1. 11 th Annual SECARB Stakeholders Briefing David Riestenberg George Koperna Advanced Resources International, Inc. March 9-10, 2016 SECARB Anthropogenic Test Update

2. Acknowledgement This presentation is based upon work supported by the Department of Energy National Energy Technology Laboratory under DE-FC26-05NT42590 and was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof.

3. Anthropogenic Test 1.Support the United States’ largest prototype coal-fired CO 2 capture and transportation demonstration with injection, monitoring and storage activities; 2.Test the CO 2 flow, trapping and storage mechanisms of the Paluxy; 3.Demonstrate how a saline reservoir’s architecture can be used to maximize CO 2 storage and minimize the areal extent of the CO 2 plume; 4.Test the adaptation of commercially available oil field tools and techniques for monitoring CO 2 storage 5.Test experimental CO 2 monitoring activities, where such technologies hold promise for future commercialization; 6.Begin to understand the coordination required to successfully integrate all four components (capture, transport, injection and monitoring) of the project; and 7.Document the permitting process for all aspects of a CCS project.

4. Storage Site: The Citronelle Oilfield Structure map by GSA

5. Topics of Discussion 1.Project Status 2.Monitoring Lines of Evidence for Non- Endangerment 3.Model Update 4.Pressure Pulse Testing 5.Conclusions and Next Steps

6. Project Status

7. Storage Project Status Injection commenced on August 20, 2012 Injection ended September 1, 2014 114,104 metric tons of CO 2 injection Entered the three year Post-Injection Site Care Period in September, 2014 CO 2 breakthrough at the D-9-8#2 observation well in 2015  Well mitigation  Monitoring protocols to characterize the arrival  Model update Testing and monitoring activities indicate containment

8. Top of Paluxy Perforations 9,394’ to 9,424’ Low Sigma Anomalies Packer 9,405’ to 9,411’ 9,351 9,364 9,398 9,411 Basal Wash-Fred Evidence of CO 2 Breakthrough Pulsed neutron capture logs run on D-9-8#2 annually ‘Sigma’ anomaly indicated gas saturation buildup in the upper Paluxy in Aug. 2015, confirmed in Nov. 2015 CO 2 confirmed in casing annulus via pressure, tracer sampling and compositional analysis D-9-8#2 Time-Lapse PNC

9. Well Mitigation Flushes from the wellhead (“bullhead”) with a 10.2 pound per gallon kill fluid (a heavy brine) to push the CO 2 down the tubing/casing and into the perforations and back into the injection zone Three flushes to date, 350 to 420 barrels per flush Tubing and casing pressure returns to 0 psi after the flushes Pressure buildups are decreasing and time between pressure buildups is increasing

10. CO 2 Injection History June 2014 Injection well workover

11. 11 Spinner Surveys August 2013 Spinner August 2014 Spinner

12. Upper Paluxy Formation 842ft *1,290ft * * Distance at depth

13. Sand ‘9460’ Stratigraphy and Architectural Geometry 13 Core Log by Pashin, 2015 Sandstone facies deposited under lower flow regime conditions on bar tops in straight to sinuous channel reaches. Consistent ripple orientation within core slabs suggests that unidirectional flows predominated, corroborating a dominant fluvial origin. Core Description by Pashin, 2015

14. Evidence of Containment

15. MVA Elements and Frequency

16. Monitoring Layout One new injector (D-9-7 #2) Two new deep observation wells (D-9-8 #2 & D-9-9 #2) Two in-zone & above zone monitoring wells (Citronelle wells D-4-13 & D-4-14) 12 soil flux monitoring locations Tracer monitoring on nine well pads New USDW monitoring wells at the D-9-7#2 and D- 9-9#2 pads, existing freshwater well at the D-9- 8#2 PFT monitoring location Soil Flux monitoring station In-zone & Above-zone monitoring wells (D-4-13 and D-4-13) AoR: 1,700ft radius from D-9-7 New Characterization Well (D-9-8#2) Back-up Injector/New Observation Well (D-9-9#2) New Injector (D-9-7#2)

17. Shallow Monitoring Soil CO 2 Flux Soil CO 2 results appear to vary as a function of mean temperature Injection startup Injection end

18. Citronelle USDW Sampling Program Three dedicated groundwater sampling wells and one water supply well 3 background sampling events prior to CO 2 injection 14 quarterly sampling events since injection started 17 metals, alkalinity, TDS, TIC, pH…etc. Groundwater sampling locations (circled) WellDepth (ft)Elev. (ft) D9-9 MW-1169.6-20.23 D9-7 MW-2S170.8-5.24 D9-7 MW-2D501.0-335.6 D9-8 WW143--

19. USDW Monitoring Results Statistically Determined Lines of Evidence for Carbon Dioxide Influence Incorporating Both Background Comparison and Trend Analysis Analysis performed through N=16 sampling event (Nov 2015) by Golder Associates based on EPA RCRA monitoring guidelines

20. Perflourocarbon Tracer Monitoring CO 2 stream inoculated with slug of PFT compounds in August 2012 (onset of injection). Well pad tracer results have been non-detects CO 2 stream inoculated with slug of PFT compounds in August 2012 (onset of injection). Well pad tracer results have been non-detects InoculationInjectionPISC Well/SampleAUG 2012JUN 2013NOV 2013MAR 2015JAN 2017 D-9-1ND D-9-2ND D-9-3ND D-9-6ND D-9-7-1ND D-9-8Invalid DataND D-9-9ND D-9-10Invalid DataND D-9-11ND Air Blank 1ND System Blank ND

21. Injection Zone Confining Zone Results from July 2014 survey compared to pre-injection “baseline” survey to image the extent of the CO 2 plume (referred to as “time-lapse imaging”) Time-lapse difference image indicates a decrease in seismic velocity in the upper injection zone suggesting CO 2 saturation no negative velocity anomalies are observed in or above the confining unit Second repeat planned in 2016 Time-Lapse Crosswell Seismic No significant negative velocity anomalies Decrease in velocity (negative anomaly) D-9-7#2 D-9-8#2

22. Deep MVA – Pressure Response Downhole pressure data is a primary input to the history match and plume model

23. D-9-8#2 Deep Fluid Sampling Pre-injection fluid sampling methodology study by USGS Early injection phase sampling with MBM U-tube Slick line Kuster sample in 2015 Continue in 2016

24. Cased Hole Pulsed Neutron Logs D-9-7#2 D-9-8#2 D-9-9#2

25. Pressure Pulse Tests Three small volume water injections in 2015 to initiate pressure transients between injector and monitoring wells Compare pressure transient times to those recorded during CO 2 injection startups Tests discontinued after CO 2 breakthrough at D- 9-8#2 was observed D-9-8#2 flushes can be used for a similar analysis

26. 2016 Model Update

27. 2015 Plume Assessment UIC Area of Review radius is 1,700 feet Annual reservoir simulation updates through 2015 suggested a maximum plume diameter of 600 feet 842 ft

28. 28 D 9-7 Injection Well D 9-8 Observation Well CO 2 Saturation 870 ft. CO 2 Saturation as of September 1 st, 2015 ‘9,460’ Sand ‘9,620’ Sand ‘9,520’ Sand ‘9,540’ Sand ‘9,710’ Sand ‘9,740’ Sand ‘9,800’ Sand 2016 Plume Assessment Preliminary 842 ft

29. Model Comparison 29 ModelPlume Radius (ft) Plume Area (acre) AoR Radius (ft) 2015600231,700 2016 (prelim)880291,700

30. Pressure Pulse Testing

31. To detail changes in saline reservoir dynamics of the Paluxy Sandstone with the injection of CO 2 at the Citronelle Oil Field and to demonstrate non endangerment of USDW’s Objective Pressure data collected from two, in-zone observation wells provides a unique opportunity to establish pressure transient relationships for the reservoir Building an empirically validated model will enable the prediction of reservoir behavior with CO 2 injection, facilitating plume monitoring Rationale :________________________________________________________________

32. Pressure data from two in-zone observation wells were collected from downhole pressure and temperature gauges deployed in the injection zone. Pressure data was compared with injection volume and timing to determine pressure-transient response time. Methodology Theoretical response times were calculated using reservoir properties for several CO 2 saturations to place constraints on changes in CO 2 saturation in the system

33. Cap Rock Injection Well r ↑P↑P Pressure rise observed Injection begins Observation Well ∆p h Simple Transient Pressure Model Time the pulse takes to reach the observation well is a function of reservoir characteristics

34. D 9-8 Pulse Testing 840 feet from injector Response times recorded from downhole pressure data Red diamonds represent CO 2 injection starts Blue circles represents post-injection water pulse tests – Water Injection – CO 2 Injection Legend

35. D 9-8 Pulse Testing A general increase in response time is observed with an increase in cumulative injected volume for early data 840 feet from injector – Water Injection – CO 2 Injection Legend

36. D 9-8 Pulse Testing 9 month shut-in The observed drop in response time follows a 9 month shut- in period 840 feet from injector – Water Injection – CO 2 Injection Legend

37. D 9-8 Pulse Testing Missing Data The pulse for the final phase of injection was not observed due top gauge failure 840 feet from injector – Water Injection – CO 2 Injection Legend

38. D 9-8 Pulse Testing 6 month shut-in A second shut in period of 6 months yields another pressure drop 840 feet from injector – Water Injection – CO 2 Injection Legend

39. D 9-8 Pulse Testing 4 month shut-in A third pressure drop is observed following 4 more months shut-in 840 feet from injector – Water Injection – CO 2 Injection Legend

40. Theoretical Transient Time Calculations

41. Rearrange to solve for the Ei pressure function using known reservoir properties and ∆p Ei function ∆p Reservoir properties The transient pressure rise observed at a known radius for a specific time is a function of the initial pressure, reservoir properties, and the Ei function Equation 3.20a, Slider (1983) Exponential Integral Function Graph

42. Theoretical response times for a pressure transient to travel from the injector to the observation well were calculated as a function of CO 2 saturation in the reservoir (a component of η) Assumptions Homogenous distribution of CO 2 in reservoir Fixed reservoir properties Cap Rock Injection Well r ↑P↑P Pressure rise observed ∆p = 0.5 psi Injection begins q = 864 bbl/day Observation Well ∆p D 9-8 #2 Example (10% CO 2 Saturation) Fluid viscosity0.49 cP Net thickness, h35 ft Permeability, k373 mD Porosity, φ19% Radius, r840 ft Diffusivity C, η1,450,474 System Compressibility 1.75E -5 Pressure gauge h t D = 0.24 t = 2.8 hours Transient Pressure Model

43. D 9-8 Pulse Testing Theoretical response times are calculated from the E i solution of the radial diffusivity equation for several saturation levels 842 feet from injector 40% CO 2 Saturation 30% 20% 10% 0%

44. D 9-8 Pulse Testing 40% CO 2 Saturation 30% 20% 10% 0% Theoretical response times are calculated from the E i solution of the radial diffusivity equation for several saturation levels 842 feet from injector 9 month shut-in 4 month shut-in Missing Data 6 month shut-in

45. D 4-14 Pulse Testing Similar observations are made for the D 4-14 well, albeit with lower saturation values due to larger distance from the injection well Failed gauges account for the fewer data points 3,500 feet from injector 10% 7.5% 2.5% 0% CO 2 Saturation 5%

46. D 4-14 Pulse Testing 10% 7.5% 2.5% 0% CO 2 Saturation Similar observations are made for the D 4-14 well (albeit with lower saturation values due to larger distance from the injection well) Failed gauges account for the fewer data points 3,500 feet from injector 9 month shut-in 5%

47. Conclusions and Next Steps

48. Conclusions CO 2 breakthrough at 9-8#2, but its contained Paluxy more heterogeneous than we thought Multiple injection interruptions limited volumes but provided opportunities for monitoring Multiple lines of evidence from monitoring and modeling suggest CO 2 containment in injection zone and non-endangerment of USDWs

49. Conclusions Modeling update  Directional permeability anisotropy  Thinner permeable zone(s) The observed pulse data shows that response time of the pressure transient increases with increasing volumes of CO 2

50. Next Steps Continue non-endangerment demonstration through monitoring activities  Heat pulse/temperature falloff demonstration at D-9-8#2  Repeat crosswell seismic  D-9-8#2 Deep fluid sampling (multi-level), cased-hole logging and bottom-hole pressure Close out test site including transfer of project wells to oilfield operator  Continue D-9-8#2 flushes as necessary  Squeeze perforations and pressure test Pursue permit closure

51. Questions?

52. Project Objectives 1.Support the United States’ largest prototype coal-fired CO 2 capture and transportation demonstration with injection, monitoring and storage activities; 2.Test the CO 2 flow, trapping and storage mechanisms of the Paluxy; 3.Demonstrate how a saline reservoir’s architecture can be used to maximize CO 2 storage and minimize the areal extent of the CO 2 plume; 4.Test the adaptation of commercially available oil field tools and techniques for monitoring CO 2 storage 5.Test experimental CO 2 monitoring activities, where such technologies hold promise for future commercialization; 6.Begin to understand the coordination required to successfully integrate all four components (capture, transport, injection and monitoring) of the project; and 7.Document the permitting process for all aspects of a CCS project.

53. Underground Injection Control Class V Permit UIV Class V Experimental Injection Well permit –Short duration of injection (3 years) and modest volumes of CO 2 –Demonstration of experimental monitoring tools and methods Several UIC Class VI (CO 2 sequestration well) standards were applied –Injection Area of Review (AOR) determined by modeling and monitoring results (Annually) –AoR based on initial modeling and forecast of 550,000 metric tons of CO 2 had a radius of 1,700 ft (maximum plume extent) –Deep, shallow and surface monitoring –Injection stream compositional monitoring –Site closure based on USDW non-endangerment and CO 2 containment demonstration (5-yr renewal) –Based on monitoring and modeling results

54. 54 © 2015 Electric Power Research Institute, Inc. All rights reserved. Citronelle Compliance Monitoring Program is Based on U.S. Environmental Protection Agency RCRA Guidelines Compliance data exceed UIC permit levels? Yes Compliance data exceed natural background range? Yes Compliance data exceed Upper or Lower Confidence Limit (C.L.)? - Check for outliers - Check for normality - Compute 95% C.L. - Value to value comparison with C.L. Wilcoxon-Mann-Whitney Trend Analysis. Trend Observed? Yes No Continue Monitoring Yes Take action

55. Shallow Monitoring Soil CO 2 Flux Multiple lines of evidence for the potential influence of carbon dioxide at individual monitoring wells have not been identified to date at Citronelle