Michael A. Payne

Modeling elastic properties in carbonate rocks

Carbonate (limestone and dolomite) reservoirs account for approximately 50% of oil and gas production worldwide. However, seismic responses in carbonate rocks are poorly understood. In addition, DHI ranking and AVO classification systems developed for clastic rocks are unlikely to be applicable to carbonate rocks. An accurate and physically sound carbonate rock physics model is needed to address these technical issues.

Understanding geophysical responses of shale-gas plays

Unconventional resources such as shale gas are becoming increasingly important exploration and production targets. To understand the geophysical responses of shale-gas plays, we use a rock physics relationship, which is constrained with geology and formation-evaluation analysis, to calculate effective properties such as impedance and VP / VS . Numerical studies suggest that in-situ rock para-meters such as mineral composition (e.g., clay, quartz, and calcite) and TOC, as well as the interaction among them, can significantly influence the geophysical responses of the organic-rich rocks, thus providing the basis for the geophysical characterization of shale-gas plays.

Analysis of microearthquake data at Cold Lake and its applications to reservoir monitoring

More than four months of continuously recorded micro-earthquake data acquired at Cold Lake, Canada, was analyzed using advanced algorithms for microearthquake location and subsurface tomography. Robust determination of the spatial, temporal, and magnitude distribution of seismicity is the first step toward understanding the relationship between the stress perturbations caused by the cyclic steam stimulation (CSS) process and seismicity. Acquisition geometry was constrained because the receivers were located in a single vertical borehole. Despite this constraint, we were successful in improving event locations by use of the double-difference method, which highlights several tight event clusters. The deep cluster at a depth of 400 m , just above the oil reservoir, shows very high seismicity during the CSS processes. A second cluster is observed at shallower depths in the successive steam cycle. This suggests that repeated steaming causes the deformation to spread to shallower depths. The number of events, h...

Considerations for high‐resolution VSP imaging

Vertical seismic profiling (VSP) data can complement surface seismic data where higher resolution is desired or necessary to fully understand a reservoir. VSP data typically provide greater resolution because of the inherently smaller Fresnel zone and because the bandwidth is usually wider than comparable surface seismic data. High fidelity images are required for effective reservoir monitoring. Also, special situations exist, such as attempting to image beneath salt or volcanics, where VSP data can potentially yield superior results because the seismic energy travels through the distorting overburden only once.

Looking ahead with vertical seismic profiles

Several operations enhance our ability to predict the subsurface below the bottom total depth (TD) of the well when applied to zero‐offset vertical seismic profiling (VSP) data. Other key issues regarding the use of VSP data in this fashion are resolution and look‐ahead distance. An impedance log is the most useful form for presenting VSP data to look ahead of the drill bit. The VSP composite trace must first tie reliably to the surface seismic section and to the well log synthetic seismogram. The impedance log is obtained by inverting this VSP composite trace. However, before performing the inversion, we need to (1) correct the composite trace for attenuation effects below TD and (2) input velocities to provide low‐frequency information. An exponential gain function applied to the VSP data below TD adequately compensates for the loss of amplitude caused by attenuation. A calibration of the seismically derived velocities with VSP velocities yields the necessary low‐frequency information. These concepts ar...

Application of noise interferometry to obtain time-lapse velocity variations during a steam stimulation cycle at Cold Lake

Summary The potential economic benefits of passive seismic monitoring motivated us to investigate whether continuous recordings could complement conventional 4D surveys in capturing subsurface changes during production. One example of such a change is the velocity drop in the steaming zone in reservoirs subjected to CSS (Cyclic Steam Stimulation), a phenomenon that has been studied by conventional active time-lapse analyses. In a two-month passive seismic monitoring experiment conducted during the first steam cycle of a CSS pad at Cold Lake, we observed a decrease in velocity by combining noise interferometry and velocity tomography. Using continuously recorded ambient noise as our input, we applied noise interferometry to retrieve pseudo commonsource gathers along a receiver string in a borehole. These gathers retrieved from noise data collected before and after the injection serve as pseudo base and monitor surveys. We measured direct arrivals between receiver pairs in each pseudo survey and used a tomography algorithm to invert for the velocity profile along the receiver line. We observe an average 15% velocity drop above the reservoir interval and a 33% drop within the reservoir interval through the stimulation cycle. The same methodology was also applied to noise recorded at the surface but failed to produce meaningful information about subsurface changes.

Rock Physics As the Basis For Inverting Geophysical Observations

This is the first in a series of papers demonstrating the application of rock physics as the linchpin in inverting geophysical measurements to predict engineering and geologic rock and fluid properties. This paper establishes the importance of having accurate rock physics models for inversion. It highlights many of the effects that need to be incorporated into an analytical rock physics model, which is our preferred embodiment. The papers following this one (Baechle et al., 2008; Chen et al., 2008a; Chen et al., 2008b; Deffenbaugh et al., 2008; Xu et al., 2008) discuss in more detail aspects of the rock physics model in carbonates, its use in 4-D applications, and its validation with computational rock physics techniques.

Intrinsic P- And S-wave Attenuation of Carbonate Reservoir Rocks From Seismic, Sonic, to Ultrasonic Frequencies

New measurements of Pand S-wave velocity dispersion in carbonate reservoir rocks from seismic (<100Hz) to sonic (~10kHz) and ultrasonic (~1MHz) frequencies were analyzed to derive the frequency-domain intrinsic attenuation spectrum. Three rock samples were analyzed, all with porosity in the same range: one sample had high permeability and two had low permeability. We used the standard linear solid model to describe the twin relationship between velocity dispersion and attenuation. The analysis led to the following observations: (1) P-wave attenuation (1/Qp) and S-wave attenuation (1/Qs) are similar in each of the frequency bands(seismic, sonic, ultrasonic): 1/Qp ~ 1/Qs; (2) The attenuation spectrum in each frequency band has an associated characteristic relaxation distance; (3) For a given carbonate reservoir rock, attenuation in the ultrasonic frequency band can be “anomalously” high (Q~1) but still be “normal” (Q~10-100) in the seismic frequency band.

Uncertainty analysis for hydrocarbon‐generated amplitude anomalies

We determined the probability of observing an amplitude anomaly (“bright spot”) due to the presence of hydrocarbons from basic physical properties distributions. The method we applied acknowledges that many varied system parameters lead to non-unique solutions. Two examples will be illustrated. The first example uses a commercially-available database that provides statistical parameters of sand and shale velocities and densities averaged over 500-foot intervals. The database is divided into large blocks within an area of approximately 35,000 square miles in the Gulf of Mexico. Probabilities were calculated as a function of depth, and maps were generated for three distinct ages. Due to the coarse nature of the data, the maps should only be used to indicate gross regional trends. The regional trends indicate that the probability of observing an amplitude anomaly caused by a gas sand decreases with increasing depth and age, and increases with the onset of abnormal pressure. The second example is an evaluation of an amplitude anomaly penetrated by a well to demonstrate the utility of the method on an individual prospect. It illustrates how incorporating AVO effects can enhance the final probability.

Shear‐wave logging to enhance seismic modeling

In an effort to understand better the amplitude variation with offset for reflections from an oil sand and the sensitivity of the AVO response to shear‐wave velocity variations, I studied synthetic and field gathers collected from an onshore field in the Gulf of Mexico basin. A wave‐equation‐based modeling program generated the synthetic seismic gathers using both measured and estimated shear‐wave velocities. The measured shear‐wave velocities came from a quadrupole sonic tool. The estimated shear‐wave velocities were obtained by applying published empirical and theoretical equations which relate shear‐wave velocities to measured compressional‐wave velocities. I carefully processed the recorded seismic data with a controlled‐amplitude processing stream. Comparison of the synthetic gathers with the processed field data leads to the conclusion that the model containing the measured shear‐wave velocities matches the field data much better than the model containing the estimated shear‐wave velocities. Therefo...