North America Business Manager

Transcription

1 Commercial Sequestration Dwight Peters North America Business Manager Mar 9, 2011

2 Acknowledgements Some graphics in this material is based upon work supported by the U.S. Department of Energy (DOE) National Energy Technology Laboratory (NETL). This work is managed and administered by the Regional Carbon Sequestration Partnerships and funded by DOE/NETL and cost-sharing partners. 2

3 The Commercial CO2 Storage Workflow Pre-Operation Phase 2-5 years Operation Phase years Post-Operation Phase 20+ years Certification at start Construction Preparation Monitoring Design CO 2 Injection Characterization Performance Management & Risk Control Decommissioning Transfer of Liability Site Selection Surveillance

4 Current Knowledge Scientific work has identified many potential storage sites in the US and rest of world Only some of these sites can provide low risk, low cost commercial storage Injection pilots build acceptance but leave many unknowns about commerciality Today s best practices manuals have been derived from small scale experiences Many important pilot project experiences are not completely understood Scale-up will require commercial processes adapted from the oil and gas industry.

5 Important Variables Possible site Probable site Appoved site Property rights? Construction Injection Equalization Closure $500M $1B monitor Cume Cost models Desktop Studie es (pennies per ton) $1M Exploration Co ost? ( success ra ate) wells and seismic Collect Data Build Models (~50 cents / ton) $50M Design and Permit (<10 cents / ton) $150M Build (~$1 / ton) gather data Operate Site 3 Mton/yr ( dollars / ton ) update models Environmental Monitoring ( pennies / ton ) Ownership, Liability? Uncertainty 5 yrs yrs 35 yrs Risk Control & Performance Assessment * Per ton estimates and total costs (in current day $USD) are based on 100 Mton lifetime storage volume

6 NATCarb Data Blobs

7 An Oil and Gas Analogy Decades ago, potential oil & gas fields were mapped in a similar il way that t potential ti storage sites are being mapped today

8 The Importance of Data Here s what we learned after decades of oil & gas related data collection

9 Scale Up Challenges for CO 2 Storage Data integration Risk management Monitoring and validation Operational challenges and HSE

10 Data Integration Pilot projects have followed hypothesis driven scientific experimentation Subsurface models should represent a range of possibilities not a best estimate. Integration enables us to continually restrict possible scenarios and lessen risk Multiple disciplines must converge on a shared earth model New information must be rapidly added into the decision process Schlumberger Petrel Model

11 CCS Full System Integration Capture plant plot s Capture Island Transport CO 2 Source CO 2 quality matched to reservoir Fluid behavior through network Operational integration alarming shut downs back up Storage

12 CO2 Injection Simple Schematic Pipeline Inlet From Oxy-fuel Combustion Plant - Purified CO 2 Compressor y miles Aftercooler Pipeline Outlet Injection Well x miles z miles Geologic Formation Surface Pipeline CO 2

13 Surface Pipeline Effect of Pipeline Diameter 200 miles long, 10 miles elevated, 190 miles buried. Inlet temperature 100 F, inlet pressure 1200 psia, ambient temperature 60 F, pure carbon dioxide, one million tonnes per year, 18 pipeline Temperature, F Vapo or Fraction, % OLGA S, 2000, V Lower Heat Transfer Coefficient Temperature, C ΔP 4.1% ressure, psia Pr Beggs and Brill OLGA S, 2000, V ressure, MPa Pr Pipeline length, km

14 Surface Pipeline Effect of Pipeline Size 200 miles long, 10 miles elevated, 190 miles buried. Inlet temperature 100 F, inlet pressure 1200 psia, ambient temperature 60 F, pure carbon dioxide, one million tonnes per year, 12 pipeline Vapo or Fraction, % Beggs and Brill OLGA S, 2000, V Temperature, F OLGA S, 2000, V5.3 Beggs and Brill Temperature, C ΔP 26.3% P ressure, psia Beggs and Brill OLGA S, 2000, V P ressure, MPa Pipeline length, km

15 Surface Pipeline Effect of Temperature 200 miles long, 10 miles elevated, 190 miles buried. Inlet temperature 100 F, inlet pressure 1200 psia, ambient temperature 75 F, pure carbon dioxide, one million tonnes per year, 12 pipeline Temperature, F Vapo or Fraction, % C Temperature, ΔP 42.5% ressure, psia Pr Beggs and Brill Pr ressure, MPa Pipeline length, km

16 Surface Pipeline Effect of 4 mole% Argon Addition 200 miles long, 10 miles elevated, 190 miles buried. Inlet temperature 100 F, inlet pressure 1211 psia, ambient temperature 60 F, one million tonnes per year, 12 pipeline 1.0 V apor Fraction C Temperature, deg Distance, m x Temperature, de eg. F ΔP 82.2% Pres sure, MPa x10 3 Distance, m Pres ssure, psia Distance, m x10 3

17 Full Integration Economics Model Petrel Geologic Model Integrated Asset Model Facilities Model Pipeline Model Wellbore Model Reservoir Simulators GeoMechanics Model GeoChemical Model Environment data Well data Seismic data (characterization) Monitoring data (all types) HSE risk evaluation Leakage risk evaluation

18 The Risk Management Matrix -25 to to to -5-4 to -2-1 BLACK RED NON-OPERABLE: Evacuate the zone and or area/country INTOLERABLE: Do not take this risk YELLOW UNDESIRABLE: Demonstrate ALARP before proceeding GREEN ACCEPTABLE: Proceed carefully, with continuous improvement BLUE NEGLIGIBLE: Safe to proceed MITIGATION Control Measures PREVENTION Light Serious Major Catastrophic SEVERI ITY Improbab ble 1-1 1L -2 1S -3 1M -4 1C Unlikely 2-2 2L -4 1S -6 2M -8 2C Possible 3 LIKELIHOOD -3 3L -6 3S -9 3M -12 3C Likely 4-4 4L -8 4S -12 4M -16 4C Probable 5-5 5L -10 5S -15 5M -20 5C Responses reduce likelihood (PREVENT) reduce severity (MITIGATE). Tasks: Intelligently construct Scenarios that can be modeled. Efficiently i apply simulation resources. Multi-Catastrophic MC -10 2MC -15 3MC White arrow indicates decreasing risk -20 4MC -25 5MC Hazard Analysis and Risk Control Standard d SLB-QHSE-S020 S020

19 Risk Management Tools Rank by Risk

20 CO 2 Monitoring 3 objectives Freshwater aquifer #3: Monitor the environment Containment Well Integrity #2: Watch possible leakage paths Sealed fault #1: Watch stored CO 2 Boundaries CO 2 injection well Monitoring well Abandoned well Monitoring well

21 Operational Challenges and HSE The ability to execute a plan in real-time is as important as the plan itself A proven methodology for decision making, in a dynamic environment, is critical. When we drill and inject into the subsurface we create: predictable events that we can validate Indicators for unpredicted events that could lead toward negative consequences Our ability to anticipate scenarios and respond, prior to incident, is crucial Response capability is the key ingredient in overall cost minimization All of the above impact HSE

22 What is Needed for Project Success People + Technology Geology People Geophysics Reservoir Engineer Drilling Engineer Petrophysics Geomechanics Hydrogeology HSE Project Management Tools for Team Integration Completion Engineer Geochemistry Economics Injection & CO2 Technology All Seismic Services Wellbore Integrity Evaluation Drilling & Completion Cementing Logging, Testing & Sampling Lb Lab Analysis Data Processing Modeling & Plume Prediction Data Management Operational Monitoring Verification Monitoring Compliance Monitoring i

23 The Operational Team Needs: Significant, commercial experience with field operations and asset development elopment CO 2 specific experience Organizational alignment and motivation culture, training, HSE Understanding of and access to key technologies and tools Support infrastructure, HSE

24 Lessons Learned Through Demonstrations Geologic uncertainty is scary to some (esp. engineers) CO2 moves farther, faster, and with fingering CO2 stands out from brine on most monitoring techniques No chance of 100% accounting Old wells will need special focus Large problem in depleted d oil fields Need to consider the entire system or suffer the consequences