Abstract
A big challenge in tight conventional and unconventional rock systems is the lack of representative reservoir deliverability models for movement of water, oil and gas through micro-pore and nano-pore networks. Relative permeability is a key input in modelling these rocks; but due to limitations in core analysis techniques, permeability has become a knob or tuning parameter in reservoir simulation. Current relative permeability measurements on conventional core samples rely on density contrast between oil/water or gas/water on CT (Computed Tomography) scans and recording of effluent volumes to determine relative fluid saturations during the core flooding process. However, tight rocks are characterized by low porosities (< 10 %) and ultra-low permeabilities (< 1 micro-Darcy), that make effective and relative permeability measurements very difficult, time-consuming, and prone to high errors associated with low pore volumes and flow rates.
Nuclear Magnetic Resonance (NMR) measurements have been used extensively in the industry to measure fluid porosities, pore size characterization, wettability evaluation, etc. Core NMR scans can provide accurate quantification of pore fluids (oil, gas, water) even in very small quantities, using T2, T1T2 and D-T2 activation sequences. We have developed a novel process to perform experiments that measure effective and relative permeability values on both conventional and tight reservoirs at reservoir conditions while accurately monitoring fluid saturations and fluid fronts in a 12 MHz 3D gradient NMR spectrometer.
The experimental process starts by acquiring Micro-CT scans of the cylindrical rock plugs to screen the samples for artifacts or microcracks that may affect permeability measurements. Once the samples are chosen, NMR T2 and T1T2 scans are performed to establish residual fluid saturations in the as-received state. If a liquid effective permeability test is required, the samples are then saturated with the given liquid through a combination of humidification, vacuum-assisted spontaneous imbibition, and saturation under pressure and temperature. After saturation, NMR scans are obtained to verify the volumes of the liquids and determine if the samples have achieved complete saturation. The sample is then loaded into a special core-flooding vessel that is invisible to the NMR spectrometer to minimize interference with the NMR signals from the fluids in the sample. The sample is brought up to reservoir stress and temperature, and the main flowing fluid is injected from one side of the sample while controlling the pressures on the other side of the sample with a back pressure regulator. The saturation front of the injected fluid is continuously monitored using 2D and 3D gradient NMR scans and the volumes of different fluids in the sample are measured using NMR T2 and T1T2 scans. The use of a 12 MHz NMR spectrometer provides very high SNR (signal-to-noise ratio); and clear distinction of water and hydrocarbon signals in the core plug during the entire process. The scanning times are also reduced by orders of magnitude, thereby allowing for more scans to properly capture the saturation front and changes in saturation. Simultaneously, the fluid flowrates and pressures are recorded in order to compute permeability values. The setup is rated to 10,000 psi confining pressures, 9000 psi of pore pressure and a working temperature of up to 100 C. Flowrates as low as 0.00001 cc/min can be recorded. These tests have been done with brine, dead and live crudes, and hydrocarbon gases. The measured relative permeability values have been used successfully in both simulation and production modelling studies in various reservoirs worldwide.
Measurement of Spontaneous Imbibition Capillary Pressure, Saturation and Resistivity Index by Counter Current Technique at Net Reservoir Stress and Elevated Temperature