3C seismic data processing and interpretation: a case study from Carpathian Foredeep basin
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Chałupki Dębniańskie seismic profile 2D–3C is located in Carpathian Foredeep basin, Poland, and is an object of interest for geologists and geophysicists due to the presence of gas-bearing layers. Multicomponent seismic plays a significant role in supporting reservoir analysis related to accumulations of crude oil and natural gas. The purpose of the research was the optimal processing workflow design, which integrated seismic images of three-component 2D seismic line (2D–3C seismic). A complete processing flow for vertical and both horizontal components was conducted to obtain stacks and prestack gathers with preserved amplitude relations (RAP processing). The main issue of the research was the interpretation of S-wave velocity, which was not provided by well log data. The obtained results increased the reliability of seismic interpretation within Chałupki Dębniańskie area. The research provided valuable information regarding amplitude anomalies and helped in the verification of the potential gas accumulations. Several reservoir analysis tools were tested, including seismic attributes and AVO analysis. Conducted research confirmed the existence of reservoir which is characterized by good reservoir parameters.
KeywordsSeismic processing Multicomponent seismic DHI AVO
PP-wave surveys are commonly used in geophysics, both in Poland and in the world, in contrast to full-wave recordings, which processing and interpretation are more demanding. Due to increasing difficulties in the prospection of oil or natural gas reservoirs, the industry began to look for methods that could help in the exploration of deposits where conventional P-wave imaging was insufficient (Farfour and Yoon 2016).
much lower S-wave velocity than P-wave velocity;
propagation of S waves only in the elastic medium, which means no impact of the fluid/gas on its propagation velocity;
shear wave splitting phenomenon, which enables anisotropy analysis based on the P-SV and P-SH wavefields.
Due to these properties of S wave, the converted wave data can provide valuable information regarding lithology, lithofacial changes, correlations and verification of amplitude anomalies on PP sections (Myśliwiec 2004c). Converted wave recordings increase furthermore the reliability of the interpretation of AVO/AVA data and the use of joint inversion.
Despite the considerable usefulness of this type of solutions, converted wave recordings are still, due to significant costs, acquisition, processing and interpretation difficulties, relatively rarely used in industrial practice, while research based on P waves is still the main source of knowledge about the subsurface.
The aim of the research was to develop the optimal processing sequence which would increase the reliability of the seismic interpretation of three-component data. The analyzed data consist of standard PP records and non-standard PS components of the wavefield (vertical and horizontal: PSx and PSy, respectively).
Geological setting of the area
The east part of the Carpathian Foredeep is our research area. The following schematic geological model of the eastern part of the Carpathian Foredeep is presented in Fig. 1. The image shows vertical and lateral diversity of the main facial types of the Miocene deposits.
consolidated rocks lying on the bottom of the Miocene basin,
neogeneous forms filling the Miocene basin.
In the research area, the basement is composed of shales interlayering of sandstones. In the regional scale tectonic forms, such as cracking and folding, are here very common.
On the Miocene formations, Quaternary sediments are present, such as clays, sands, gravels, locally loesses. The thickness of the sediments ranges from 5 to 25 meters.
Myśliwiec (2004c) describes traps for gas accumulations in the Miocene strata in the Carpathian Foredeep. Among them there is Chałupki Dębniańskie area with gas-bearing zones. In our research we have selected three perspective areas in terms of the hydrocarbon presence which will be analyzed. Two of them can be checked and verified by well log data. The third zone of interest is interpreted only on the basis of seismic data. Further, we will focus on the analysis of the selected zones.
The experimental seismic profile, which is the subject of this research, was part of the first multicomponent recording in Poland. The data were acquired in 2002. The purpose of the survey was (1) to develop the methodology for processing and interpretation of this type of recordings and (2) to apply the analysis results to the identification of natural gas deposits within the Miocene in the Carpathian Foredeep. First reports come from Gruszczyk et al. (2002). The data analyzed in the article is the 13D-4-02K seismic line, acquired with the dynamite source located in deep shot holes and VectorSeis digital geophones (three-component recording).
Seismic acquisition parameters
Dynamite, average uphole depth = 15 m
VectorSeis digital geophones
305 shots with shot interval = 20 m
280 channels with receiver interval = 10 m
− 2125–1410 m
The first and the most important research objective was to obtain the best resolution of seismic data (both prestack and stack image) with preserved relative amplitudes (RAP processing). Such a methodology enables interpretation of amplitude versus offset (AVO) and amplitude versus incidence angle (AVA). AVO anomaly, which is visible on prestack seismic gathers on times representing the Miocene strata, results from hydrocarbon saturation observable in this area. AVO/AVA processing aims are: (1) to estimate and calculate the signal energy losses during propagation in the medium, (2) to remove the impact of noise and the weathering layer, and (3) to remove processing-related artifacts (Chopra and Castagna 2014). This assumption requires a careful selection of procedures and a thorough quality control of the results.
The analyzed data were migrated with Kirchhoff algorithm to be suitable for AVO study. This is the most computationally demanding solution (e.g., Yilmaz 2001). An unquestionable advantage of the chosen method is the ability to perform migration velocity analysis (MVA). Another possibility is the direct migration of the calculated AVO attributes (Chopra and Castagna 2014).
Poststack processing included spectral whitening, time-variant frequency filter and FX deconvolution (Treitel 1974). It was directed at signal-to-noise ratio improvement.
Converted wave recordings have much lower data quality than PP-wave recordings due to the behavior of the reflected S wave. Their processing is difficult and demanding, especially when it is directed at relative amplitude preservation. The final result of two acquired PS components (PSx and PSy) will be compared to the PP data in order to find the differences in seismic images related to the gas occurrence.
Most of the procedures used (attenuation of coherent and random noise, deconvolution) were processed in the same manner and in the same order as for the PP component (Fig. 3), differing only in parameters such as the size of the time gates or the filter frequencies. The fundamental differences are related to the specific properties of converted waves, in particular: (1) data rotation (2) estimation of the receiver statics and (3) estimation of VP/VS and common conversion point binning (Stewart et al. 1999). Procedures essential for PS components processing sequence and their location in the workflow are shown in Fig. 3. In this chapter we will discuss only these specific differences.
In case of isotropic medium, most of the converted wave energy is recorded on the radial component (in-line direction), while on the cross-line component the white noise should be recorded (Jezierska and Keller-Utracka 2003). Despite the proper orientation of the geophones on the profile, it is usually impossible to place the source exactly in the line of the receiver points, so it is necessary to rotate the recorded data from the physical measurement system to the radial and transverse system. As a result, a change in the polarization of the negative offsets and the improvement of the continuity of shallow horizons on the seismic section can be obtained.
Receiver refraction statics
VP/VS estimation and CCP binning
3C seismic results
For all components (PP, PSx and PSy), two types of datasets were obtained: (1) prestack migrated gathers (suitable for AVO analysis) and (2) poststack migrated sections (appropriate for seismic attributes calculation). All of the datasets were used in the interpretation.
At the end of the processing stage, we discovered that the resolution and general quality of PS data is lower than PP data. The reason for that is the stronger attenuation of S wave, as mentioned before. Also, because the S-wave velocity is much smaller than P-wave velocity (see Figs. 5, 7), we are not able to compare the corresponding reflections on PP and PS datasets. Therefore, in the next chapter we present and discuss PS sections transformed to the t0 time of PP wave.
Basic interpretation of the seismic data
Basic interpretation of the data consists of the well log and PP and PS poststack data correlation. In Fig. 12 three seismic sections are presented (PP, PSx and PSy, all in RAP version). PSx and PSy sections were recalculated using the estimated VP/VS to allow more reliable seismic interpretation.
In direct vicinity of seismic line, two boreholes are located (CHD-2 around CMP 770 and CHD-3 around CMP 1170). Both are reaching the top of the Precambrian (Fig. 12a). On PP seismic section, selected well log data were presented: water saturation (green curve), gamma ray (black curve) and certain top formations (M0, MI, MII and Anh(st)). In the wells basic logs are available (GR, RHOB, DT, VSH, NPHI, SW and SP), but the lack of experience in multicomponent data interpretation resulted in no measurement of the interval time of the S wave for the entire cross-section. Marzec et al. (2006) proposed method of calibration of measured or synthetic S-wave curves on the basis of the P-wave distribution and recorded P- and S-wavefields. To limit some uncertainties during seismic and well log data interpretation, we were focused on the proper S-wave velocity field estimation at the processing stage.
Among the seismic attributes, which are used as hydrocarbon indicators, we consider bright spots and time sags. Qualitative interpretation is based on the fundamental property of S wave, mentioned at the beginning of the work, i.e., hydrocarbon saturation has no effect on the S-wave velocity. This enables the verification of amplitude anomalies present on the PP section.
According to the analysis of PP sum, three bright spot zones were selected. (They reveal large differences in acoustic impedance.) The areas are located inside red rectangles and numbered in Fig. 12. Bright spots, resulting from large differences in acoustic impedance at the top and bottom of the saturated layer, are a frequent phenomenon in the Miocene deposits in the Carpathian Foredeep (Myśliwiec 2004a, 2004c). The basic problem of the PP sections interpretation is the fact that other factors, such as lithology, can cause similar amplitude effects. However, an anomaly, which is the result of lithology change, shall be recorded on all wavefield components, while anomaly resulting from hydrocarbon saturation will be recorded only on PP wavefield image (only in RAP version). Unfortunately, the small gas saturation can also induce large amplitude anomaly (Chopra and Castagna 2014).
The CHD-2 well is located in the main reservoir area on the seismic section (zone number 2). There is a strong correlation between decreased water saturation (green curve in Fig. 12a) and the increased amplitudes of seismic horizons in time interval of 250–500 ms on PP section. From well log data it can be concluded that the reservoir is rich in organic matter and has good reservoir properties (17 gas-bearing layers have been detected); therefore, the correlation between seismic and well log data is evident and easy for interpretation.
The CHD-3 passes through the third reservoir area (zone 3: CDP range 1100–1300, TWT: 500–800 ms in Fig. 12). Lower values of water saturation are detected almost in the whole depth interval. The performed studies suggested that this zone is in fact non-productive. Myśliwiec (2004a, 2004c) and Chopra and Castagna (2014) explain that the strong amplitude anomaly may be also caused by the existence of many layers saturated by a small amount of gas or by bad reservoir properties. During drilling hydrocarbon saturation was not taken into account and no additional measurements were taken. Therefore, the correlation of seismic and well log data is evident, but the analysis of reservoir properties is very doubtful.
PSx and PSy sections in RAP version (Fig. 12b, c) give additional information about potential gas accumulations. Amplitudes of the horizons in red boxes in Fig. 12c are also increased, but their anomalous amplitude behavior is detectable almost on the whole profile. This suggests the impact of the lithology on reflection coefficient on the particular boundaries. Inversely, on the PSx section horizons are very weak except the ones on time interval 150–300 ms, but still their amplitude is comparable on the whole section. When comparing PP and PS images (Fig. 12), it can be concluded that the local amplitude anomalies within selected zones occur only on PP sum. This fact suggests that they are the result of hydrocarbon saturation.
In Fig. 13 we present selected well log data for CHD-2 and corresponding seismic data, in particular: GR, SP, RHOB, DT, PHI and SW, part of seismic section near CHD-2 and the nearest CDP gather. Gas zones are located between horizon 0 and horizon 1 (marked as hor0 and hor1 in Fig. 13, respectively). There is a clear correlation between water saturation (SW) and the level of seismic amplitude in direct well area. Much lower values of water saturation correspond to higher amplitudes on seismic. Unfortunately, some measurements were not done from the surface; therefore, the interpretation of shallow part of the reservoir is limited.
Amplitude versus offset (AVO) study for P wave is based on the analysis of the reflection coefficient (RC) change with source-receiver offset. Similarly, amplitude versus angle (AVA) reveals the change of RC with an incidence angle. Both methods are commonly used in detection and estimation of the anomalous density and velocity contrasts for P wave along a given seismic boundary (Chopra and Castagna 2014). In fact, the AVO/AVA interpretation cannot be the only method used to verify the gas existence, because low-saturated layers, for example gas sands, can cause similar amplitude anomaly to those with high gas saturation (Chopra and Castagna 2014). There are many interpretation techniques using the described wave phenomenon, based on gather analysis (offset/angle gathers), sum analysis (offset/angle limited stacks) and AVO/AVA attribute distributions (including Intercept and Gradient). Recently, there is greater interest in PP- and PS-wave joint AVO inversion, but the methodology is still rather rare (Gaiser 2016). These limitations can be the result of high data quality requirements.
AVO/AVA analyses are more demanding comparing to the bright spot interpretation. A case study is conducted on prestack data (lower S/N), and it is necessary to determine and remove the influence of acquisition and wave propagation on the amplitude of the signal. This means much more careful and demanding processing of seismic records. In order to improve signal-to-noise ratio and coherence of the reflections, additional processing was conducted. In this research we focused only on the interpretation of PP-wave AVA anomaly, because we did not obtain the satisfactory quality of the PS data.
The angle gathers were created on prestack CRP gathers (Fig. 15). A range of angles from 1 to 45° with an interval of 2° was used, obtaining 22 traces for each CMP. This range of angles was necessary to obtain the same effective coverage for the entire time interval of interest as for CMP gathers. Four angle gathers were generated in the range of: (1) 1–22° (2) 11–33° (3) 22–44° and (4) in the whole range of angles: 1–44°. Presented angle gathers show amplitude increase with angle in the specified time interval (Fig. 15b).
AVA analysis was performed for the top and bottom reflection within 700–750 ms time interval (Fig. 16). Having the reflection amplitude as a function of the square of the sine of the incidence angle, we could calculate the following AVO attributes: Intercept and Gradient (denoted as P and G, respectively). Crossplot of the Intercept, calculated as the reflection coefficient at zero angle of incidence, and Gradient, representing the slope of the line on the aforementioned plot, are shown in Fig. 16c.
Amplitude versus offset plot for top and bottom reflection (Fig. 16b) and crossplot of Intercept and Gradient (Fig. 16c) suggest that in this case we are dealing with the third class of AVO, which is typical for poorly consolidated sandstones saturated with gas and surrounded by rocks of much higher impedance. Unfortunately, measurable AVO anomalies can also be generated by a relatively low level of gas saturation. A standard analysis of PP-wave recordings is not sufficient to distinguish the degree of saturation (Myśliwiec 2004c).
The paper confirms that multicomponent seismic significantly supports seismic data interpretation due to the differences in S-wave propagation. Good example for that is a direct hydrocarbon indicators verification, such as bright spots and time sags. Another advantage is the possibility of using prestack seismic data for AVO/AVA analysis.
On the other hand, three-component seismic processing is demanding and difficult. The significant problems are the data rotation, estimation of the receiver statics and reliable estimation of VP/VS ratio used for CCP binning and the transformation of S-wave recording to the time of PP-wave recording. In the research no additional assumptions regarding anisotropy were formulated; however, when analyzing the sums of PSx and PSy, it can be certainly stated that anisotropy occurs in the analyzed area and is associated not only with the presence of cracks, fissures and faults, but also with the variability of rock layering and granulation (Myśliwiec 2004a).
The development of the appropriate sequence of 3C seismic processing led to the results in the form of stacks and prestack gathers, which were appropriate for reservoir analyses based on the amplitude changes resulting from hydrocarbon saturation. On the basis of conducted analyses, we concluded that there is a strong amplitude anomaly in the central part of the conducted survey near CH-2 well. All performed analyses proved the existence of many gas-bearing layers. In the vicinity of CH-3 well seismic anomaly around 1100–1300 CDP does not correlate with gas content information, in contrast to the AVA analysis results, which suggest clear and strong amplitude anomaly. Finally, in the third considered zone, chosen on the basis of PP RAP section, we did not observe any AVO anomaly suggesting oil or gas saturation. PS sections were helpful in verification of potential gas accumulations.
To summarize, obtained datasets with preserved relative amplitudes can be the basis for detailed seismic interpretation which can answer very important question: which of the perspective zones are worth drilling? On the datasets several reservoir analyses, including seismic attributes and AVO/AVA analysis, were conducted. The integrated analysis confirmed existence of reservoir which was characterized by good reservoir parameters (Chałupki Dębniańskie reservoir), as well as existence of non-productive zones which have been misinterpreted in previous studies.
The paper was financially supported from the research subsidy no. 126.96.36.1995 at the Faculty of Geology Geophysics and Environmental Protection of the AGH University of Science and Technology, Krakow, Poland, 2019. The paper was presented at the CAGG 2019 Conference "Challenges in Applied Geology and Geophysics" organized at the AGH University of Science and Technology, Krakow, Poland, 10–13 September 2019. The seismic processing presented in the paper was carried out as a part the master’s thesis of Paweł Dubiel, Faculty of Geology, Geophysics and Environmental Protection, AGH, Kraków, Poland. Authors thank Polish Oil and Gas Company for providing seismic and well log data. Analyses were done in SeisSpace software (Landmark Halliburton) and Hampson-Russell software (CGG) thanks to Academic Grants funded by these companies to the AGH University of Science and Technology, Kraków, Poland.
Compliance with ethical standards
Conflict of interest
On behalf of all authors, the corresponding author states that there is no conflict of interest.
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