SanLinn I. Kaka

Relationships between Instrumental Ground-Motion Parameters and Modified Mercalli Intensity in Eastern North America

A new relationship between modified Mercalli intensity (MMI) and peak ground velocity (PGV) is developed by comparing instrumentally recorded and inferred historical PGV values to observed MMI for 18 significant earthquakes from eastern North America (ENA), of moment magnitude 3.6-7.25. This PGV-MMI relationship is implemented in ShakeMaps in Ontario to estimate ground-shaking intensity (instrumentally derived MMI), given instrumental recordings of PGV. Corresponding relationships for 5% damped pseudoacceleration (PSA) at frequencies of 1, 5, and 10 Hz are also developed. We compare the results with previous relationships between MMI and ground motion parameters developed for California by Wald et al. (1999a) and Atkinson and Sonley (2000). We conclude that empirical relationships between MMI and ground motion are significantly different in eastern North America than in California. Thus, such relationships should be assessed for each region where ShakeMaps are implemented. Manuscript received 24 October 2003.

Passive Microseismic Experiments at King Fahd University of Petroleum and Minerals in Saudi Arabia

Passive microseismic research is still a relatively new technology in the oil and gas industry. To date, very little has been explored by Middle Eastern universities and research centers on the use of passive microseismic data for reservoir monitoring and characterization, with the exception of hydraulic fracture monitoring which has recently been established as a commercial service. To fill this gap, I at King Fahd University of Petroleum and Minerals (KFUPM), under the National Science Technology and Innovation Plan of the King Abdulaziz City for Science and Technology (KACST) program, have initiated a pilot experiment to better understand subsurface reservoirs through the use of passive microseismic data. Meanwhile, recent advances in passive seismic research indicate that significant efforts are needed to separate the near-vertically propagating wavefield (possibly crossing a reservoir) from the near-surface noise (particularly in Saudi Arabia, which is very well known for its complex near-surface conditions). Such a separation is a key prerequisite for understanding and characterizing reservoirs. Some researchers suggest that good correlations exist between passive microseismic data and near-surface features (Hanssen and Bussat, 2008) as well as between passive microseismic data and weather, human activities (Ali et al. , 2010), and seasonal changes (Vesnaver et al. , 2003). Consequently, I have deployed an array of three-component passive microseismic recording stations over different geologic conditions on the KFUPM campus to better understand the origin of various near-surface noises and to develop algorithms to remove them. My long-term vision is to develop passive microseismic technology as an additional reliable tool for hydrocarbon exploration in Saudi Arabia. In this article, I present the preliminary results obtained from passive microseismic stations distributed at various locations of interest over the Dammam Dome structure on the KFUPM campus. Over the last decade, a number of workshops and dedicated technical sessions on passive …

Automated SVD filtering of time-frequency distribution for enhancing the SNR of microseismic/microquake events

Recently, there has been a growing interest in continuous passive recording of passive microseismic experiments during reservoir fluid-injection monitoring, hydraulic-fracture monitoring and fault-movement monitoring, to name a few. The ability to accurately detect and analyze microseismic events generated by these activities is valuable in monitoring them. However, microseismic events usually have very low signal-to-noise ratio (SNR), especially when monitoring sensors (receivers) are located at the surface where coherent and non-coherent noise sources are overwhelming. Therefore, enhancing the SNR of the microseismic event will improve the localization process over the reservoir. In this study, a new method of enhancing the microseismic event is presented which relies on one trace per receiver record unlike other methods. The proposed method relies on a time-frequency representation and noise eliminating process which uses the singular-value decomposition (SVD) technique. Furthermore, the SVD is applied on the matrix representing the time-frequency decomposition of a trace. More importantly, an automated SVD filtering is proposed, so the SVD filtering becomes observation-driven instead of user-defined. Finally, it is shown that the proposed technique gives promising results with very low SNR, making it suitable to locate passive microseismic events even if the sensors are located on the surface.

3D Polarization Analysis of Surface And Borehole Microseismic Data

During the last few years, observation of low-frequency microtremors data has been proposed as a direct hydrocarbon indicator (van Mastrigt and Dulaijan 2008, Lambert et al., 2009). Spectral anomalies in the frequency range of 2 to 6 Hz seemed to be correlated with some underlying reservoirs. Holzner et al. (2009) and Frehner et al. (2009) proposed possible explanations, but their theories predicted anomalies at much higher frequencies, when applied to carbonate rocks as shown by Broadhead (2010). Other researchers highlighted the dominant energy of cultural noise and surface waves in a similar frequency band (Hanssen and Bussat 2008, Green and Greenhalgh 2009, Ali et al., 2010) as well as the lack of repeatability (Vesnaver et al., 2011). In this paper, we investigate a major assumption in the claimed link between microtremors and hydrocarbon reservoirs, i.e., a near vertical propagation of seismic waves through the reservoir upwards to the Earth’s surface. We use microseismic data acquired during a reservoir monitoring experiment in Saudi Arabia. If the microtremor signal comprises dominantly surface waves they may instead be useful for shallow engineering applications (Okada 2003), instead of exploration and production of oil and gas (see Shapiro et al., 2002, 2009, Shapiro and Dinske 2009, Urbancic et al., 2009, Vesnaver et al., 2008, 2010, Verdon et al., 2009, and others).

Analysis of microseismic events during a multistage hydraulic stimulation experiment at a shale gas reservoir

Despite the current easing in demand for increased oil production linked to the global downturn in crude prices, energy demand continuously increases and the long-term demand will require maximizing the productivity of reservoirs and a search into the exploitation of new resources in increasingly challenging environments. In this study, we present the results from the monitoring of the very first multistage stimulation experiment at a shale gas reservoir in Saudi Arabia, presenting an analysis of the microseismicity induced during the treatment. Our aim was to analyse microseismic events to better understand fracture growth and the role of pre-existing fractures in these reservoirs. Microseismic (MS) event monitoring is used to track the creation of fractures during and after the stimulation, and therefore to evaluate the effect of the reservoir stimulation. The monitoring includes a downhole array of 12 3C-sensors that were deployed in a vertical well with a 30.5 m level spacing. A total of 415 MS events were located and analysed, with the results outlining induced fractures extending consistently with an average azimuth of N335° E, normal to the horizontal section of the treatment well. This implies that there are no changes in the local stress direction along the treatment well either in situ or induced along the treatment. There are significant changes in total length and aspect ratio (length/width) of the fractures induced in the different stages. These variations could be attributed to in situ fracturing, local rock heterogeneity or the influence of the treatment parameters. In general, early and late stages of stimulation show the longest fracture networks, with events induced further away from the initiation point. We found no immediate relationship between treatment parameters (peak pressure and pumping rates) and fracture extension. Sensitivity analysis using Monte Carlo simulation methods shows a higher location uncertainty for events located at the early stages, thus limiting the interpretation from monitored seismicity in the early stages. An analysis of magnitude distribution with distance shows a decrease in sensitivity of one degree of magnitude for every 375 m, and a maximum viewing distance of approximately 700 m for the current set-up. The low number of located events does not provide a complete enough dataset for a robust analysis of changes in b-value (slope in linear part of magnitude distribution) during the treatment: however, magnitude distributions, corrected for array sensitivity, provide a useful variable for the validation of geomechanical models currently being developed for the reservoir.

Iterative interferometry-based method for picking microseismic events

Abstract Continuous microseismic monitoring of hydraulic fracturing is commonly used in many engineering, environmental, mining, and petroleum applications. Microseismic signals recorded at the surface, suffer from excessive noise that complicates first-break picking and subsequent data processing and analysis. This study presents a new first-break picking algorithm that employs concepts from seismic interferometry and time-frequency (TF) analysis. The algorithm first uses a TF plot to manually pick a reference first-break and then iterates the steps of cross-correlation, alignment, and stacking to enhance the signal-to-noise ratio of the relative first breaks. The reference first-break is subsequently used to calculate final first breaks from the relative ones. Testing on synthetic and real data sets at high levels of additive noise shows that the algorithm enhances the first-break picking considerably. Furthermore, results show that only two iterations are needed to converge to the true first breaks. Indeed, iterating more can have detrimental effects on the algorithm due to increasing correlation of random noise.

Preliminary geotechnical characterization of a site in southwest Nigeria using integrated electrical and seismic methods

Geophysical investigation using Vertical Electrical Sounding (VES), Electrical Resistivity Tomography (ERT) and Seismic Refraction at a proposed conference center site along Ajibode-Labani road, Ibadan, southwestern Nigeria has been carried out. The investigation aims at characterizing and delineating the subsurface strata to understand the weathered profile at the site. Understanding the weathered profile is essential in determining the suitability of the site for engineering construction of the future conference center. A total of 25 VES and 10 ERT profiles were acquired in a systematic grid pattern using both Schlumberger andWenner configurations with Allied omega terrameter. TheVES data were processed and analyzed using WinResist and the ERT data were inverted using RES2DINV. The data were combined to form a 3-D data set of the site and RES3DINV was used to produce the depth slices. Seismic refraction data were also acquired with an ABEM seismograph and processed using SeisImager and Fajseis software. Seismic data were used in understanding the velocity distribution and thickness. The results of VES, ERT and seismic refraction show good correlation. Four sub-surface layers were delineated: top layer of reworked sand, clayey sand/ lateritic hard pan, clay/ sandy clay and fracture/ fresh basement. The 3-D model permits a pictorial view of the sub-surface in relation to materials that overlie the basement. The thickness of unconsolidated materials to bedrock varies from 2.7 m to 12.2 m which revealed inhomogeneity in weathering under the shallow sub-surface. It is found that the integrated geophysical tool is well suited to characterize and delineate sub-surface structure (weathered profile) for engineering site characterization.

Microseismic events enhancement and detection in sensor arrays using autocorrelation-based filtering

Passive microseismic data are commonly buried in noise, which presents a significant challenge for signal detection and recovery. For recordings from a surface sensor array where each trace contains a time-delayed arrival from the event, we propose an autocorrelation-based stacking method that designs a denoising filter from all the traces, as well as a multi-channel detection scheme. This approach circumvents the issue of time aligning the traces prior to stacking because every trace’s autocorrelation is centred at zero in the lag domain. The effect of white noise is concentrated near zero lag; thus, the filter design requires a predictable adjustment of the zero-lag value. Truncation of the autocorrelation is employed to smooth the impulse response of the denoising filter. In order to extend the applicability of the algorithm, we also propose a noise prewhitening scheme that addresses cases with coloured noise. The simplicity and robustness of this method are validated with synthetic and real seismic traces.

On the use of microtremors for hydrocarbon detection

The link of spectral anomalies of microtremors to underlying hydrocarbon reservoirs is very controversial, as field experiments support both positive and negative opinions, and there is not a solid theory supporting this work hypothesis. We conducted field tests at different sites, with and without oil and gas presence, to add new experimental data to the ongoing studies. Microtremor information may become repeatable (and so physically meaningful) only when the observation duration exceeds a few days, but even in this case, factors such as topography and active faults may severely bias the signal. Ocean waves impinging the coasts provide natural background noise, which stands out clearly when the observation time exceeds a dozen days or so, in such a way that human noise is stacked out statistically over time. Microtremors recorded in (relatively) deep wells may provide useful information about ongoing production in a reservoir, and may link well data and seismic surveys, as their interferometric analysis can provide information comparable to Vertical Seismic Profiles.

Low frequency in depth

The depth of microtremors origin can provide an important clue about the propagation path, as to whether it is coming from deep or shallow sources. Most relevant hydrocarbon reservoirs are located at a depth much larger than that one surface waves can penetrate; so only body waves can carry signals whose anomalies might detect oil and gas presence. A field experiment was carried out in a test site acquiring 3-component records continuously for over 3 weeks. This case study seems to support a shallow propagation path for microtremors and definitely highlights the instability in the wave polarization over time.