Qiuliang Yao

Physical constraints on c13 and δ for transversely isotropic hydrocarbon source rocks

Based on the theory of anisotropic elasticity and observation of static mechanic measurement of transversely isotropic hydrocarbon source rocks or rock-like materials, we reasoned that one of the three principal Poisson’s ratios of transversely isotropic hydrocarbon source rocks should always be greater than the other two and they should be generally positive. From these relations, we derived tight physical constraints on c13, Thomsen parameter δ, and anellipticity parameter η. Some of the published data from laboratory velocity anisotropy measurement are lying outside of the constraints. We analysed that they are primarily caused by substantial uncertainty associated with the oblique velocity measurement. These physical constraints will be useful for our understanding of Thomsen parameter δ, data quality checking, and predicting δ from measurements perpendicular and parallel to the symmetrical axis of transversely isotropic medium. The physical constraints should also have potential application in anisotropic seismic data processing.

Acoustic Properties of Coal From Lab Measurement

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.

Quantitative interpretation for gas hydrate accumulation in the eastern Green Canyon Area, Gulf of Mexico using seismic inversion and rock physics transform

Gas hydrate can be interpreted from seismic data through observation of bottom simulating reflector (BSR). It is a challenge to interpret gas hydrate without BSR. Three-dimensional qualitative and quantitative seismic interpretations were used to characterize gas hydrate distribution and concentration in the eastern Green Canyon area of the Gulf of Mexico, where BSR is absent. The combination of qualitative and quantitative interpretation reduces ambiguities in the estimation and identification of gas hydrate. Sandy deposition and faults are qualitatively interpreted from amplitude data. The 3D acoustic impedance volume was interpreted in terms of high P-impedance hydrate zones and low P-impedance free gas zones. Gas hydrate saturation derived from P-impedance is estimated by a rock physics transform. We interpreted gas hydrate in the sand-prone sediments with a maximum saturation of approximately 50% of the pore space. Sheet-like and some bright spot gas hydrate accumulations are interpreted. The interpr...

Velocity of heavy‐oil sand

Several sand samples from shallow heavy oil reservoirs in Alberta, Canada were measured. The samples are loose sands held together by heavy oil from depths between 380 and 500 meters. There is no obvious indication of sample damage by drilling. We observed undisturbed thin shale beds (few mm thick) embedded in sands. We measured the porosity, grain and bulk density of samples at room conditions. Measured data suggest that mineral grain density is around 2.65 gm/cc and porosity ranges from 36 to 40%. The samples show slightly different grain sizes from fine to medium with good sorting. A typical SEM images (Figure 1) show that the sands are clean and well sorted with no cementation. Porosity for the sample is estimated at 37% with permeability of ~7 to 10 Darcy, which is typical for this kind of sands.

Complex properties of heavy oil sand

Summary With more core samples measured in laboratory, we observed wide scattering of velocity on heavy oil sand samples from different fields. A simple universal modeling for heavy oil sand velocity is unrealistic at this stage. However, with improvements on measurement techniques, plus additional information from heavy oil study and other sources, we have better understanding on each factor controlling velocities of heavy oil sands, which include: rock texture, pore fluid properties, and interaction between pore fluids and rock frame at different temperatures.

Application of Spectral Decomposition to Detect Deepwater Gas Reservoir

In this paper, spectral decomposition techniques are applied to deepwater seismic data from Gulf of Mexico to examine the gas associated spectral anomalies. In the first case, thick gas sand with nearly constant P-impedance is encased in shale with non-symmetric P-impedance, and gas reservoir are bright at low-frequency iso-frequency sections; Commercial gas sand and low-gas saturated sand also show apparently different spectral characteristics. In the second case, gas reservoir includes two consecutive up-fining sand intervals with gradually changed P-impedance in each sand interval. Spectral anomalies of gas sand occur at highfrequency iso-frequency sections. Detailed forward modeling is analyzed to help understand the underlying physical mechanisms. Reservoir thickness and Pimpedance structure are the first order factors to control the spectral decomposition responses of the above two gas reservoirs. Systematic synthetic model based on reservoir properties is needed to select optimal frequency range to directly detect hydrocarbon for specific reservoir.

Characterizing the effect of elastic interactions on the effective elastic properties of porous, cracked rocks

Elastic interactions between pores and cracks reflect how they are organized or spatially distributed in porous rocks. The principle goal of this paper is to understand and characterize the effect of elastic interactions on the effective elastic properties. We perform finite element modelling to quantitatively study how the spatial arrangement of inclusions affects stress distribution and the resulting overall elasticity. It is found that the stress field can be significantly altered by elastic interactions. Compared with a non-interacting situation, stress shielding considerably stiffens the effective media, while stress amplification appreciably reduces the effective elasticity. We also demonstrate that the T-matrix approach, which takes into account the ellipsoid distribution of pores or cracks, can successfully characterize the competing effects between stress shielding and stress amplification. Numerical results suggest that, when the concentrations of cracks increase beyond the dilute limit, the single parameter crack density is not sufficient to characterize the contribution of the cracks to the effective elasticity. In order to obtain more reliable and accurate predictions for the effective elastic responses and seismic anisotropies, the spatial distribution of pores and cracks should be included. Additionally, such elastic interaction effects are also dependent on both the pore shapes and the fluid infill.

Frequency‐ and angle‐dependent poroelastic seismic analysis for highly attenuating reservoirs

We extend the frequency- and angle-dependent poroelastic reflectivity to systematically analyse the characteristic of seismic waveforms for highly attenuating reservoir rocks. It is found that the mesoscopic fluid pressure diffusion can significantly affect the root-mean-square amplitude, frequency content, and phase signatures of seismic waveforms. We loosely group the seismic amplitude-versus-angle and -frequency characteristics into three classes under different geological circumstances: (i) for Class-I amplitude-versus-angle and -frequency, which corresponds to well-compacted reservoirs having Class-I amplitude-versus-offset characteristic, the root-mean-square amplitude at near offset is boosted at high frequency, whereas seismic energy at far offset is concentrated at low frequency; (ii) for Class-II amplitude-versus-angle and -frequency, which corresponds to moderately compacted reservoirs having Class-II amplitude-versus-offset characteristic, the weak seismic amplitude might exhibit a phase-reversal trend, hence distorting both the seismic waveform and energy distribution; (iii) for Class-III amplitude-versus-angle and -frequency, which corresponds to unconsolidated reservoir having Class-III amplitude-versus-offset characteristic, the mesoscopic fluid flow does not exercise an appreciable effect on the seismic waveforms, but there exists a non-negligible amplitude decay compared with the elastic seismic responses based on the Zoeppritz equation.

Effect of Compaction History on Pore Pressure Prediction

Summary Correct pore pressure prediction relies on the recognition of formation compaction history and good characterization of the velocity pressure relationships under various scenarios. Experiments were attempted to better characterize the normal compaction trend and unloading curves. Theoretical models were used to better understand the pore pressure’s effect on velocity. Introduction The relationship between velocity and pressure is currently the main resource used to predict pore pressure in formation. Eaton’s (Eaton 1975) equation remains the most popularly used method in the industry. While the overburden pressure follows a stable trend, the pore pressure experiences more variation during compaction. Furthermore, the effect of the pore pressure on velocity and other rock properties does not follow a one to one relationship. Figure 1 schematically depicts the pressure paths for three different scenarios. For a normal compaction trend, the overburden and pore pressures increase at approximately a 2:1 ratio during subsidence. If undercompaction occurs, the overburden and pore pressures may increase at approximately the same rate (dashed dotted line). In the third scenario, the formation first went through normal compaction, and then underwent a pore pressure increase which would most possibly be caused by the fluid expansion. Although the final overburden/pore pressure pair can reach the same value from scenario 2 and 3, the formation rocks have different compaction levels thus exhibit different properties including velocity, resistivity, and porosity. This non-uniqueness in velocity-pressure relationships imposes ambiguity into the pore pressure prediction. To reduce the ambiguity and improve the pore pressure prediction, we need attempts in the following four aspects: 1. Better understanding on the pore pressure mechanism and its relationship to velocity. 2. Ways to recognize the compaction history of the formation: mostly by geologic interpretation, maybe with help from multi-parameter analysis as suggested by Bowers. 3. Better characterization on the normal compaction trend by experiments, for different lithology, and different geologic settings. 4. Also to characterize the unloading trend by experiments. In this report, we present our recent work mainly on points 1, 3, and 4.

Reply to Joel Sarout’s comment on “Physical constraints on c13 and δ for transversely isotropic hydrocarbon source rocks”

We thank Joel Sarout for his perspective reading of our paper (Sarout 2016). First, we want to state explicitly that the physical constraints on c13 are not theoretical constraints; they are heuristic constraints based on observation of laboratory static measurement and physical intuition concerning the explanation of the behavior of a certain amount of hydrocarbon source rocks, to the author’s knowledge. As the title suggests, they only applied to hydrocarbon source rocks whose elastic properties can be described by transverse isotropy. This point is also emphasized in the discussion part of our paper.