**Source**

**Conference**

**Theme**

**Author**

- Adam, Ludmila (1)
- Agudelo, William (1)
- Al-Kharusi, Layaan (1)
- Arns, Christoph (1)
- Baechle, Gregor T. (1)
- Bandyopadhyay, Kaushik (1)
- Batzle, Mike (2)
- Bayly, Martin (1)
- Becerra, Carlos (1)
- Bekara, Mai¨za (1)
- Boyd, Austin (1)
- Bruhn, David (1)
- Bächle, Gregor (1)
- Bächle, Gregor T. (1)
- Castagna, John (1)
- Chen, Ganglin (1)
- Chesnokov, E. (1)
- Chu, Dez (1)
- Clennel, Ben (1)
- DeGrange, Jean Marie (1)
- Dyaur, N. (1)
- Eberli, Gregor (1)
- Eberli, Gregor P. (2)
- Fabricius, Ida L. (1)
- Ferreira, Analiese (1)
- Flóvenz, Ólafur (1)
- Guevara, Saul (1)
- Guo, Manhong (1)
- Gurevich, Boris (1)
- Han, De Hua (2)
- Huenges, Ernst (1)
- Jaya, Makky (1)
- Kato, Ayato (1)
- Keehm, Youngseuk (1)
- Kim, Young (1)
- Knackstedt, Mark A. (1)
- Krishnamoorti, Ramanan (1)
- Kullmann, G. (1)
- Latham, Shane (1)
- Lebedev, Maxim (1)
- Levin, Stewart A. (1)
- Li, Weiwei (1)
- Liang, Haiyi (1)
- Liu, Enru (1)
- Lu, Ning (1)
- Madadi, Mahyar (1)
- Mavko, Gary (2)
- Mese, Ali I. (1)
- Moeller, Jens (1)
- Mueller, Tobias (1)
- Mukerji, Tapan (1)
- Nakayama, Toru (1)
- Onozuka, Shigenobu (1)
- Ortiz, A. (1)
- Pal-Bathija, Arpita (1)
- Payne, Michael A. (1)
- Pena, V. (1)
- Pervukhina, Marina (1)
- Petrovitch, Christopher (1)
- Prasad, Manika (1)
- Pyrak-Nolte, Laura J. (1)
- Rojas, Maria Alejandra (1)
- Sarker, Rituparna (1)
- Sen, Satyakee (1)
- Shapiro, Serge (1)
- Sheppard, Adrian P. (1)
- Sherrill, Francis (1)
- Sok, Rob (1)
- Soroka, William L. (1)
- Tomich, Richard (1)
- Toms, Juliana (1)
- Tran, Andre (1)
- Tutuncu, Azra (1)
- Tutuncu, Azra N. (1)
- Upmanyu, Moneesh (1)
- van der Baan, Mirko (1)
- Vanorio, Tiziana (2)
- Voltolini, Marco (1)
- Wang, Bin (1)
- Wenk, Hans Rudolf (1)
- Xie, Jing (1)
- Xu, Jim (1)
- Xu, Shiyu (2)
- Yao, Qiuliang (1)
- Yoon, Pilsun (1)
- Zhang, Jie (1)
- Zhang, Yuanzhong (1)

**Concept Tag**

- acoustic property (2)
- analysis (3)
- anisotropy (4)
- Artificial Intelligence (4)
- attenuation (3)
- Barnett shale (1)
- Barnett Shale Core (1)
- Behavior (1)
- Berea sandstone (1)
- Berea Sandstone Core (1)
- bitumen (2)
- Bootstrap (1)
- carbonate (4)
- carbonate rock (2)
- change (3)
- Checkerboard (1)
- Checkerboard test (1)
- Claerbout (1)
- clay (2)
- clay mineral (2)
- Comparison (1)
- complex reservoir (3)
- compressional (3)
- core (3)
- decrease (3)
- dispersion (3)
- distribution (4)
- drilling fluid chemistry (2)
- drilling fluid formulation (2)
- drilling fluid property (2)
- drilling fluid selection and formulation (2)
- drilling fluids and materials (2)
- effect (6)
- Efficiency (1)
- elastic property (2)
- Epsilon (1)
- equation (3)
- experiment (4)
- flow in porous media (2)
- Fluid Dynamics (2)
- formation evaluation (5)
- frequency (4)
- function (2)
- Gassmann (1)
- Gassmann equation (2)
- geophysics (3)
- Geothermal Rock (1)
- GPa (1)
- Hydrate Remediation (1)
- image (2)
- increase (3)
- interpolation (2)
- inversion (2)
- IT software (1)
- Kirchhoff Migration (1)
- Klinkenberg permeability (1)
- Lab (1)
- las vegas (2)
- log analysis (3)
- Magnitude (1)
- management and information (3)
- method (5)
- Microstructure (1)
- model (3)
- Monte Carlo (1)
- montmorillonite (2)
- NMR (1)
- North Sea shale (1)
- Note (1)
- Nyquist (1)
- oil sand (2)
- Pattern Recognition (1)
- permeability (4)
- pore (5)
- Pore Fluid (1)
- porosity (7)
- Production Chemistry (1)
- relaxation (2)
- Reservoir Characterization (21)
- reservoir description and dynamics (22)
- Reservoir Surveillance (1)
- rock (7)
- SAGD (1)
**sample (23)**- sandstone (2)
- saturation (4)
- seg las vegas (7)
- seismic processing and interpretation (17)
- shale (3)
- shear modulus (2)
- shear wave (2)
- Simulation (2)
- spectrum (3)
- structure (2)
- trace (2)
- Upstream Oil & Gas (23)
- water (3)
- Wave (4)
- well (2)
- well logging (3)

**File Type**

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

Oilfield Places:

- South America > Colombia > Norte de Santander Department > Catatumbo Basin (0.99)
- North America > United States > West Virginia > Volcano Field (0.98)
- Europe > Iceland > North Atlantic Ocean > Iceland Basin (0.91)

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

Elastic anisotropy of shale is mainly controlled by the intrinsic anisotropy of individual clay minerals as well as by the textural alignment of grains, pores, and fractures. One of the major challenges in predicting the elastic anisotropy of shales, while using rock physics models, is that the elastic properties of rock-forming clay minerals are poorly known. Since it is impossible to find single and large enough clay crystals for acoustic measurements and ab initio calculations are still incomplete, few data exist on the elastic moduli of clay minerals.

In an attempt to derive the intrinsic anisotropy of pure clay minerals, we present laboratory measurements of compressional and shear wave anisotropy in compacted clay powders at different porosities. In the present work, we focus on the anisotropy of montmorillonitic clays. We used a cold-press method by applying uniaxial compaction in order to obtain compacted mineral aggregates. Different degrees of compaction enable us to obtain samples with variable porosities and crystallite alignments. We measure ultrasonic P- and S- wave velocities along the beddingnormal and the parallel directions. The textural orientation of compacted clay aggregates is found to be controlled by compaction. We obtain the orientation distribution of the clay minerals using synchrotron X-ray diffraction.

Increasing anisotropy of the clay assemblages corresponds to an increase in the preferred orientation of the clay minerals. The combined usage of P- and S- anisotropy measurements with orientation distributions allows us to better constrain the inversion of clay mineral moduli. Our work provides laboratory data on elastic anisotropy of pure clay minerals while linking them to the variation of clay orientation distribution with porosity.

anisotropy, clay, clay mineral, compaction, distribution, elastic anisotropy, elastic property, Epsilon, exponential, formation evaluation, geophysics, intrinsic anisotropy, log analysis, mineral, model, montmorillonite, orientation, porosity, Reservoir Characterization, reservoir description and dynamics, sample, seismic processing and interpretation, shale, stiffness, Thomsen, Upstream Oil & Gas, well logging

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)

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

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

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

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

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)

Guo, Manhong (TGS-NOPEC Geophysical Company) | Kim, Young (TGS-NOPEC Geophysical Company) | Sen, Satyakee (TGS-NOPEC Geophysical Company) | Xu, Jim (TGS-NOPEC Geophysical Company) | Wang, Bin (TGS-NOPEC Geophysical Company) | Xie, Jing (TGS-NOPEC Geophysical Company)

Despite the development of excellent techniques for predicting multiples such as convolution based or wavefield extrapolation based approaches, subtracting multiples in the data using the predicted multiples still remains as a challenge. The difficulty stems from the fact that many existing techniques try to match the predicted multiples to the multiples in the data by either adaptation or pattern matching. Because the prediction techniques mentioned above change the waveform of the predicted multiples, it will be very difficult to perfectly match the waveform of the predicted multiples to that of the multiples in the data. We report a new technique for subtracting the multiples using the attributes of the predicted multiples to determine the multiples in the data without any matching process. We illustrate the technique using a synthetic data set and show 3-D field data examples.

aav, adaptive subtraction, adaptive subtraction method, approach, Artificial Intelligence, attribute, dip, machine learning, method, Note, Pattern Recognition, prediction, Reservoir Characterization, reservoir description and dynamics, sample, seg las vegas, seismic processing and interpretation, spectrum, subtraction, technique, Upstream Oil & Gas, wavefield extrapolation, waveform, well

Technology: Information Technology > Artificial Intelligence > Machine Learning > Pattern Recognition (0.35)

In general speaking, the porosity obtained by nuclear magnetic resonance (NMR) measurement is independent of lithology. However, when the matrix has paramagnetic impurity, such as hematite which is one of the paramagnetic mineralogy of the matrix in volcanic rock, the NMR measurement results will be influenced by the internal magnetic field induced by the matrix paramagnetic mineralogy. In the paper NMR transverse relaxation time T2 of the volcanic breiccia samples have been measured with different echo spacing. The experimental results show that T2 measurement is strongly dependent of echo spacing because of internal magnetic field induced by paramagnetic impurity of the matrix, and it also has an obvious impact on NMR porosity.

distribution, effect, formation evaluation, fracture, internal field, internal magnetic field, log analysis, magnetic susceptibility, magnetic susceptibility contrast, matrix, matrix paramagnetic, NMR, nuclear magnetic resonance, paper, paramagnetic impurity, Pore Fluid, porosity, relationship, relaxation, reservoir description and dynamics, sample, Upstream Oil & Gas, volcanic breccia, well logging

Oilfield Places:

- Asia > China > Xinjiang Uyghur Autonomous Region > Junggar Basin (0.99)
- Asia > China > South China Sea > China Basin (0.97)

SPE Disciplines: Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)

An analysis of two rock samples, hyaloclastites and basalts, at in-situ reservoir conditions has been done to identify the role of temperature on the seismic velocity and attenuation. The goal is to establish a temperature-dependent fluid substitution analysis of geothermal rocks using Gassmann equation within the framework of Biot''s poroelasticity. The analysis of temperature-dependent wave attenuation is shown for hyaloclastites. The results show that the general decreasing trend of seismic velocity towards temperature may be related to the thermophysical characteristics of fluid. Using Gassmann equation it has been shown that the presence of steam bubbles can reduce the effective elastic property of rocks which indirectly demonstrates the role of temperature to the seismic velocity. The Q factor, i.e., inverse of attenuation, behaves surprisingly almost in the same way as the seismic velocity with temperature, except in the lower temperature range. The Q factor increase with the temperature is supposed to be a quick viscosity decrease. The later decrease of Q factor may indicate the presence of steam bubbles due to the further temperature increase. This finding demonstrates that the application of temperature-dependent fluid substitution modelling using Gassmann equation can be applied for the characterization of geothermal reservoir systems.

In geothermal reservoirs, fluid-steam phase transition, fluid pressure and temperature are some crucial factors that potentially produce and/ or contribute to seismic anomalies. When interpreting such anomalies, realistic assumptions based on validated rock physics models are important (Jones et al., 1980; Boitnott and Bonner, 1994).

A laboratory measurement of temperature dependent seismic velocities of rocks at high temperature reservoir conditions has been referred to, for example in (Kern, 1978; Kern et al., 2001; Punturo et al., 2005; Scheu et al., 2006). However, these laboratory experiments have been mainly employed on dry samples and under deep mantle rock condition, i.e., very high pressures (up to 600 MPa with 50 MPa interval) and very high temperatures (up to 1000°C with about 100°C interval). Meanwhile, many geothermal reservoirs, as the case of Icelandic reservoir being investigated, are characterized by temperature range up to 200-300°C and pore pressure around 10 MPa with the pore water being in the liquid phase (Flóvenz et al., 2005). A controlled petrophysical laboratory experiment simulating those conditions becomes important for the evaluation of such a geothermal resource. An analysis of core scale properties of rock sample at in-situ reservoir conditions is useful to identify the role of temperature on the seismic velocity and attenuation. The goal of this work is to present the result of using Gassmann equation within the framework of Biot''s poroelasticity for a fluid substitution analysis of temperature-dependent geothermal rocks. For that, the measurement of ultrasonic transmission wave has been performed on two samples of volcanic geothermal rocks with different alterations (Bruhn et al., 2007; Jaya et al., 2007). Gassmann equation is then used to relate the effect of temperature on the fluid and on the effective elastic property of saturated rock. In addition, the temperature-dependent wave attenuation is shown for the hyaloclastite sample.

analysis, attenuation, condition, decrease, factor, Gassmann equation, geothermal reservoir, Geothermal Rock, Reservoir Characterization, reservoir description and dynamics, rock, sample, seismic processing and interpretation, steam bubble, temperature-dependent fluid substitution, thermophysical characteristic, Upstream Oil & Gas, Wave

Oilfield Places: North America > United States > California > Mayacamas Mountains > Geysers Field (0.99)

Thank you!