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GoLebedev, Maxim (Curtin University of Technology) | Gurevich, Boris (Curtin University of Technology) | Toms, Juliana (Curtin University of Technology) | Clennel, Ben (CSIRO-petroleum) | Pervukhina, Marina (CSIRO-petroleum) | Mueller, Tobias (University of Karlsruhe)

Ultrasonic velocities and fluid saturations are measured simultaneously during water injection into sandstone core samples. The experimental results obtained on lowpermeability samples show that at low saturation values the velocity-saturation dependence can be described by the Gassmann-Wood relationship. However, with increasing saturation a sharp increase of P-wave velocity is observed, eventually approaching the Gassmann-Hill relationship. We relate this transition behavior to the change of the fluid distribution characteristics inferred from CT scans. In particular, we show that for relatively large fluid injection rate this transition occurs at smaller degrees of saturation as compared with high injection rate.

casino, direct laboratory observation, distribution, experiment, fluid patch, fluid saturation, injection, Reservoir Characterization, reservoir description and dynamics, rock, rock saturation, sample, sandstone, saturation, seg las vegas, seismic processing and interpretation, transition, Upstream Oil & Gas, velocity-saturation relation transition

Oilfield Places:

- Oceania > Australia > Victoria > Otway Basin (0.99)
- Oceania > Australia > South Australia > Otway Basin (0.99)

SPE Disciplines: Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (0.91)

Bächle, Gregor (University of Miami) | Eberli, Gregor (University of Miami) | Madadi, Mahyar (Australian National University) | Sok, Rob (Australian National University) | Knackstedt, Mark A. (Australian National University) | Arns, Christoph (Australian National University) | Latham, Shane (Australian National University) | Sheppard, Adrian P. (Australian National University)

Carbonate rocks are extremely diverse and their pore spaces complex and heterogeneous. Large uncertainties in the petrophysical properties of carbonates are due to wide variations in pore type, pore shape and interconnectivity. Petrophysical properties such as acoustic velocity and permeability are directly correlated to the amount and type of porosity, the dominant feature size and the interconnectivity of different porosity types. Accurately measuring these attributes requires the quantitative 3D analysis of the pore structure of carbonates. In this abstract we describe the imaging and analysis of two types of carbonate core; a set of vuggy, recrystallized dolostones and a set of oomoldic limestones. The structure and topology of the pore space is accurately determined via micro-CT analysis and the porosity consistent with experimental data. Acoustic velocity-porosity, pore connectivity and porosity permeability relationships are derived directly on the image data via numerical simulation and compared with measured data on the same rock. Acoustic velocity:porosity trends are good. Pore structural properties (pore size, aspect ratios, pore and throat shape and connectivity) are determined. The correlations between pore geometry and topology and elastic and flow properties can now be directly probed in a systematic manner. Three dimensional imaging and analysis of carbonate core material can provide a basis for more accurate petrophysical modeling and improve carbonate reservoir characterization.

Many studies have demonstrated the importance of the pore structure in carbonates on petrophysical properties (e.g. Anselmetti and Eberli (1993); Kumar and Han (2004); Rossebo et al. (2005)). Traditional pore type classifications describe the pore structures but fail to quantify the pore system for correlations to the rock''s physical properties. In order to quantitatively describe 2-D pore size, pore surface roughness, aspect ratio, and pore network complexity in carbonates a digital image analysis (DIA) methodology was developed that produces repeatable quantitative pore shape parameters. Each of these quantitative parameters describes a certain aspect of the pore shape. When these parameters are compared to acoustic data, the two DIA parameters that capture the pore complexity and the pore size plus the amount of microporosity prove to be the most influential for the acoustic behavior of the samples. Each of these parameters explains about 60% of the variations in velocity at similar porosity ( Bächle et al. (2004); Weger (2006)). These 2D studies have added much to the understanding of the influence of the pore structure on acoustic properties, yet their 2D nature is a limiting factor for a comprehensive mathematical treatment of pore shapes in simulations of acoustic properties.

There is now an opportunity to image and characterise the pore structure of carbonate cores in 3D. This is based on coupling high resolution x-ray micro-tomography and high end computational software methods including visualizing core material at the pore scale in 3D, measuring structural properties and directly predicting physical properties directly from digitised 3D images ( Arns et al. (2005)). In parallel with 3D experimental techniques one can probe higher resolutions using scanning electron microscopy (SEM);

acoustic property, Artificial Intelligence, carbonate, carbonate core, carbonate reservoir, carbonate rock, complex reservoir, connectivity, eberli, experiment, image, management and information, network, permeability, petrophysical property, pore, pore network, porosity, production control, production logging, production monitoring, Reservoir Characterization, reservoir description and dynamics, Reservoir Surveillance, resolution, sample, Simulation, structure, sucrosic dolomite, Upstream Oil & Gas

SPE Disciplines:

- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (0.71)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (0.56)
- Management and Information > Information Management and Systems > Artificial intelligence (0.48)

Elastic moduli of water saturated sedimentary rocks have in some cases been found to be lower than what would be expected from Gassmann-substitution of moduli for rocks in the dry state, Such water weakening of elastic moduli of carbonate sedimentary rocks may be discussed by effective medium modeling. In the present case we use the isoframe model, which is based on upper Hashin- Shtrikman bounds for mixtures of a stiff carbonate frame and a suspension of carbonate particles in fluid. The proportion of carbonate in the frame is given as the iso-frame value ranging from zero to one. We model ultrasonic compressional wave and shear wave data for dry and water saturated samples from a range of geological settings. Our modeling indicates that water weakening is related to permeability. Samples with permeability up to 1 mD have relatively high water weakening possibly as a consequence of fluid interaction with the relatively frequent crystal contacts in the low-permeability samples. For samples with permeability above 100 mD we rather find a stiffening of water saturated samples. This may be a dispersion effect, as high permeability and high frequency may cause the water in the water saturated samples to move out of phase with the solid during propagation of the sonic wave and thus cause a stiffening effect.

carbonate, compressional, compressional wave modulus, dispersion, dry sample, effect, elastic moduli, flow in porous media, Fluid Dynamics, Gassmann, geophysics, iso-frame modeling, Klinkenberg permeability, las vegas, permeability, porosity, Reservoir Characterization, reservoir description and dynamics, rock, sample, seismic processing and interpretation, shear modulus, Upstream Oil & Gas, water, weakening

Li, Weiwei (Purdue University) | Petrovitch, Christopher (Purdue University) | Pyrak-Nolte, Laura J. (Purdue University) | Liu, Enru (Exxon Mobil Upstream Research Company) | Xu, Shiyu (Exxon Mobil Upstream Research Company)

Introduction Nurmi et al. (1990) observed that heterogeneity in physical properties occurs on all length scales in carbonate reservoirs, i.e., from the micro-scale to the reservoir scale. The physical properties of carbonate rock are strongly influenced by the rock fabric which depends on the depositional environment, diagenetic and tectonic processes. The fabric of carbonate rock is often classified based on the major constituents, pore space, fractures and styolites (Durrast & Siegesmund, 1999). The major constituents in the rock (e.g., fossils, ooides, etc) and the packing and cementation of these constituents result in heterogeneity in physical properties at multiple scales. The most common form of heterogeneity is layering caused by a variation in porosity (Nurmi et al., 1990).

carbonate, carbonate rock, compressional, compressional wave, effect, fluid invasion, impedance contrast, increase, layer, microsecond, Reservoir Characterization, reservoir description and dynamics, rock, sample, seismic processing and interpretation, shear wave, Shear Wave Propagation, signal, Upstream Oil & Gas, Wave

SPE Disciplines: Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)

We measured ultrasonic P and S-wave velocities as a function of varying pore pressure (0-6000 psi) and confining hydrostatic pressure (0-7000 psi) for a North Sea overpressured shale sample simulating subsurface pressure conditions. The estimated effective stress coefficient, n as a function of P- and S-wave velocities and bulk and shear modulii is less than 1 and is a function of differential pressure and mode of wave propagation. The value of n for our unloading case is quite low .The simplified assumption of n=1 is not true and depends on the geology and the stress history of the rock. The experimental results indicate that the shale velocities are more sensitive to changes in confining pressure than to changes in pore pressure during unloading.

change, coefficient, differential, effect, equation, experimental study, function, geophysics, North Sea shale, pore, propagation, Reservoir Characterization, reservoir description and dynamics, reservoir geomechanics, rock, sample, sandstone, seg las vegas, seismic processing and interpretation, shale, stress, Upstream Oil & Gas

The sampling requirements for seismic data are determined by the desired resolution, both temporally and spatially. As essentially all seismic data recorded at this time are sampled discretely, a further consideration is the number of bits used to represent each sample. This paper describes methods for sampling and bit allocation to reduce the CPU and disk resources needed in seismic data processing, and at the same time preserving a high level of signal fidelity. The variable bit allocation method is completely general, while the variable bandwidth sampling method is best adapted to the imaging applications.

allocation, compression, equation, fidelity, fraction, frequency, interpolation, method, Reservoir Characterization, reservoir description and dynamics, residual difference, sample, seg las vegas, seismic processing and interpretation, stop band attenuation, Upstream Oil & Gas, variable bandwidth, variable bit, variable bit allocation, window

SPE Disciplines: Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)

The low velocity propagation of the seismic waves in the first meters of the sub-surface and the topographic irregularities have an effect in the correct position of deep reflectors on seismic images. Velocity models builded using algorithms of tomographyc inversion have shown to be useful to correct this effect, but the solution has associated uncertainties. Three techniques of uncertainty analysis are applied on a tomographical inversion of real near surface data, giving a measurement of the associated error. These tecnhiques are computationally expensive, because they explore intensively the model space. Eventhough, with the use of current high-performing computers, their practical use have been made possible.

Seismic tomography tecnhiques are usually used to obtain velocity models of the weathering layers which is further applied to calculate statics corrections. Several tomographical techniques have been developed with different methologies of ray tracing or inverse problem solution. The main idea is to use the misfit between computed and observed first arrivals times to correct an initial velocity model. Due to the nature of the seismic method that is generally acquired in only one edge of the medium, it have not a unique solution. It is possible have a family of solutions that explain the same dataset. To give a meaning to a non-unique solution, uncertainty analysis techniques are necessary. They can give additional information about the solution such as: which zones in the are better determined? which zones are better resolved? Is there a dispersion measurement (such as variance) associated with the solution model family? Is there a more probable solution model?. In this case study we have applied four methodolies: jackknife, checkerboard test, Monte Carlo, Bootstrap.

The seismic data used was acquired in the Catatumbo basin (Norte de Santander - Colombia). It is a zone with rough topography, where the weathering layer has high thickness and velocity variablility due to the particular conditions in these zones: the tropical weather, the solar energy, the high precipitation regime, the humidity and the temperature. This variablility have a strong effect on seismic image, which have, in general, a low SNR.

In order to perfom a seismic tomography the medium should be discretized. The 2-D velocity field is parameterized as a mesh of nodes hanging from the topography where the node spacing can vary laterally and vertically. The forward problem of refracted arrivals is solved using a hybrid ray-tracing scheme based on the graph method with a local ray bending refinement. For the inverse problem we have used the iterative matrix solver LSQR based in conjugate gradients. To regularize the iterative linearized inversion we employ smoothing constraints using predefined correlation lenghts and damping constraints. For further details of this method see Korenaga (2000).

Jackkniffing Method Jackkniffing was proposed by Quenouille in 1956 and developmented by Tukey in 1957. It is a procedure to estimate the uncertainty of all the set parameter of the model Less (1989) White (1990). In our application, data set was divided in shot gathers.

analysis, Artificial Intelligence, Bootstrap, Checkerboard, Checkerboard test, inversion, method, model, Monte Carlo, perturbation, realization, Reservoir Characterization, reservoir description and dynamics, sample, seismic processing and interpretation, seismic tomography, solution, solution model, traveltime, Upstream Oil & Gas, variation

SPE Disciplines: Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)

Ultrasonic velocities, densities and porosities for a set of coal and surrounding silty coal, silty shale, and shaly coal samples were measured in laboratory. The pressure effect, temperature effect, and saturation effect on velocities and anisotropy were evaluated. The results were compared and correlated with the well log data and discrepancies were analyzed. The potential influences of the coal seams to neighboring gas or oil reservoir seismic response were discussed.

acoustic property, anisotropy, bedding, coal, coal formation, coal sample, coal seam, core, effect, las vegas, porosity, Reservoir Characterization, reservoir description and dynamics, sample, saturation, seismic processing and interpretation, shale, Upstream Oil & Gas, water, water saturation, Wave, well

Baechle, Gregor T. (ExxonMobil Upstream Research Company) | Eberli, Gregor P. (University of Miami) | Boyd, Austin (Schlumberger Doll Research Center) | DeGrange, Jean Marie (Schlumberger Doll Research Center) | Al-Kharusi, Layaan (University of Miami)

In order to model the effect of oil/gas production or CO2 injection at the seismic scale, we have to understand the effects of pore structure, pressure and fluid changes on velocity at the laboratory scale. To reach this goal, we measured carbonate rocks with a suite of miscible fluids, simulating the entire range of reservoir fluid moduli from light to heavy oils.

In our experiments, compressional velocity (Vp) and shear wave velocity (Vs) are simultaneously measured at a frequency of 1MHz and under increasing effective stress from 3 MPa to 30 MPa. We observe large variations in velocities between 3200 m/s and 6500 m/s and a large scatter in the P-wave velocity-porosity relationship. The P-wave velocity shows up to 2000m/s difference at a given porosity. The velocity increases between 250 and 750m/s as pressure incresases from 3 to 30MPa. The bulk of the samples show increasing Vp/Vs ratios with pressurization, up to values between 1.7 and 1.84. The ratio of normalized bulk versus shear modulus ranges from 0.7 to 0.9.

Twenty-one oomoldic carbonate samples with nearly spherical pores show a weak correlation between velocity and porosity under dry conditions. We attribute the weak correlation between velocity and porosity in rocks with similar pore geometry to variations in inter-crystalline porosity in the rock frame. This finding questions the assumption that spherical pores have a dominant effect on velocity.

Four oomoldic samples were chosen for fluid substitution and saturated "in-situ" with seven different pore fluids. Significant effects of fluid changes on velocity are observed. A linear correlation exists between bulk modulus and fluid modulus (r2 > 0.97). In contrast, shear modulus changes correlated with the viscosity of the fluids: the lower the fluid viscosity, the lower the shear modulus. Our results question common hypotheses for modeling pore-structure effects on acoustic properties in carbonates; (a) P-wave velocity is controlled by the percentage of spherical porosity, and (b) the P-wave velocity in oomoldic rocks is insensitive to fluid and pressure changes because of high stiffness of the rock frame. These findings imply that one has to be cautious in relating rock-physics model parameters to volumetric dominant pore types.

carbonate, effect, ethanol, fluid effect, fluid substitution, glycol, intercrystalline, intercrystalline porosity, moduli, oomoldic rock, pore, pore structure, porosity, Reservoir Characterization, reservoir description and dynamics, rock, sample, seismic processing and interpretation, shear moduli, shear modulus, spherical pore, structure, type, Upstream Oil & Gas

Gas hydrates have recently drawn great attention because of their importance as potential future energy resources, a global warming factor and a hazard in ocean structures such as oil platforms. Geophysically, we are seeking the physical property changes in hydrates-bearing sediments, which can relate seismic response to the gas hydrate saturation or predict permeability changes due to gas hydrates, etc. However, the formation of gas hydrates and corresponding physical property changes are not well known, since the detailed hydrates formation mechanism at the pore scale are poorly understood. In this paper, we present preliminary results on gas hydrates formation modeling at the pore scale using computational rock physics approach and comparison of physical property changes to similar laboratory experiments (KIGAM and AIST). First, several formation mechanisms were applied to a detailed 3D pore structures from X-ray microtomography. Then we performed pore-scale fluid flow simulations on the pore structure containing gas hydrates and obtained permeability changes as a function of gas hydrates saturation. Lastly, we compared the results to the lab experiments and tried to explain the pore-scale formation mechanism. From our preliminary results, the KIGAM results agrees well with G-2 model, where the nucleation and growth of hydrates occur at the pore throats; while AIST results seem to match the G-3 model, which is growth-dominant one. Though more detailed and complete modeling results are necessary for identify accurate formation mechanism, this computational approach is versatile and robust technique to model gas hydrates formation at the pore scale.

asphaltene inhibition, asphaltene remediation, change, Comparison, experiment, flow assurance, gas hydrate, gas hydrate formation, gas hydrate saturation, growth, hydrate, hydrate inhibition, Hydrate Remediation, Lab, lab experiment, mechanism, model, modeling, nucleation, oilfield chemistry, paraffin remediation, permeability, pore, Production Chemistry, remediation of hydrates, Reservoir Characterization, reservoir description and dynamics, sample, saturation, scale inhibition, scale remediation, Upstream Oil & Gas, wax inhibition, wax remediation

SPE Disciplines:

- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Hydrates (1.00)

Thank you!