1. Investigation of CO 2 Sequestration Options for Alaskan North Slope with Emphasis on Enhanced Oil Recovery Shirish Patil, Principal Investigator, UAF Abhijit Dandekar, Co- Principal Investigator, UAF And Pete McGrail and Mark White, PNNL AETDL Annual Project Review Meeting Anchorage, AK January 23, 2007

2. 2 Introduction Source: http://www.irccm.de/greenhouse/files/greenhouse06.png Why Geological Sequestration ?  CO 2 is an important GHG gas  Geological formation has potential  Experience from the oil and gas industry  Global storage capacity is around 24 Giga tons Global Warming and Arctic Environment  Increase in average winter temperature  Reduction in the extent of the summer ice pack in the Arctic Ocean  Either change could accelerate warming  Change could substantially reduce winter drilling window, thus threatening oil and gas developmental drilling and related activities

3. 3 Introduction (cont’d) Why store CO 2 in Alaska? Arctic : impact of climate change is more pronounced Viscous oil production by CO 2 flooding IEA estimates 6000 SCF CO 2 stored for 1 STB of oil (Fanchi,2001) Annual CO 2 generation on North Slope Gas turbines+ handling facilities = 14 million tons Gas sales = 8 million tons TOTAL = 22 million tons Necessity: Advances in drilling technology to develop engineered well bores to avoid communication between injected CO 2 and producer wells. Benefits: Increased oil and gas production in an environmentally friendly manner, leading to economic development.

4. 4 CO 2 sources on ANS (Courtesy BP )

5. 5 Proximity of Potential Sinks on ANS Oil and Gas Fields Sedimentary Basins Thickness, KM 0.0-1.1 1.2-3.1 3.2-7.1 7.2-13.1

6. 6 Coal Resource on ANS Trans-Alaskan Pipe Line Roads Coal Resource

7. 7 Objectives of the study Characterize oil pools, amenable to CO 2 -EOR, on ANS by parametric screening technique Simulate phase behavior by tuning equation -of- state Prediction of oil production by CO 2 injection with compositional simulator well as economics related to it Study of long-term CO 2 storage in a saline aquifer

8. 8 Screening of Oil Reservoirs  Influencing parameters for CO 2 -EOR studies Temperature, Pressure, Porosity, Permeability, API gravity, Oil saturation, Minimum Miscibility Pressure (MMP), and Net pay zone thickness  Parametric study is adopted – Optimum values of above factors are considered to screen out reservoirs best for EOR

9. 9 PoolT, o FΦ,%k, mdS o, %h, ft o APIP/ MMPRiRi Pt. Mcintyre1802220060156271.271 Meltwater14020106095361.52 Lisburne183101.570125271.033 Tarn1422096040371.644 Prudhoe2002226570222280.945 Alpine16019158048401.816 Kupurak -Milne1602015090100240.797 Kupurak River16523407035220.768 Sag River2341846030371.869 North Prudhoe206205906020352.0710 West Sak7530100770 190.4111 Schrader Bluff802850570 17.50.412 Hemlock18010.5537029033.12.3413 Ivishak2541520050125444.1114 Rank (R i ) of the ANS oil Pools

10. 10 Phase Behavior Study The phase behavior of any reservoir fluid in CO 2 injection involves mass transfer and changes in composition. Any compositional simulator can predict the phase behavior of gas flooding, provided the equation of state (EOS) is tuned. In the case of West Sak oil, the phase behavior during CO 2 injection was used to estimate the miscibility condition

11. 11 Results after Regression Better match of ROV and % liquid volume after Regression

12. 12 Multiple Contact Miscibility-CO 2 Injection To investigate the miscibility condition for mixture of West Sak crude and 100% CO 2, the miscibility prediction were obtained by using tuned PR-EOS. Pseudo-ternary diagrams are used to describe for West Sak crude in CO 2 injection process

13. 13 (a) Pressure =1600 psia (b) Pressure =2600 psia (d) Pressure =6600 psia (c) Pressure = 3600 psia Component 1: C7+ as the heavy fraction (H) Component 2: N2,C1 as the light fraction (L) Component 3 : C2,C3,C4,C5,C6,CO2 as the intermediate fraction (I) 1(H) 2(L) 3(I) 1(H) 2(L) 3(I) 1(H) 2(L) 3(I) 1(H) 2(L)

14. 14 West Sak Reservoir and Properties Due to the vast nature of the West Sak Pool, only small portion of the reservoir was selected for the simulation study Area around 260 sq.miles Oil gravity 14 -22.5 API Porosity upto 38% Permeability 10 -140 md Drawn using well log data by Panda et al. and geostatistical tool Top Sand Depth

15. 15 Injection Pattern in CMG’s GEM (Compositional Model) 25 x 25 x 9 Cartesian model: 40 acre area Five sand layers alternated by shale layers Avg. petrophysical properties were obtained from Bakshi (1991) Previously tuned equation-of- state was put into the model CO 2 was continuously injected into the reservoir for 24 years. West Sak five-spot CO 2 injection pattern Producer

16. 16 Changes in oil saturation for 0.2 PV

17. 17 Pore volume & oil rate

18. 18 Pore Volume and Oil Rate for 24-year CO 2 Injection Increase in injection pore volume increased the oil rate and % recovery (OOIP= 4.015MM STB ), but it led to early onset of breakthrough

19. 19 Summary of Injection at 24-year Period For 50% pore volume of CO2 injection was found to be 9.709 Mscf/STB of oil produced. Oil production and corresponding CO 2 storage for 0.5 PV was considered for economical modeling for CO 2 -EOR % PV% Recovery CO 2 Injected, million standard cubic ft CO 2 Produced, million standard cubic ft CO 2 Storage Ratio 1011.401.5980.0750.95 2014.933.1961.0090.68 3016.824.8412.3270.52 5020.628.0404.9810.38

20. 20 Economical Model  To evaluate the feasibility of the CO 2 sequestration with EOR  Costs for each stage of the CO 2 -EOR project includes  CAPEX: Capital Expenditures  OPEX: Operating Expenditures  Annual net cash flow (NCF), as given by Gasper et al (2005),was used to calculate the net present value (NPV) of the EOR project  NCF= (Gross Revenue+ CO 2 credits- Royalty-OPEX-Annual drilling or completion cost (if any)-Depreciation)*(1-Corporate tax)+ Depreciation- CAPEX

21. 21 Economical Model 40 X 75 (3000) acre area to justify the construction of pipeline as well as CO 2 compression unit and other facilities Stored CO 2 will be 75 times the 40 acre flood pattern = 1.37 million tons per year for 50% PV scenario. ParameterAssumed Value for NPV Oil Price (US $/bbl)50 Project Life (years)25 Royalty12.50% Corporate Tax35% Discount Rate12% Rent$12/acre Storage Ratio38 % CO 2 Credits (US $/ton CO 2 )10 Capture Cost (US $/ton CO 2 )3 Compression Cost (US $/tonCO 2 )7.5 Transportation Cost (US $/ton CO 2 )8 Storage Cost (US $/ton CO 2 )3

22. 22 Comparison of NPV Increasing with CO 2 in terms of PV can lead to more NPV with CO 2 credits as long as no leakage conditions are present $ 25.67 MM $ 26.90 million

23. 23 Economical Model Parameters for Sensitivity Analysis Source: Gaspar et al (2005) VariableDistributionParameter Values Discount RatelognormalMean =12%; standard deviation =4% Oil PricelognormalMean = 50; standard deviation =10 CO 2 Creditslognormalmean=10;standard deviation =5 Storage Costtriangular1.5;3;4.5 Capture Costtriangular1.5;3;4.5 Compression Costtriangular6;7.5:9 Storage Rationormalmean =37%; standard deviation =10% Transportation Costtriangular6;8;10

24. 24 Sensitivity Analysis of NPV using Monte Carlo Simulation Rise in oil price by $1 can increase NPV by 45.5%

25. 25 Probability Distribution Probability distribution shows mean of the NPV would be around US$ 0.44 billion

26. 26 Source: PNNL Properties of CO 2 at 45 o C Use of STOMP-WCSE CO 2 injected was injected in the bottom layer for 10 years (3650 days) : 2 kg/s Purpose: To study temperature profile and its impact on CO 2 solubility 3: Saline aquifer 1: Saline aquifer 2: Shale Permafrost & water body of 0.005 NaCl 2-d 42 by 28 radial model

27. 27 Gas saturation at 230ft from the injection CO 2 aqueous mass fraction at 230ft from the injection

28. 28 Temperature profile at 230ft Temperature in the permafrost region remains constant

29. 29 Conclusions Parameters such as temperature, pressure and average petrophysical properties of the oil pools are important to carry out rudimentary screening of potential oil pools with respect to their amenability to CO 2 -EOR. At reservoir pressures of West Sak oil pool, the presence of partial miscibility can be observed from phase behavior study. Oil recovery by continuous CO 2 injection for 24 years predicted 27.57% oil recovery when 50% PV of CO 2 was injected. Increase in pore volume led to decrease in CO2 storage ratio.

30. 30 Conclusions Economical analysis of CO2-EOR proved to be important to estimate time value of the project. At a rate of 2 Kg/s, saline aquifer can successfully sequester CO 2 with no leakage. Changes in temperature profile were negligible when supercritical carbon dioxide was injected in saline formation of NaCl mass fraction of 0.05.