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Visit from DONG Energy Åsmund Haugen, Bergen, 9 jan. 2012.

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Presentation on theme: "Visit from DONG Energy Åsmund Haugen, Bergen, 9 jan. 2012."— Presentation transcript:

1 Visit from DONG Energy Åsmund Haugen, Bergen, 9 jan. 2012

2 Introduction Rock Water Porosity+ Permeability+ Oil Wettability Water Oil Strongly water-wet Neutrally wet Oil-wet

3 Introduction – Fractured Reservoirs

4 Objective Study impact form wettability on oil recovery from fractured reservoirs Suggest ways to improve oil recovery

5 Controlled laboratory experiments on simplified systems Method of Approach 2D MRI of Fracture 2D MRI of Core 2D NTI 3D MRI Larger Sample Smaller core with fracture Numerical Simulations EOR Sensitivities

6 Experimental – NTI - Vertical Flow Rig Rock Sample Nuclear Tracer Imaging Radioactive isotopes are added to fluids Each isotope emmits defined γ-energies Intesity of each energy is detected by germanium detector Intesity related to amount of fluid phase present Co 60

7 Experimental – NTI - Vertical Flow Rig Injection Pump Rock Sample Detector Nuclear Tracer Imaging Radioactive isotopes are added to fluids Each isotope emmits defined γ-energies Intesity of each energy is detected by germanium detector Intesity related to amount of fluid phase present

8 Experimental – NTI - Vertical Flow Rig Rock Sample Differential Pressure Injection Pump Collimated Germanium Detector Nuclear Tracer Imaging Radioactive isotopes are added to fluids Each isotope emmits defined γ-energies Intesity of each energy is detected by germanium detector Intesity related to amount of fluid phase present

9 2.0 T Superconducting Permanent Magnet Electronics Sample Coils Computer Samples are Loaded Here Experimental – MRI

10 MRI to image in-situ saturation development Non destructive method Sensitive to hydrogen density (similar in oil and water) D 2 O (heavy water) as it does not reveal any signal in the MRI No magnetic materials close to MRI magnet Epoxy coated rock sample Relatively low pressures Pump MRI Transducer Experimental – MRI

11 Experimental – Schedule 1. Coated block with epoxy 2. Measure rock properties Saturate with water Porosity Permeability 3. Drained with oil multi- directionally to S wi 4. Waterflooded with imaging 5. Drained back to S wi 6. Cut and reassembled with fracture network 7. Waterflooded with fractured network with imaging A B C 15 cm 5 cm 9 cm

12 Simulation - History matching History matching the waterfloods Production profiles

13 Simulation - History matching History matching the waterfloods Production profiles Capillary Pressure Relative Permeabilites

14 Simulation - History matching History matching the waterfloods Production profiles In-situ fluid saturation development Matching Procedure Match production/saturation for whole block Adjust relative permeability curves and capillary pressure Use as input for fractured block

15 Simulations – The Numerical Model Grid: 100 x 1 x 17 Honour porosity/permeability distribution Additional layers in outlet and inlet (boundary) 99.9% porosity mD P c = 0 100% initial oil saturation Wells connections Porosity distribution chalk Porosity distribution limestone

16 Simulations – The Numerical Model Grid: 100 x 1 x 17 Honour porosity/permeability distribution Additional layers in outlet and inlet (boundary) 99.9% porosity mD P c = 0 100% initial oil saturation Wells connections Fractures 99.9 % porosity mD P c = 0 Straight relperm curves 100% initial oil saturation Width of 0.01 cm → 0.1 mm

17 Nuclear Tracer Imaging

18 Experiment Simulation Simulation – Pc = 0 in fracture

19 Experiment Simulation Simulation – Pc = 0 in fracture

20 Experiment Simulation Simulation – Pc = 0 in fracture

21 Experiment Simulation Simulation – Pc = 0 in fracture

22 Experiment Simulation Simulation – Pc = 0 in fracture

23 Experiment Simulation Simulation – Pc = 0 in fracture

24 Experiment Simulation Simulation – Pc = 0 in fracture

25 A B C Simulation – Capillary Contact

26 P c = 0 Capillary Contact Simulation – Capillary Contact

27 P c = 0 Capillary Contact Simulation – Capillary Contact

28 P c = 0 Capillary Contact Simulation – Capillary Contact

29 P c = 0 Capillary Contact Simulation – Capillary Contact

30 P c = 0 Capillary Contact Simulation – Capillary Contact

31 P c = 0 Capillary Contact Simulation – Capillary Contact

32 P c = 0 Capillary Contact

33 Magnetic Resonance Imaging

34 ExperimentalNumerical Simulation – Strongly Water-Wet Chalk 0.05 PV

35 ExperimentalNumerical Simulation – Strongly Water-Wet Chalk 0.10 PV

36 ExperimentalNumerical Simulation – Strongly Water-Wet Chalk 0.13 PV

37 ExperimentalNumerical Simulation – Strongly Water-Wet Chalk 0.17 PV

38 ExperimentalNumerical Simulation – Strongly Water-Wet Chalk 0.19 PV

39 ExperimentalNumerical Simulation – Strongly Water-Wet Chalk 0.22 PV

40 ExperimentalNumerical Simulation – Strongly Water-Wet Chalk 0.26 PV

41 ExperimentalNumerical Simulation – Strongly Water-Wet Chalk 0.28 PV

42 ExperimentalNumerical Simulation – Strongly Water-Wet Chalk 0.31 PV

43 ExperimentalNumerical Simulation – Strongly Water-Wet Chalk 0.35 PV

44 ExperimentalNumerical Simulation – Strongly Water-Wet Chalk 0.44 PV

45 Simulation – Summary SSW case Recovery mechanism Capillary dominated imbibition Large influence of fractures Block-by-block displacement Excellent reproduction of experiment

46 Simulation – Oil-Wet Limestone ExperimentalNumerical 0.00 PV

47 ExperimentalNumerical Simulation – Oil-Wet Limestone 0.05 PV

48 ExperimentalNumerical Simulation – Oil-Wet Limestone 0.10 PV

49 ExperimentalNumerical Simulation – Oil-Wet Limestone 0.13 PV

50 ExperimentalNumerical Simulation – Oil-Wet Limestone 0.16 PV

51 ExperimentalNumerical Simulation – Oil-Wet Limestone 0.19 PV

52 ExperimentalNumerical Simulation – Oil-Wet Limestone 1.15 PV

53 Simulation – Summary OW case Recovery mechanism Viscous displacement Large influence of fractures Reduced sweep – low recovery No apparent fluid transport to matrix Excellent reproduction of experiment

54 Fractured Blocks - Simulation Weakly oil-wet Strongly water-wet Numerical Experimental

55 Conclusions Matching both production and in-situ fluid distribution gave higher confidence in simulations Fractures were explicitly represented in the numerical model and confirmed to have significant impact on recovery and fluid flow dynamics. Capillary contact across fractures may impact recovery Fracture permeability had large effect on recovery and sweep for oil-wet conditions.


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