Visit from DONG Energy Åsmund Haugen, Bergen, 9 jan. 2012
Introduction Rock Water Porosity+ Permeability+ Oil Wettability Water Oil Strongly water-wet Neutrally wet Oil-wet
Introduction – Fractured Reservoirs
Objective Study impact form wettability on oil recovery from fractured reservoirs Suggest ways to improve oil recovery
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
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
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
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
2.0 T Superconducting Permanent Magnet Electronics Sample Coils Computer Samples are Loaded Here Experimental – MRI
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
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
Simulation - History matching History matching the waterfloods Production profiles
Simulation - History matching History matching the waterfloods Production profiles Capillary Pressure Relative Permeabilites
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
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
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
Nuclear Tracer Imaging
Experiment Simulation Simulation – Pc = 0 in fracture
Experiment Simulation Simulation – Pc = 0 in fracture
Experiment Simulation Simulation – Pc = 0 in fracture
Experiment Simulation Simulation – Pc = 0 in fracture
Experiment Simulation Simulation – Pc = 0 in fracture
Experiment Simulation Simulation – Pc = 0 in fracture
Experiment Simulation Simulation – Pc = 0 in fracture
A B C Simulation – Capillary Contact
P c = 0 Capillary Contact Simulation – Capillary Contact
P c = 0 Capillary Contact Simulation – Capillary Contact
P c = 0 Capillary Contact Simulation – Capillary Contact
P c = 0 Capillary Contact Simulation – Capillary Contact
P c = 0 Capillary Contact Simulation – Capillary Contact
P c = 0 Capillary Contact Simulation – Capillary Contact
P c = 0 Capillary Contact
Magnetic Resonance Imaging
ExperimentalNumerical Simulation – Strongly Water-Wet Chalk 0.05 PV
ExperimentalNumerical Simulation – Strongly Water-Wet Chalk 0.10 PV
ExperimentalNumerical Simulation – Strongly Water-Wet Chalk 0.13 PV
ExperimentalNumerical Simulation – Strongly Water-Wet Chalk 0.17 PV
ExperimentalNumerical Simulation – Strongly Water-Wet Chalk 0.19 PV
ExperimentalNumerical Simulation – Strongly Water-Wet Chalk 0.22 PV
ExperimentalNumerical Simulation – Strongly Water-Wet Chalk 0.26 PV
ExperimentalNumerical Simulation – Strongly Water-Wet Chalk 0.28 PV
ExperimentalNumerical Simulation – Strongly Water-Wet Chalk 0.31 PV
ExperimentalNumerical Simulation – Strongly Water-Wet Chalk 0.35 PV
ExperimentalNumerical Simulation – Strongly Water-Wet Chalk 0.44 PV
Simulation – Summary SSW case Recovery mechanism Capillary dominated imbibition Large influence of fractures Block-by-block displacement Excellent reproduction of experiment
Simulation – Oil-Wet Limestone ExperimentalNumerical 0.00 PV
ExperimentalNumerical Simulation – Oil-Wet Limestone 0.05 PV
ExperimentalNumerical Simulation – Oil-Wet Limestone 0.10 PV
ExperimentalNumerical Simulation – Oil-Wet Limestone 0.13 PV
ExperimentalNumerical Simulation – Oil-Wet Limestone 0.16 PV
ExperimentalNumerical Simulation – Oil-Wet Limestone 0.19 PV
ExperimentalNumerical Simulation – Oil-Wet Limestone 1.15 PV
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
Fractured Blocks - Simulation Weakly oil-wet Strongly water-wet Numerical Experimental
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.