion of the project.

• Tests on impurities (H2S in fuel reactor / SO2 in air reactor) have been completed and showed that up to 100 ppm H2S does not impact the carrier.

Scale-up of oxygen carrier production (spray-drying) has been successful. Spray-dried particles produced in batches of 30 kg by the Belgian company VITO confirmed performances of the freeze granulated particles in CCP1. The CLCGASPOWER Project came to completion during summer 2008. The next step is a detailed feasibility study for a field pilot/demo unit.

Hydrogen Membrane Reformer, HMR

Development of Hydrogen Membrane Reforming (HMR) was initiated in CCP Phase 1 (Vigeland and Åsen, 2005) and further development is being explored in Phase 2. HMR is based on the development of novel ceramic membranes permeable to hydrogen, applicable to pre-combustion decarbonisation schemes for CO2 Capture.

Figure 5 shows an example of a HMR gas power cycle principle with two reactors, one for syngas (hydrogen, carbon monoxide and carbon dioxide) generation and one for hydrogen production. The first reactor combines steam reforming of methane to syngas and combustion of permeated hydrogen by air. The next reactor is used for separating hydrogen and CO2, generating carbon free fuel for power production. Reforming reactions take place at a pressure of 20 bars and temperature of 700-1000°C. Alternatively the second membrane reactor can be omitted and hydrogen produced by means of conventional CO-shift and CO2 separation technology. Generated N2/H2O gas can be used as sweep gas in the downstream membrane process or used as dilutent for hydrogen in the gas turbine for NOx control.

Figure 5. Example of a HMR gas power cycle.

One of the targets in CCP2 is to develop small membrane monoliths (diameter = 2 cm). This has been achieved, see Figure 6. The module is made of a ceramic monolith with 37 active channels (1.5 mm), 21 for reforming and 16 for sweep, and equipped with a manifold system for gas distribution at each end. This unit was tested under process conditions at 1000°C and 20 bara and methane conversion close to equilibrium combined with hydrogen flux were demonstrated. A pilot scale membrane monolith (7x7 cm) has also been fabricated.

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Figure 6. The small scale HMR membrane module made during the HMR CCP2 project.

Another objective of the HMR development in CCP2 was to update the HMR cost estimates based on new project results. Two factors have been central in this update:

1. The cost of membranes. The original HMR process had three membrane stages. New knowledge and insight into the design and production of monolith based membrane reactors since CCP1 resulted in a very significant cost increase of the membrane reactors. The second and third reactor steps have become very expensive due to the large membrane areas that will be required.

2. The CCP1 version of HMR showed an air extraction ratio of combustion air (> 60%) which is outside the vendors’ experience. It has been a target in CCP2 to develop HMR concepts using a more conventional gas turbine setup with air extraction ratios below 20%.

The most promising new scheme, with only one stage of membrane reforming combined with conventional CO-shift and CO2-removal techniques is shown in Figure 7. This concept has several advantages over the original three step process:

Membrane volume < 10% of the three step process Gas turbine air extraction is reduced from 60% to 11% (thus allowing conventional gas

turbines to be used) Almost pure hydrogen may be extracted from the process. Membrane reactor development cost is reduced as only the syngas reactor step needs to be

developed. Reduced complexity and risks in general.

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Figure 7. HMR Process scheme with 1-stage of membrane

The main disadvantages are:

Reduced efficiency by 3 % points. However, alternative CO2 removal techniques developed in parallel CCP projects, like Membrane Water Gas Shift (MWGS, see Section 2.4.1) and Sorption Enhanced Water Gas Shift (SEWGS, see Section 2.4.2), may improve efficiency.

Reduced CO2 capture. With one membrane stage and conventional CO2 removal 87 - 93% capture is feasible, compared to 95 – 98 % for three membrane stages. The higher CO2 capture ratio may also be achievable with two membranes stages and low temperature MWGS, a possibility that is being looked into.

At least one turbine vendor claims it is possible to modify existing gas turbines for air extraction up to about 55%. Thus the original HMR concept may still be feasible and it has therefore been re-estimated using a supplementary air compressor to supply additional compressed air.

The results of CCP2 concept evaluation of HMR show that the efficiencies in natural gas combined cycle are in the range 50 – 53%, with the version with amine wash and one membrane (HMR-2) having the lowest efficiency and the original concept with three membrane stages being the most efficient.

The project was completed summer 2008. The technology needs two more years of material testing before it is deemed ready for a pilot unit. The project has received funding from the Research Council of Norway under the CLIMIT Programme.

Technology developments with completion date in 2009

There are six technologies in this group. They are all part of the EU-funded programme CACHET, to which CCP2 gives a substantial contribution, focused on technologies deriving from CCP1. All of the CCP2 Partners are also Partners in the CACHET Project. All the projects in this group will continue into spring 2009. CACHET is focused on pre-combustion capture in Natural Gas

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Combined Cycle (NGCC) power stations. The performance of the technologies will be compared to a baseline, which is a conventional air-fired Auto Thermal Reforming (ATR) process combined with Methyldiethanolamine (MDEA) washing.

Membrane Water Gas Shift (MWGS)

Additional developments in membrane water gas shift have been accomplished in Phase 2 following the initial work in CCP Phase 1 (Klette et al, 2005). Hydrogen membranes with an ultra-thin Pd-layer on a porous support are utilized to remove the hydrogen from the syngas produced by reforming and water gas shift reactions, and to shift the equilibrium of these reactions in favour of the products. During CCP1 very thin palladium layers (< 5 m) supported on porous stainless steel were developed. Good performance of tubes a few centimetres long was demonstrated in the water gas shift environment. The objectives in CCP2 were to scale-up the membrane tubes and test them for flux, selectivity and durability.

The tubes have successfully been scaled-up. Membranes have been successfully produced at 50 cm length with palladium/silver using a two-step method in which the thin defect-free Pd-alloy film is prepared by sputtering deposition onto the ‘perfect surface’ of a silicon wafer. In a second step the membrane is removed from the wafer and transferred to a porous stainless steel support. The PdAg membranes have been applied in a water gas shift membrane reactor. Figure 8 shows a schematic of the MWGS process.

Figure 8. The MWGS process scheme. MEM-WGS= MEMbrane Water Gas Shift

Other achievements include:

A bench scale reactor module with hydrogen production roughly equivalent to 4 - 8 kW has been constructed and operated, based on the new tubes.

The sealing technology for application of the membranes at membrane reactor conditions is available.

Within the current uncertainty level the membranes measured are inside the thickness bracket of the target.

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Membrane selectivity is sufficient for the application, while additional investigation is needed to confirm permeability under syngas conditions.

Based on stability tests performed, membranes that are sufficiently stable to be used for tests in a bench scale reactor can be fabricated.

The concept design of both the test rig and the bench scale reactor has been finalized, Fig. 9. The rig will be the focus of activity till the conclusion of the project in 2009.

At this stage of development during the Project, the efficiency of a NGCC power station with MWGS capture is estimated to be about 6 percentage points higher than the precombustion baseline.

By the end of CCP2 the membrane module developed in CACHET should form the basis for a modular pilot unit in the 100 kW range in a non-integrated version of the technology (separate WGS reactors and membrane vessels). A feasible means for large scale membrane fabrication needs to be developed and demonstrated.

Figure 9. The MWGS test rig

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Sorption Enhanced Water Gas Shift, (SEWGS)

This is a continuation of a CCP1 technology (Allam et al, 2005). SEWGS operates on a syngas stream. It uses a solid adsorbent able to preferentially adsorb CO2 and thereafter applies pressure swing absorption (PSA) and water gas shift (WGS) within a single vessel to simultaneously convert CO/H2O to CO2/H2 and to capture CO2, see Figure 10. One of the advantages of SEWGS is that temperatures stay high throughout the system and the hydrogen fuel is produced hot. No energy is lost to cooling water or steam generation from the High Temperature Shift (HTS) forward reaction. Other advantages are process integration and more complete conversion of reactants. During CCP1, suitable adsorbents (modified hydrotalcites) were developed and tested in a single laboratory reactor alternating adsorption and desorption. The target of CCP2 is the construction and operation of a multi-reactor lab unit, simulating the commercial operating cycle.

Figure 10. The SEWGS process flow diagram

A multi-column test rig (6 columns) representing a complete continuous commercial cycle has been constructed, Figure 11. Columns are the same height as future commercial columns (6 meters), so that scale-up should be straightforward. Commissioning started in December 2007 and multi-column operational experience will be obtained through the remaining period of the CACHET programme.

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Figure 11. The SEWGS Multicolumn test unit: Isometric Drawing and Front Picture

In addition to the multi-column rig the achievements during CCP2 include

Intensive experimentation using the single column test unit has demonstrated that the sorbent (hydrotalcite, HTC) is stable and can be repeatedly regenerated.

Acquired performance data for model simulation from extended operations of a single column unit

Model tested numerous cycle concepts and developed a “light” version of the simulation tool to accelerate design

Heat exchanger network improvements

Design optimization

o Reduced steam to carbon ratio

o Reduced rinse and purge steam

o CO2 rinse

The cycle optimizations and improvements of the simulation tool will continue during the completion of CACHET. With these improvements it is likely that the efficiency of SEWGS will be 4 – 5 % above the precombustion baseline. If sorbent durability and mechanical resistance are proven, the technology may be ready for pilot testing at the completion of CCP2/Cachet. The project will finish in early 2009.

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Chemical Looping Reforming, CLR, and One Step Decarbonisation, OSD

The concept of Chemical Looping Combustion described earlier is also applicable to production of hydrogen using a design called Chemical Looping Reforming (CLR), provided that oxygen carrier materials with tailored properties are developed. These technologies are new to CCP2. Three concepts are studied in parallel:

(i) CLR(a) in which the solid oxygen carrier must be able to partially oxidize methane to synthesis gas, rather than bringing it to complete oxidation, Figure 12A.

(ii) CLR(s) in which the solid oxygen carrier must be able to burn a fuel. The heat generated by the combustion is used to run the steam reforming reaction, in a gas heated reforming type of process, Figure 12B.

(iii) OSD, in which the solid carrier must be able to capture oxygen from steam, with direct production of hydrogen. Oxygen is then removed in a separate vessel through complete combustion, generating a typical oxyfuel effluent (CO2 and H2O), Figure 13.

The objectives of the CCP2 activities are:

a. Optimization of solid carrier based on activity and cost perspectives.

b. Optimization of reactor and process scheme design through simulation and cold flow studies.

Chemical Looping Reforming, CLR

As true for CLC, the most promising solid carrier for CLR is based on nickel oxide (NiO). Detailed testing in continuous fluidized beds using both atmospheric and pressurized conditions has been performed to establish the potential for char formation and to determine kinetics, selectivity, and mechanical performance.

Status of CLR can be summarized as follows:

NiO based materials for chemical looping applications have been tested for more than 160 hours in a circulating fluidized bed (CFB) reactor

A reactor model for CLR (parallel with CLC model) is ready

Building of a pilot plant has been completed and no severe problems encountered. This is the same unit as for CLC but when applied to CLR(a) it may go up to 200 kW due to different stoichiometry (CH4 + 2 O2 in CLC while CH4 + 1/2 O2 in CLR).

At this stage of the Project, the efficiency of a NGCC power station based on the CLR concept is estimated to be about 4 (CLR(a)) to 7 (CLR(s)) percentage points higher than the precombustion baseline.

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A) CLR(a)

B) CLR(s)

Figure 12. The two versions of CLR. Autothermal reforming (A) and heat supplier to steam reforming (B).

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One Step Decarbonisation, OSD

A preliminary testing activity under pressure at lab scale has been carried out, making use of a semi-batch Fluid Bed Reactor (FBR). The aim was to investigate the physical and chemical performances of the OSD process using fuel and the steam reactors up to 10 barg with the standard oxygen carrier materials based on iron oxide (FexOy) materials as well as with more promising new materials. Good test results have been achieved in terms of product purity (higher than 96%), reactants conversion and stability of the carrier.

Figure 13. OSD process scheme

Both CLR(a) and OSD concepts show improved economics by high pressure operation (20-30 bars). No commercial Circulating Fluid Bed (CFB) processes are, however, operating at pressure higher than 2-3 bars. Development of a pressurized CFB system should be regarded as a high risk and long term challenge.

At this stage of development during the Project, the efficiency of a NGCC power station based on the high pressure (25 bars) OSD concept is estimated to be about 2 percentage points higher than the baseline.

Membrane Reforming

This project is closely related to MWGS. Reforming normally takes place at ~900 oC, but in this project the target is to make a membrane reformer (MRef) that can operate at 550 - 600 oC. This may, in principle, allow implementation of membranes directly inside the reforming furnace, generating a membrane reforming environment. The membranes tested show promising features but a technically sound implementation for an industrial application still needs to be developed.

50 cm long pure Pd membranes with 220 cm2 separation area are now being produced on a low cost ceramic support and capped with new high temperature/high pressure sealings, which allow operation up to 550 °C and 38 bars, see Figure 14. These membranes will be applied in water gas shift and steam reforming membrane reactors.

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Figure 14. Pd membranes from DICP with ECN's high pressure, high temperature sealings

At this stage of development during the Project, the efficiency of a NGCC power station based on the high pressure (45 bars) the membrane reforming concept is estimated to be about 5 to 7 percentage points higher than the precombustion baseline. Further work is needed to confirm this estimate.

HyGenSys

HyGenSys is a technology for steam reforming of hydrocarbons to syngas, based on a heat integration of gas turbine and exchanger reactor rather than the typical externally fired furnace. The concept is applied to a two-shaft turbine integrated with the reformer. In order to reduce CO2 emissions, hydrogen fuel is used in three combustion chambers in the two-shaft turbine cycle. The Process scheme is shown in Figure 15.

The objectives of the study are further reactor development through simulation and mechanical design and development of the whole co-generation process scheme for the technology.

Work has focused on the conceptual design of the reformer tubular reactor. The concept will rely on existing available catalyst pellets. There are possible loading and unloading issues related to this. The loading and unloading questions require tests in a dedicated cold mock-up, which are under way.

At this stage of development during the Project, the efficiency of a NGCC power station based on the high pressure (25 bars) the HygenSys concept is estimated to be about 3 percentage points higher than the precombustion baseline.

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Figure 15. HyGenSys process scheme

Cost estimation and ranking

The cost estimation and economic evaluations are ongoing but will not be completed until 2009. As in Phase 1 (Melien, 2005, in Thomas (ed.), 2005) the different technologies will be applied to one or more of four scenarios and cost estimated. The CCP2 scenarios, partly different from those applied in CCP1, are:

New Built 400MW Natural Gas Combined Cycle (NGCC) power station (North West Europe)

Retrofit of the boiler-heaters system in a European refinery.

Petcoke gasification (Canada)

Retrofit of a Fluid Catalytic Cracking unit in a Brazilian refinery.

The individual technology providers will prepare process design and description, flow diagrams, process equipment lists and CAPEX and OPEX estimates for the various capture technologies. To enable a fair and consistent technology comparison, the supplied range of performance and cost estimates will be integrated and completed as part of the relevant application scenarios. External cost estimator consultants will check and align technical scopes, process flows, equipment pricing, utility supplies/ pricing, capex/opex trade-offs, and currency/ inflation-assumptions, in order to establish a final and aligned set of CAPEX and OPEX-estimates The final cost estimates will then be input to a Common Economic Model (CEM, described in Melien, 2005) for comparative calculation of cost of carbon capture across technologies in terms per ton of CO2 (EUR/ton, USD/ton captured/ avoided cost) and incremental product/ electricity cost (EUR/MWh, USD/MWh).

When technology evaluations and cost estimates are completed, the technologies will be ranked according to the following set of criteria:

Absolute and relative CO2 and product/ electricity costs (EUR/USD per tCO2 or per MWh, as well as % reduction relative to Baseline costs)

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Potential impact on emissions of the CCP partners

Probability of overall technical and economic success

Retrofit capability

Expected time to mature technology for demo and full scale application

Fuel flexibility

Expected cost of demonstration unit.

Summary and preliminary conclusions capture

By mid-2008 CCP2 has completed four out of ten technology development contracts. Main objectives and targets have been achieved for the completed technology studies and developments. The technology projects with completion in early 2009 are on track. Though the CCP2 selected pre-combustion technologies as high potential options for future deployment of CO2 Capture and Storage (CCS), evaluations available at the moment of preparing this paper seem to point out that oxy-firing and post-combustion technologies have similar potential in terms of energy efficiency and capture cost and higher potential for early deployment of demo units.

STORAGE, MONITORING AND VERIFICATION (SMV)

Objectives The principal objective of the CCP2 SMV programme is to address remaining technical issues in geologic CO2 storage assurance. This will be accomplished by developing improved understanding of the integrity of geologic and engineered systems, storage site assessment protocol, optimization of operations, cost effective monitoring and risk assessment. The findings of these studies and their integration in emerging site certification and risk assessment protocols will help qualify assumptions about the reliability of CO2 storage.

The CCP2 SMV programme (2005-2009) continues to develop promising storage technologies identified in the CCP1 SMV programme (2001-2004, Benson (ed.) 2005) while addressing emerging technical gaps and high impact opportunities in carbon dioxide (CO2) storage assurance.

The CCP2 storage technology portfolio

The CCP2 Storage Monitoring and Verification (SMV) portfolio consists of seven technologies. Table 2 lists the technologies together with the involved R&D institutions and co-funding sources. The portfolio consists of an integrated platform for site certification for CO2 permitting, operation and decommissioning; well integrity logging, sampling, modelling, history matching and simulation of post-closure sealing capability over extended time; testing the capability of standard logging tool to detect a sharp interface between free-phase CO2 and brine; coupling of geochemical and geomechanical models; simulation of safe and effective operational constraints and monitoring for CO2 injection in coal beds; and a field test of airborne remote sensing technologies.

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Table 2. List of major SMV projects for phase II of CCP. Underscore indicates the leading institutions

Project Name Involved

institutions

Starting

Date

Duration

Certification Framework

Lawrence Berkeley National Laboratory (LBNL), Univ. Texas

April 2006

33 months

Well Integrity Field Study

Schlumberger, Los Alamos national Laboratory (LANL)

April 2006

33 months

Well-Based in situ Detection

Schlumberger April 2006

18 months

Coupled Geochemical-Geomechanical Simulation

Univ. Bergen and University of Catalonia, Spain

April 2006

33 months

Operability of ECBM Sproule Associates, April 2006

33 months

Non-seismic monitoring of ECBM

LBNL June 2005

43 months

Direct Detection of CO2 and Methane

University of California Santa Cruz (UCSC)

June 2005

43 months

Certification Framework The overall objective of the Certification Framework (CF) Project is to develop a simple, transparent and accepted framework for analyzing and evaluating leakage risk of geologic storage of CO2. The framework is intended for certifying operation and decommissioning of Geological CO2 Storage (GCS) systems. It will provide a single, streamlined platform for integrating site assessment, field development/operation and risk assessment of proposed CO2 storage programmes for use in project permitting, operating and decommissioning. The Certification Framework is developed in conjunction with an independent stakeholder advisory board.

The CF combines site data, simulations of plume migration, estimates of probability of intersection of the CO2 plume with conductive wells and faults, and model calculations of fluxes and concentrations in compartments to calculate CO2 leakage risk. The theory and philosophy of the certification framework includes the following generalized elements:

1) Effective trapping requirement – the CO2 leakage risk over the period of review is below specified threshold flux levels (agreed upon by the proponent and regulator).

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2) CO2 Leakage Risk (CLR) – probability that storage volume of CO2 (source) will migrate from the target reservoir (source) to impact a receptor compartment via preferential pathways or conduits (faults / fractures and wells). Safety and effectiveness of GCS are achieved if injected CO2 does not impact underground sources of drinking water (USDW), nor migrate to the shallow subsurface and seep out into the atmosphere.

Simplicity in the CF is achieved by assuming that the main potential leakage pathways at carefully chosen GCS sites are wells and faults. Further, it is assumed that all of the vulnerable entities reside within a handful of compartments, and that impacts to compartments can be represented by proxy CO2 fluxes and concentrations affecting the compartments. These aspects of the CF are illustrated in Figure 16. Transparency is achieved by making use of a precise terminology and a logical work flow (Figure 17). The CF allows screening of sites through use of a pre-computed catalogue of simulation results that a non-specialist user can query to estimate plume locations and pressures. This feature also enables interactive use of the CF to examine sensitivities of leakage risk to operating parameters or site properties. For site-specific simulations, the Certification Framework can use the results of commercial simulations developed with detailed geologic data.

As can be seen from Figure 17 the CF is comprised of several parts, including : 1) External inputs – an organizing scheme to build a geological 3D model using available data (e.g., stratigraphic / structural cross sections, well logs, etc.); 2) Reservoir Simulator – Uses the geospatial model and reservoir characteristics (e.g., porosity, permeability) and operational parameters (injection location, rate) for interpolation with respect to a catalogue of reservoir simulations; 3) Calculations – Numerical assessment of risk (probability x impact) for migration of CO2 from the source (injected reservoir) to compartments via conduits (wells and faults).

Inputs to the CF are properties and definitions of the injection system. The output of the CF is CO2 leakage risk (CLR) values for individual compartment / conduit combination and a composite for the system. The CF is probabilistic in supporting the existence of flow pathways but “deterministic” in flow along a pathway. The CF project is structured to provide a basic, streamlined platform for input of geologic data (static model), reservoir simulation across a broad range of reservoir properties and operational conditions and a risk assessment protocol.

The Certification Framework team is also developing specialized well-flow models and atmospheric dispersion visualization capabilities. To date, two case studies have been conducted using the CF approach: (1) a hypothetical large-scale (24 million tonnes / 30 yr) GCS site in the Texas Gulf Coast; and (2) a one-million tonnes / 4 years pilot project at “Kimberlina”, California, that is part of the Phase III of the U.S. DOE Regional (WestCarb) Carbon Sequestration Partnership Programme.

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Figure 16. (a) Generic geologic cross section of a potential GCS site showing reservoir and sealing formations, faults, wells, hydrocarbon resources, USDW, and the near-surface and surface environments. (b) Generic cross section with CO2 source and Hydrocarbon and Mineral Resources (HMR), Near-Surface Environment (NSE), Health and Safety (HS), and Emission Credits and Atmosphere (ECA) compartments overlaid.

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Figure 17. Certification Framework: Workflow scheme including reservoir simulation using rock and fluid properties, statistical treatment of CO2 migration through conduits and into compartments, leakage model scenarios with impact and final calculation of achieving CO2 leakage risk (CLR) threshold

The Texas site is in an area of historical hydrocarbon production and has a high density of deep exploration wells resulting in a 100% certainty that at least one abandoned well will be intersected by the CO2 plume. The purpose of the case study was to apply the elements of the CF process to a simple setting for which significant geological data are available. The injection rate was constant at 0.8 Mt CO2/yr over 30 years. The simulations indicated that 10% of the injected CO2 remained mobile after 100 years. The rest was immobilized by residual phase and solubility trapping. Indications are that:

The CO2 leakage fluxes are small and unlikely to make a measurable impact on a large aquifer and therefore not on drinking water, although the CF does not evaluate these impacts directly.

In the near-surface environment, the highest predicted well flux would disperse if emitted directly to the atmosphere, but could potentially impact the soil zone impacting local plants if discharged in the shallow subsurface.

The CO2 Leakage Risk (CLR) is highest for local impact to the environment, an impact that could be mitigated as soon as effects were observed.

The Kimberlina study is under review and additional, potential case studies have been identified. The project will finish in 2008 but improvements have been suggested, e.g. by incorporating more sophisticated elements such as geomechanical models.

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Well Integrity Field Study This project is a well “autopsy” and “prognosis” study with the objectives to provide quantitative information on the extent of alteration in wells that have been exposed to CO2; to history match the observed alteration, forward project the long-term barrier performance; and to develop appropriate engineering solutions to improve well integrity.

The “Well Integrity Field Study” addresses what is a significant concern in geologic storage - the long-term sealing capacity of wells in a CO2-rich environment. The study outcome will gauge the type and levels of risk posed by failure of well components and identify preventative and remedial engineering solutions.

Two surveys (2006 and 2007) in a natural CO2 production facility in Colorado have produced better than expected logging / sampling results (Figure 18). The well was completed in a clastic reservoir in 1976 and cemented with a 50% “Pozmix” cement blend (50% fly ash and 50% Portland cement). It produced CO2 from 1986 until it was suspended in 2006 due to production decline. A comprehensive set of well logs (caliper, cement bond, ultrasonic, gas saturation spectroscopy) acquired during the first access indicated that the casing was in good condition and that good cement bonding has been maintained. Intact cement cores through casing were recovered, one with attached country (cap) rock. Fluid sampling was less successful, with only one possibly “representative sample” obtained. In the second access, additional samples further up in the caprock were sampled and a pulse test (in situ permeability) was conducted. Some conclusions from this 30 years old wellbore barrier are:

The wellbore remains an effective hydraulic seal to CO2

Conventional cement-fly ash systems can inhibit CO2 migration even after carbonation of the cement, i.e. carbonated cement remains an adequate seal

Permeability and capillary resistance of the cement are at levels sufficient to act as barriers to CO2 migration

CO2 migration above caprock did occur

Cement interfaces appear to be the preferential CO2 migration path

Current technologies effectively evaluate the barrier system

A Petrobras CO2 EOR production well (clastic reservoir and shale caprock) at Buracica Field, Brazil has been investigated. Results from the sampling will become available later in 2008. Access to a third well may take place in 2008.

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Figure 18. Well Integrity Field Study: Solid samples acquired in the first well accessed in October 2006. Cement (and in one case cap rock shale) are physically intact.

Well-Based In Situ Detection

This project was completed in 2007. Its objective was to develop, construct, and bench test a new well design that allows accumulation and detection of CO2 leaking from wells and surrounding rock.

The primary activity was to test the ability of a pulsed neutron and Reservoir Saturation Tool (RST) tool in detecting CO2 in the formation outside the casing under various fluid types and CO2 pressures. RST offers two different measurement modes that have potential in detecting the presence of CO2 in the formation. Inelastic-Capture (IC) mode measurements provide the relative amount of carbon (yield) and the ratio of carbon to oxygen present in the wellbore and surrounding formation. Sigma mode provides measurements of the capture cross-sections of the formation and borehole along with count rate ratios that help determine the type of fluids present.

A bench scale pressurized chamber, which could be loaded with sediments / water, charged with CO2 and tested for RST tool response, was constructed for the study (Figure 19). The study results (based on a sand loaded tank with pore space filled with 2/3 brine and 1/3 CO2) indicated that the RST contrast readings (versus pre-CO2 charge) are too small using IC mode (relative carbon yield and carbon/oxygen ratios), but sufficient using sigma mode (detection of decay response to neutron pulses, specific for fluid types) to detect a free-phase CO2/brine interface.

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Figure 19. Test rig for the well-based in situ detection experiments

No further CCP2 studies are planned although it is noted that a pressurized vessel specially constructed for this study is available for further work using different salinities, CO2 saturations, other phases, etc.

Coupled Geochemical-Geomechanical Simulation Coupling of models and simulations is a recognized need for CO2 storage site assessment, establishing operational constraints and defining monitoring needs. At present, flow and geochemical simulation software is well-developed but the net consequences of injection-related pressure fields (geomechanics) and mineralogical transformations (geochemistry) on reservoir and caprock integrity are poorly understood.

The Coupled Geochemical-Geomechanical Simulation project was developed to assess interactions among physio-chemical phenomena during and after CO2 injection in saline formations that can affect containment. Of principal concern is the rapid dissolution of minerals such as calcium and magnesium carbonates which, over time, leads to their erosion and loss of rock mechanical integrity. The coupled simulation will undergo parametric studies using data from two suitable fields.

The simulator was developed from multiple, existing standalone programmes, with important code modifications and integrated on a common platform (Figure 20). CodeBright (e.g. Olivella et al., 1994, 1996 and 1997) calculates thermohydraulic evolution (changes in salinity and water movement over time) and geomechanical response in the reservoir. The code solves implicitly the differential equations describing fluid flow, heat flow and geomechanics.. One shortcoming of the code has been its limitation to ideal gas assumption for the gas phase.

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Figure 20. Geochemical-Geomechanical Simulation: Integration of functional codes used to analyze input geological and fluid data to assess the impact of CO2 injection on rock stability

In CCP2 the code has been completely rewritten in all parts that involve the density of the gas phase, and gradients of this with respect to the variables in the flow equations, as well as gas/liquid phase transitions. This has been particularly complex since the reactive transport section has a higher resolution in time than the CodeBright part, which also required substantial rewriting of the algorithms used in the numerical solutions. So far the project team has accomplished the following:

The geomechanical reactive transport simulator RetrasoCodeBright has been extended into high pressures relevant for reservoir storage of CO2.

Corrections for non-ideal gas has been implemented based upon the Soave-Redlich-Kwong (SRK) equation of state but can easily be replaced by similar results from any equation of state since the necessary data are interpolated from calculated tables of compressibility factors and fugacities as function of temperature and pressure.

the convergence of the Newton-Raphson iterative solution has been improved through implementation of an algorithm that minimizes the total square residual for the Galerkin method after each Newton-Raphson step.

The corrected model version has been applied to a simple test case with high buffering effect, see Figure 21. The top and bottom zones have the same geological structure. Each is a 1000m x 100m rectangular section consisting of 3% calcite and 97% quartz. Porosity in these two zones is 35%. The middle zone is 1000m x 800m rectangular. This section is subject to sensitivity analysis with variations of Calcite between 3% and 100% and the rest quartz. The porosity of this section is varied between 0.1 and 0.3.

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Figure 21. Geometry of the 2D reservoir and the CO2 injecting point test case

For this particular test case the erosion is very limited and the corresponding geomechanical implications of the CO2 injection estimated to be correspondingly small, even for time periods up to 100 years. The simulation results have shown that under the premise of same percentage of calcite, the sedimentary reservoir which has larger porosity has the lower pH value. If the porosity in the vicinity is the same, pH value is higher where there is more calcite, which is due to the buffering effects of calcite dissolution.

Additional parametric studies, aimed at assessing the affects of mineralogy on simulation runs, are now in progress. Prospective case studies are under review for completion in 2008 or thereafter. These include fields in Brazil, Illinois and Colorado.

Operability and Monitoring of Enhanced Coal Bed Methane, ECBM This project is co-funded by the CO2 Capture Project (CCP) and the U.S. Department of Energy (DOE). The project aims to advance carbon dioxide (CO2) sequestration monitoring, verification and risk assessment technology to include coal beds. It consists of the three following tasks:

• Simulation of CBM and CO2 ECBM recovery processes and operating practices that could lead to leakage of methane or CO2

• Modelling the resolution of inexpensive non-seismic geophysical monitoring tools to detect gas behaviour within coal seams and generically in the rock overburden

• Direct, remote detection of methane and CO2 leakage from a coal (mining, EBM or CO2 ECBM) or other geologic storage

The geologic model and simulations developed in the first task is necessary to construct a rock geophysical model to conduct the second task. The Deerlick Creek Field in the Black Warrior Basin, Alabama, USA, which will be the site of a small CO2 injection pilot in 2008, was selected as a case study. The work flow for the two first tasks is shown in Figure 22.

TOP

MIDDLE

BOTTOM

CO2

injectionpoint

100 m

100 m

1000 m

y

x0

TOP

MIDDLE

BOTTOM

CO2

injectionpoint

100 m

100 m

1000 m

TOP

MIDDLE

BOTTOM

CO2

injectionpoint

100 m

100 m

1000 m

y

x0

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Figure 22. ECBM Geophysical Monitoring: Workflow used to assess the feasibility of CO2 monitoring in coal using geophysical techniques

Coalbed Methane Simulation

The objectives of this task are to establish safe and effective operating parameters for CO2 injection and methane (CH4) production processes in deep, unmineable coals.

The model of the Deerlick Creek Field consists of 27 layers including 14 coal seams in the three major groups of coal beds found in the field. The model includes thirteen intervening shale layers and nine wells. In order to enable modelling of leakage of CO2 from the coal seams to upper horizons and the surface, a model of the entire overburden has also been developed.

Gas and water production have been successfully history matched by adjusting the fracture permeability and fracture porosity. Short term and long term injection of CO2 into three coal seams have been successfully simulated.

Longer term injection of CO2 into the three coal zones was also simulated. A number of injection scenarios were studied including:

• a base case with no CO2 injection • continuous CO2 injection for 10 years with continuous operation of production wells

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• continuous CO2 injection for 10 years with production wells shut-in after CO2 breakthrough

• continuous CO2 injection for 13 years, production wells shut-in, CO2 injection continued for an additional 20 years

• continuous CO2 injection for 13 years, production wells shut-in, CO2 injection continued for an additional 16 years at a higher injection rate

Simulation results showed CO2 sequestration amounts that varied by a factor of about five between the scenarios but almost similar volumes of methane produced.

Non-seismic Geophysical Monitoring Techniques

The objective of this task is to develop cost effective monitoring technologies to assess CO2 flood performance and detect low seepage rates. Simulation studies conducted in the task described in 3.7.1 of CO2 injection into coal beds in the Deerlick Creek pilot area were used to develop geophysical models to simulate gravity and EM responses from coal beds containing CO2 and to predict the utility of these non-seismic detection methods for monitoring the presence and migration of CO2 in the geologic setting. Laboratory measurements, carried out independently from this project, of electrical resistivity and seismic velocity as a function of CO2 saturation on a coal core sample were used as a link between the coal bed CO2 injection flow simulation results described in 3.7.1 and the geophysical models.

The sensitivity studies showed that while the response to the 300 tons of CO2 injected into a single layer would not produce measurable surface response for either gravity or EM, the response due to 1,000 tons of CO2 injected into three layers would produce measurable surface signal for both techniques. A density model of CO2 plume in coal beds is shown in Figure 23. The inversion of gravity data recovers the lateral extent and density contrast accurately from noise free data (Figure 24). The inversion of data with random noise (25% of the peak) results in the correct location of the CO2 plume; however, the density contrast cannot be resolved. A resistivity model with and without CO2 present is shown in Figure 25a, while the amplitude and phase response is shown in Figure 25b. A normal Move-Out (NMO) corrected Common Depth Point (CDP) stack section of the difference between the responses with and without the CO2 plume is shown in Figure 26.

In summary, simulation results indicate that CO2 injected into a coal seam should be detectable using gravity or EM non-seismic detection methods. Even the small volumes planned for a field test should be detectable.

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Figure 23. Density model in (a) plane view, (b) in section view.

Figure 24. Gravity inversion

Figure 25. (a) Resistivity log with and without CO2, (b) amplitude and phase response to the model

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Figure 26. NMO corrected CDP stack section

Remote, Direct Detection of CO2 and Methane

The objective of this task is to evaluate aerial hyperspectral monitoring as a means of directly detecting CO2 and CH4 leakage over large areas, eliminating the need for extensive ground based monitoring infrastructure and thereby providing significantly lower operational costs.

The work builds on results from CCP1, where Visible-Near InfraRed (VNIR) hyperspectral imagery was used to detect gas emissions and their environmental proxies (Pickles et al., 2005). In this phase, the MASTER (MODIS/ASTER Airborne Simulator) instrument, an airborne multi-spectral imager, was selected to map simulated CO2 and CH4 leaks within the boundaries of an active oil field. The primary field area is 35 miles north of Casper, Wyoming, in the Rocky Mountain Oil Field Testing Center (RMOTC), Naval Petroleum Reserve #3, Teapot Dome Oil Field. Data from this field test were studied and compared to data from other previously flown MASTER sites (Kilauea, HI; Mount Saint Helens, WA; and Mammoth Mountain, CA) as well as other imaging and spectroscopic instruments such as the HyMap airborne hyperspectral imager and the ASD FieldSpec Pro portable spectrometer. The previously flown MASTER imaging sites were included because each of the three sites has natural CO2 and/or CH4 leaks that could be used to improve larger scale methods of gas detection prior to the field data acquisition at RMOTC.

Seven experimental leak sites were used in this experiment, laid out to simulate leaks from a pipeline. Four sites were used as sources of methane/natural gas, and three were used as sources of CO2.

Figure 27 shows examples of three experimental CO2 leaks as seen at three different wavelengths from the visible to the thermal infrared. There are no clear indications of a CO2 plume from browsing the images, nor were there any consistent differences that could be attributed solely to CO2 absorption by the gas plume.

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Figure 27. Three experimental CO2 leak sites visualized at three different wavelengths from the visible (Band 01, 0.45µm) to the thermal infrared (band 03, 8.16µm). Leaks rate were 8 m3/h (left), 23 m3/h (right) and 142 m3/h (centre).Red arrows indicate the approximate locations of the leaks. Scale and North (shown by white text and arrow in centre lower image) is the same for all images.

The conclusion of the study is that it appears likely that the MASTER instrument could detect large ground leaks of CH4 with its present configuration. However, the MASTER instrument could probably not reliably detect CO2 from ground based leaks.

Summary and Conclusions SMV

By mid-term 2008 CCP2 has completed one out of seven SMV projects. The “Certification Framework” project has progressed from concept to development of a prototype application incorporating site characterization data, reservoir simulation interpolations and risk calculations and has been applied to a test case. The “Wellbore Integrity Field Study” work programme has acquired data from CO2-exposed wells and is increasing the database of information available for assessing the impact of CO2 on well materials, information that will be critical to predicting the fate of well materials over extended time and to development of well design recommendations and intervention solutions. A “Geochemical-Geomechanical Coupled Simulation” project has developed an integrated application that is ready for parametric testing and eventual field studies to assess the effect of CO2 injection on reservoir and cap rock integrity. A study designed to test the detection

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threshold of resistivity logging using a pressurized vessel charged with water, sediments and CO2 is complete. Projects undertaken by CCP2 aimed at addressing risks associated with injecting CO2 into unmineable coal beds have evaluated novel geophysical and remote sensing monitoring techniques and conducted simulation studies designed to identify CO2 storage and CH4 production safe operational limits.

POLICY AND INCENTIVES

Policy matters are key to the successful deployment of CCS technology. To this end, the CO2 Capture Project organized a Policies and Incentives Team (P&I Team) in 2002 to begin studying the state of policies, regulations, incentives, and potential barriers around the world. The P&I Team had the primary mission to provide information and advice to the CCP partners on these issues and any other external developments that may impact or benefit the technology programme being developed by the CO2 Capture Project. More specifically, the objectives of the P&I part of the programme are:

Update survey of existing policies, regulations, and incentives that impact or benefit CO2 capture, injection and storage in geologic formations

Continue network monitoring function and share information about proposed regulations, policies, and incentives that can affect CCS

Identify potential opportunities to inform the debate on CCS Participate in international forums to discuss the formulations of policies and incentives in

CCS technology Comment on significant proposed policies and incentives in CCS technology – developing

key policy related messages in support of creating favourable conditions for technology and commercial development

Share information about proposed regulations, policies, and incentives that can affect CCS and identify potential opportunities to inform the debate on CCS

In CCP1 the team completed two key tasks (Lee et al., 2005):

A comprehensive survey of existing policies, regulations, and incentives that impact or benefit CO2capture, injection and storage in geologic formations.

Gap analysis necessary to formulate the regulatory and policy framework that will show how to get from “where we are” to “where we want to be” in deploying the technology.

In CCP2 the P&I Team has been focused on a pipeline financing model. For carbon dioxide capture and geologic storage to be deployed commercially and in a widespread manner will require well thought out approaches for transporting the CO2 in a pipeline system from the capture facility to the injection site. In cooperation with Environmental Resources Management (ERM) the P&I Team completed a study that evaluated the benefits and risks of two approaches to developing CO2 pipeline systems (Chrysostomidis et al., 2008). The two basic approaches were:

1. A point-to-point basis, which matches a specific source to a specific storage location; or

2. The development of pipeline networks, including backbone pipeline systems, which allow for common carriage of CO2 from multiple sources to multiple sinks.

While point-to-point pipelines may be readily funded on a project-by-project basis by individual developers, there may be a need for public policy to encourage the development of optimized networks. An optimized network could offer the potential to significantly reduce the per unit costs

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of transportation and reduce the barriers to entry when compared to point to point systems. Furthermore, optimized networks can help to broaden participation and deepen deployment of CCS.

Establishing a widespread CO2 transportation infrastructure will require strategic long-term planning, adopting a paradigm that takes into account the potential magnitude of future deployment scenarios for CCS, up to a scale of infrastructure that could be comparable to the scale of oil & gas infrastructure.

The included issues of financing the development of a hypothetical CO2 transportation pipeline infrastructure. These issues include debt and equity structure, loan guarantees, government bonds, and the role of public-private partnerships.

ACKNOWLEDGEMENTS

The authors wish to thank representatives of all Technology Providers for their cooperation during the preparation of this summary article and for their willingness to contribute valuable comments and good illustrations. The CCP2 partners are BP, Chevron, ConocoPhillips, ENI, Petrobras, Shell, StatoilHydro and Suncor, with EPRI and Repsol as associate members. Additional funding is provided by the European Union, the Research Council of Norway and the US Department of Energy .

REFERENCES

Benson, S.M., ed., 2005, Carbon Dioxide Capture for Storage in Deep Geologic Formations - Results from the CO2 Capture Project, Vol. 2: Geologic Storage of Carbon Dioxide with Monitoring and Verification, Elsevier Publishing, UK. 654 pp.

Allam, R.J., Chiang, R., Hufton, J.R., Middleton, P., Weist, E.L., White, V., 2005. Development of the Sorption Enhanced Water Gas Shift Process, in: Thomas, D., (ed), 2005. Carbon Dioxide Capture for Storage in Deep Geologic Formations - Results from the CO2 Capture Project, Vol. 1: Capture and Separation of Carbon Dioxide from Combustion Sources, Elsevier Publishing, UK.

Choi, G.N., Chu, R., Degen, B., Wen, H., Richen, P.L., Chinn, D., 2005. CO2 Removal from Power Plant Flue Gas – Cost Efficient Design and Integration Study, in:Thomas, D., (ed), 2005. Carbon Dioxide Capture for Storage in Deep Geologic Formations - Results from the CO2 Capture Project, Vol. 1: Capture and Separation of Carbon Dioxide from Combustion Sources, Elsevier Publishing, UK.

Chrysostomidis, I., Zakkor, P., Bohm, M., Beynon, E., Filipo, R.d., Lee, A., 2009. Assessing Issues of Financing a CO2 Transportation Pipeline Infrastructure. To be presented at GHGT9, Washington DC, 17-20 November, 2008.

Hurst, P. and Miracca, I., 2005. Chemical Looping Combustion (CLC) Oxyfuel Technology Summary, in: Thomas, D., (ed), 2005. Carbon Dioxide Capture for Storage in Deep Geologic Formations - Results from the CO2 Capture Project, Vol. 1: Capture and Separation of Carbon Dioxide from Combustion Sources, Elsevier Publishing, UK.

Klette, H., Raeder, H., Larring, Y., Bredesen, R., 2005. GRACE: Development of Supported Palladium Alloy Membranes, in:Thomas, D., (ed), 2005. Carbon Dioxide Capture for Storage in Deep Geologic Formations - Results from the CO2 Capture Project, Vol. 1: Capture and Separation of Carbon Dioxide from Combustion Sources, Elsevier Publishing, UK.

Lee,A., Christensen, D., Cappelen, F., Hartog, J., Thompson, A., Johns, G., Senior, B., Akhurst, M., 2005. Policies and Inventives Development in CO2 Capture and Storage Technology: A Focused

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Survey by the CO2 Capture Project, in:Thomas, D., (ed), 2005. Carbon Dioxide Capture for Storage in Deep Geologic Formations - Results from the CO2 Capture Project, Vol. 1: Capture and Separation of Carbon Dioxide from Combustion Sources, Elsevier Publishing, UK.

Melien, T., 2005. Economic and Cost Analysis for CO2 Capture Costs in the CO2 Capture Project Scenarios, in:Thomas, D., (ed), 2005. Carbon Dioxide Capture for Storage in Deep Geologic Formations - Results from the CO2 Capture Project, Vol. 1: Capture and Separation of Carbon Dioxide from Combustion Sources, Elsevier Publishing, UK

Olivella, S., J. Carrera, A. Gens, E.E. Alonso, 1994. Non-isothermal Multiphase Flow of Brine and Gas through Saline Media. Transport in Porous Media, 15, pp. 271-293.

Olivella, S., A. Gens, J. Carrera, E. E. Alonso, 1996. Numerical Formulation for a Simulator (CODE_BRIGHT) for the Coupled Análisis of Saline Media. Engineering Computations, vol. 13, No.7, pp.87-112

Olivella, S., A. Gens, J. Carrera, 1997. CodeBright User’s Guide. Barcelona, E.T.S.I. Caminos, Canales y Puertos, Universitat Politecnica de Catalunya and Instituto de Ciencias de la Tierra, CSIS, 1997

Pickles, W.L., Cover, W.A., 2005. Hyperspectral Geobotanical Remote Sensing for CO2 Storage Monitoring, in: Benson, S.M., ed., 2005, Carbon Dioxide Capture for Storage in Deep Geologic Formations - Results from the CO2 Capture Project, Vol. 2: Geologic Storage of Carbon Dioxide with Monitoring and Verification, Elsevier Publishing, UK. 654 pp.

Thomas, D., (ed), 2005. Carbon Dioxide Capture for Storage in Deep Geologic Formations - Results from the CO2 Capture Project, Vol. 1: Capture and Separation of Carbon Dioxide from Combustion Sources, Elsevier Publishing, UK. 654 pp.

Vigeland, B. and Åsen, K., 2005. Development of a Hydrogen Mixed Conducting Membrane Based CO2 Capture Process, in: Thomas, D., (ed), 2005. Carbon Dioxide Capture for Storage in Deep Geologic Formations—Results from the CO2 Capture Project, Vol. 1: Capture and Separation of Carbon Dioxide from Combustion Sources, Elsevier Publishing, UK.

CO2 Capture Project participating organizations

CO2 Capture Project Phase 2Status mid-2008

The CO2Capture Project Phase 2 (CCP2) Programme began in 2005 and will be completed in

2009. The Programme includes development and/or studies of ten CO2 capture technologies

and seven CO2 storage projects. This article summarizes the status of the Programme nine months before the completion of the technical work. For the completed technology studies and developments the main objectives and targets have been met.

The CO2Capture Project Phase 2 (CCP2) Programme (2005-2009) continues the development

of the most promising technologies for CO2 Capture and Storage (CCS) identified in the CCP1

Programme (2001-2004; Thomas (ed.), 2005; Benson (ed.), 2005). The CCP2 Programme has two major technical focal points 1) Development of Capture technologies and 2) Storage, Monitoring and Verification (SMV) tools and processes. The Programme also includes analysis of policies that support use of capture and storage methods, as well as efforts to communicate the advances in these areas of the Programme. Phase 2 of the Programme continues the most promising technologies from Phase 1, has identified and developed technologies not included in the first phase and is currently updating the cost evaluation. Most of the technology development activities will be concluded in 2008, with the remainder completed in early 2009. This paper provides an overview of the achievements that have been made in the last four years (Phase 2) in the technology programmes.