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ABSTRACT Single and two-phase 2D, fluid flow equations are used to design a transformation procedure that evaluates horizontal permeability directly from time-lapse seismic data. The exact formula used depends on whether the seismic is predominantly sensitive to saturation or pressure changes. Tests are performed on synthetic and observed 4D, seismic from a North Sea field, and illustrate the promise of this technique to deliver information directly for future integration with the reservoir model. The results suggest that pressure-controlled seismic is to be preferred over saturation-controlled for robust permeability estimation.
- Geophysics > Time-Lapse Surveying > Time-Lapse Seismic Surveying (1.00)
- Geophysics > Seismic Surveying (1.00)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/7a > Magnus Field > Kimmeridge Formation > Magnus Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/7a > Magnus Field > Kimmeridge Formation > Lower Kimmeridge Clay Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/12a > Magnus Field > Kimmeridge Formation > Magnus Formation (0.99)
- (5 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Four-dimensional and four-component seismic (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Analog Reservoir Modeling This paper describes a research program at the Australian Analog Reservoir Modeling (ARM) is based around a Resources Research Centre to establish and use an analog synthetic cementation technique that allows scaled analog model of a turbidite channel reservoir to investigate issues representations of reservoir systems to be constructed in a with reservoir simulations and time-lapse seismic laboratory. The cementation technique, known as Calcite monitoring of these complex fields. The project goal is to In-situ Precipitation System (CIPS) allows sandstones to be gain a better understanding of issues relating to uncertainty fabricated with pre-determined physical properties such as in reservoir simulations of channelized fields and their porosity, permeability and impedance (Sherlock and seismic expression.
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (0.95)
ABSTRACT Field and laboratory data indicate anomalously high reflectivity from fluid-saturated reservoirs at the low-frequency seismic range. It also has been observed that the reflected signal is frequency-dependent and is strongly related to the reservoir flow properties. We have obtained an asymptotic representation of the seismic reflection from a fluid-saturated porous medium in the low-frequency domain. The frequency-dependent component of the reflection coefficient is proportional to the square root of the product of frequency of the signal and the mobility of the fluid in the reservoir. This provides an opportunity for locating the most productive zones of the field before drilling. In the presented example we quantify low-frequency imaging amplitude attribute in terms of reservoir fluid mobility and reservoir production rate.
- North America > United States > Colorado (0.20)
- North America > United States > Texas (0.15)
- North America > United States > California (0.15)
The Role of Macroporosity And Microporosity In Constraining Uncertainties And In Relating Velocity to Permeability In Carbonate Rocks
Baechle, Gregor T. (Comparative Sedimentology Laboratory, University of Miami) | Weger, Ralf (Comparative Sedimentology Laboratory, University of Miami) | Eberli, Gregor P. (Comparative Sedimentology Laboratory, University of Miami) | Massaferro, Jose‐Luis (Shell International E&P,Carbonate Development Team)
ABSTRACT Velocity — porosity transforms and porosity — permeability transforms are frequently used for upscaling of rock properties from core and log scale to reservoir scale. Carbonate rocks often show a large scatter in the relationship between porosity and permeability. Hence further analyses are required in order to better predict permeability, which would result in more accurate reservoir modeling, and better reserve predictions. Incorporating image analysis enables us to reduce the uncertainties present in velocity and permeability scatter. Obtaining the microporosity by subtracting the macroporosity from the plug porosity leads to a better correlation with velocity than total porosity. The trend follows the Wyllie time average trend line. The deviation between measured total porosity and microporosity, the image macroporosity, is an excellent indicator of permeability in our dataset. Using the image macroporosity versus permeability trend reduces the uncertainty of permeability prediction by more than one order of magnitude. In our case, the microporosity is the dominant ineffective porosity for fluid flow. This reduction in uncertainty allows for better reservoir prediction and development.
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.87)
- Geology > Geological Subdiscipline > Geomechanics (0.67)
ABSTRACT Fractures and faults provide the primary control on the underground fluid flow through low permeability massive carbonate rocks. Fault cores often represent lower transmissibility whereas the surrounding damaged rocks and main slip surfaces are high transmissibility elements. We determined the physical properties of fault rocks collected in and around the fault cores of large normal faults in central Italy. The cemented fault rocks present along the main slip surfaces have low porosity and high bulk and shear moduli, which are very similar to those characterizing the Cretaceous limestone host rock. Conversely, the fault gouge within the fault cores and the fractured limestone have higher low porosity and high bulk and shear moduli relative to the host rock. These two rocks are however composed by a different pore frame. After studying the P- and S-wave velocity variation during cycles of confining pressure, we conclude that a rigid pore frame characterizes the fault gouge whereas the fractured limestone comprises pores with a larger aspect ratio.
- Europe > Italy (1.00)
- North America > United States > Colorado (0.17)
- Geology > Structural Geology > Fault (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.71)
ABSTRACT Numerical simulations of fluid flow through 3D pore space can provide accurate estimations for permeability. A digital volume required for these numerical experiments may be obtained directly by microtomography or statistically reconstructed from 2D thin sections. Such a digital pore volume has to be statistically representative of the original rock. However, only small rock fragments, such as drill cuttings, and only 2D images of those may be available in the field. To address this practical constraint, we investigate how permeability can be estimated from small 2D images. We select a number of natural and artificial medium-to-high porosity well-sorted sandstones. 3D microtomography volumes are obtained from each of these physical samples. Then, analogous to making thin sections of drill cuttings, we select a large number of small 2D slices from a 3D scan. As a result, a single physical sample is used to produce hundreds of virtual-drill-cutting 2D images. Corresponding 3D pore space realizations are statistically generated from these 2D images, fluid flow is simulated in 3D, and the absolute permeability is computed. As expected, this permeability does not match the measured permeability of a physical sample, which is due to inherent variations of pore-space geometry among the small images. However, for all the physical samples, a single and clear trend is formed by cross-plotting the simulated permeability versus porosity. This trend is typical for clean sandstone. The simulated permeability of under-representative sandstone fragments does not match the physically measured data. Instead it provides a valid permeability-porosity transform which can be used to estimate permeability if porosity is independently known from well log or seismic measurement
- Asia > Middle East > Israel > Mediterranean Sea (0.25)
- North America > United States > Colorado (0.17)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.74)
- Geology > Sedimentary Geology (0.73)
- Geophysics > Seismic Surveying (0.70)
- Geophysics > Borehole Geophysics (0.51)
- North America > Canada > Newfoundland and Labrador > Newfoundland > North Atlantic Ocean > Atlantic Margin Basin > Grand Banks Basin > Jeanne d'Arc Basin > Hibernia Field > Hibernia Formation (0.99)
- North America > Canada > Newfoundland and Labrador > Newfoundland > North Atlantic Ocean > Atlantic Margin Basin > Grand Banks Basin > Jeanne d'Arc Basin > Hibernia Field > Avalon Formation (0.99)
ABSTRACT An algorithm is presented that uses reservoir geophysical data to estimate the productivity index of vertical oil wells. The estimate includes pressure dependent changes in net thickness and permeability. A soft rock example shows that well productivity index has a notable dependence on pressure in some reservoirs.
ABSTRACT The Lattice-Boltzmann (LB) method has been recognized as a very powerful tool for computational fluid dynamics, especially with complex pore structures. Although the LB methods can simulate realistic fluid flow in complex digital pore structure, we cannot predict accurate permeability and relative permeability without good input data — digital rocks. The parameters that make the digital rocks good or bad, is two length scales — grid spacing and the size of digital rock (representative elementary volume). To have fair comparison of these two length scales among many digital rocks with different grain/pore sizes, we first define the characteristic length scale (a, ) of pore geometry. Absolute permeability and relative permeability shows very similar behaviors with the grid spacing (d, ). When the grid spacing is reasonably small (d, =a, /10), permeability stays within reasonable error range. We also found that permeability is consistently overestimated with the increase of grid spacing. Permeability is reasonable determined when the size the digital rock (L, ) is greater than 10 autocorrelation lengths (L, =10a, ). Relative permeability requires bigger digital rocks to be determined accurately. We recommend L, =20a, for accurate prediction of relative permeability.