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IntroductionWintershall-Libya’s onshore concession 97 includes the Nakhla field where oil is produced from the almost 4 km deep Sarir sandstone reservoir. For each new production well in the field, as well as for each appraisal or explora-tion well in the concession and surrounding areas, the main risk is an absence of Sarir sandstone reservoir. Reservoir sandstones can be partly or fully missing because of intru-sions of basalt or deposition of volcanoclastics or presence of shallow basement. Figure 1 illustrates the risks involved, providing a schematic view of a 3 km short line, the worst case line with three dry wells and only one oil well. Looking at well statistics, the overall risk is lower but significant, in the order of 10-30%.

Much geophysical and geological effort has been spent over the years to understand the issue and, despite much progress in terms of qualitative understanding (Weihe et al., 2004; Fornaciari et al., 2003), there has only been lim-ited success in terms of quantitative prediction, i.e. what is the risk of encountering a non-reservoir in a new well location?

This paper discusses multi-component seismic which, we believe, forms a significant step towards quantitative prediction. However, it should always be kept in mind that

the capability to respond to the question requires a full understanding of the overall geological setting and, due to its complexity, cannot be limited to one technical approach only.

State-of-the-art processing applied to conventional (P-wave) seismic data does not enable us to differentiate the nearly 4 km deep Sarir reservoir sandstone from basement, volcanoclastics, and basalt dykes and sills in the study area. Only large basalt bodies can be recognized by P-wave based seismic reservoir characterization.

Well sonic log data (Figure 2) show low Vp/Vs ratio for reservoir (1.55 – 1.7) and high Vp/Vs ratio (1.8 – 2.1) for all non-reservoirs (basement, volcanoclastics, and basalt) with one exception. This suggests that the Vp/Vs ratio would be the physical parameter that allows differentiation between reservoir and non-reservoir in this area. However, the cited exception makes the discussion more complex. Four types of basement have been described in the area. One of them, the Gargaf Group, also exhibits a low Vp/Vs ratio (about 1.7, from sonic log data). The Gargaf Group is heavily frac-tured and fluid-filled which explains the low Vp/Vs value. Therefore, the Vp/Vs ratio (or the related Poisson’s ratio) is the physical parameter that allows differentiation of the res-ervoir from most (but not all) non-reservoirs.

Dual inversion applied to �D multi‑component seismic data onshore Libya

Christian Hanitzsch,1* Luca de Vincenzi,1 Wolfgang Heerde,1 Jean Marc Michel,2 andDamienSemond2

1 Wintershall Holding AG.2 CGGVeritas.* Corresponding author, E-mail: christian.hanitzsch@wintershall.com.

Figure1 Schematic view illustrating the risk of hitting non-reservoir (basalt intrusions, deposition of volcanoclastics or shallow basement), the worst case scenario with three dry and one oil well along one line. The overall statistical risk is much lower, in the order of 10-30%.

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Multi‑component seismic acquisition and processingThe challenge was to accurately predict Vp/Vs in a deep target prior to drilling. Therefore, a 2D3C (multi-compo-nent) survey consisting of 11 lines (212 km total length) was acquired by AGESCO/CGG in 2004 and processed by CGG in 2005 on behalf of Wintershall-Libya. It was the first multi-component acquisition in Libya. A vibrator array was used as P-source and three-component geophones acted as the multi-component receivers. The large maximum offset of 5.5 km ensured the capture of reflection angles up to 400 and enabled the most accurate estimation of P- and S-velocities. Upholes (P- and S-mode) were recorded every kilometre to minimize problems with S-wave static corrections (it turned out that this high density was justified for the study area).

The processing workflow was specific to the project, because it was one of the first cases where the technology had been applied for lithology detection. A true amplitude process-ing sequence of full Kirchhoff prestack time migration was applied in a consistent way for PP- and PS-data. Strong acqui-sition noise was filtered on both PP- and PS-seismic traces. The availability of P- and S-wave well velocity data from shallow to target was one of the key ingredients for successful process-ing. The polarity was controlled using the PP- and PS-reflectivi-ty coefficients of wells, and the seismic amplitude was calibrat-ed to well reflection coefficients.

Consistent interpretation prior to dual inversionBefore using the results of the seismic processing for simultane-ous elastic inversion (‘dual inversion’), an a priori model of the interval Vp/Vs ratio from traveltime differences had to be built. PP- and PS-seismic are directly connected by the unknown Vp/Vs ratio field, so instead of two separate interpretations, one simultaneous interpretation of the two seismic datasets

was required. As displayed in Figure 3, the interpretation was performed with CGG’s special workstation VectorVista (Wild and Souffez, 2006). This ensured that the interval Vp/Vs ratio from interpreted traveltime differences remained within physi-cally meaningful ranges everywhere.

The PP- and PS-seismic were interpreted consistently for three horizons: top, mid, and base zone of interest (Figure 4). The left image shows the PP-seismic in true amplitude (i.e., without any gain, trace balancing, or other approaches usually applied to obtain improved displays). For the target between 2-2.5 s PP-traveltime, the image quality is satisfactory. The weak amplitudes below the graben are a good reminder of attenua-tion and scattering of seismic P-waves in complex areas. The image in the middle shows the PS-seismic, again in true-ampli-tude, with the target between 3.4-4.1 s PS-traveltime. The con-tinuity of reflections is poor, but was sufficient to continue the project. The right image shows the a priori model calculated from the interpreted traveltime differences.

There have been projects where this type of Vp/Vs model was considered the final result. The comparison with well data quickly revealed that lithology detection based on traveltime differences alone would be invalid, at least for this case study, mainly due to uncertainties of picked traveltimes. Also, Vp/Vs estimated from processing is insufficient due to imprecision of picked velocities and lack of resolution.

Dual inversionThe input data of the dual inversion (Figure 5) were the PP-AVO attributes Rpp (PP-wave intercept), Gpp (PP-wave gradient), and Gps (PS-wave gradient). The main inversion parameters were the Vp/Vs a priori model and the limits of the search area for Vp/Vs, Vp, and density. Combined inversion of PP- and PS-wave AVA attributes increases the robustness and resolution of Vp/Vs ratio definition. Matching time and amplitude information from geological events allows the tying of PP- and PS-wave data sample by sample.

The dual inversion (Garotta et al., 2002; Dariu et al., 2003) is a method of obtaining elastic rock properties from joint inversion of multi-component AVO data. Unlike conven-

Figure 2 Cross-plot of compressional versus shear wave velocities from sonic logs within the study area, indicating that the Vp/Vs ratio (or the related Poisson’s ratio) is the physical parameter that allows discrimination of reservoir from most (but not all) non-reservoirs. Figure3 Team work: interpretation using special software.

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tional inversion, which uses single mode waves in the inver-sion process, dual inversion simultaneously reconciles ampli-tude and time information from both PP- and PS-data. The inversion is done in two steps: first the Vp/Vs is computed to minimize the misfit between the D(Vp/Vs) derived from PP- and PS-transit time and the D(Vp/Vs) derived from seis-mic amplitude. In the second step, the obtained optimum Vp/Vs values can be used for the estimation of Vp, Vs, and den-sity values. Vp, Vs, and density are randomly perturbed and are synthetic AVO attributes are computed. The real and the synthetic AVO attributes are compared in a 1D global opti-mization scheme using a variant simulated annealing to find the optimum solution. The step length is automatically adjust-ed during the cooling schedule, a robust technique to improve the accuracy of the inversion results. A priori parameter con-straints ensure that the end result is close to the low frequen-cy parameter trend. In this case study, only the first step was required to invert for Vp/Vs.

Sensitivity analyses Twelve wells were located inside the study area, six of which had P- and S-wave sonic log data available over the reservoir section. Well data were only indirectly used in the inversion (for amplitude scaling and polarity control). Several well datasets were used as blind tests and only made available for comparison afterwards. These hard datasets were most useful for gaining trust as well as understanding the limitations of the technology applied to the dataset.

Several sensitivity analyses were performed. Figure 6 (left) shows two different a priori models (calculated from traveltime differences of two different interpretations ‘A’ and ‘B’, top and bottom images). Dual inversion (using amplitude and traveltime information simultaneously) calculated the updates displayed in the middle, which are different for the two cases. The compar-ison of final results (displayed on the right) shows very similar images. Two zones of clear difference exist and are highlighted by white ellipses, one in the area of weak PP seismic amplitudes below a graben (as shown in Figure 4, obviously amplitudes

have no impact when they are too weak) and another one on the right attributable to an interpretation inconsistency.

The conclusion from this and other sensitivity analyses is that it is most important to consistently pick the same event on both PP- and PS-seismic sections. The choice which event we consistently pick as top and bottom for the a priori model is less important. Not only for testing, but also for production processing, dual inversion was applied twice with different a pri-ori models as input for every line. The similarities and differenc-es are very useful for the interpretation of final results.

Discussion of resultsSeismic data quality was identified as key for successful Vp/Vs calculation. In the areas of good seismic data quality, it was pos-sible to consistently pick and relate events on PP- and PS-seismic sections that could be used as the a priori model. This enabled the inversion to minimize misfits derived from meaningful transit times and seismic amplitudes, and therefore, to obtain Vp/Vs ratio sections (Figure 7) that correlate well with the well log data. Figure 8 shows the case of an oil well (with volcanic sequences partly replacing the deeper part of both the upper and lower reservoir) for which a very good match between seismi-cally inverted and upscaled sonic log Vp/Vs ratios is obtained.

Even in areas of medium seismic data quality, a reser-voir interpretation is possible. If PP- and PS-events can be consistently picked, the inversion still manages to estimate

Figure4 True-amplitude displays (see text for details) of PP- seismic (left) and PS- seismic (middle). The consistent interpreta-tion of Top, Mid and Base zone of interest were used to calculate the a-priori Vp/Vs model (right).

Figure5 Dual Inversion scheme.

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Figure6 Sensitivity analysis (please see the text for details).

Figure7 Vp/Vs section estimated by Dual Inversion. Blue areas (low Vp/Vs) are interpreted as possibly reservoir, orange / red areas (high Vp/Vs) as non-reservoir. The red dashed lines denote locations of oil wells – both are in blue areas. Intersections with two other lines are also annotated.

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Vp/Vs ratio sections that can be interpreted laterally in a rela-tive sense: lower values point towards reservoir, higher values towards non-reservoir. In areas of very weak amplitudes, it is not possible to obtain reliable estimates. For example, this was observed below a major graben with associated scattering and attenuation of the seismic data.

For many intersections of 2D lines, the results show a good correlation except for some intersections located close to major faults (Figure 9). In such cases 3D effects impacted the 2D processing. A 3D multi-component survey would over-come this limitation.

As explained in the introduction, there was one particular non-reservoir limiting the value of Vp/Vs for reservoir differen-tiation, namely the Gargaf Group basement which also shows low Vp/Vs values on logs. The first well from the left in Fig-ure 9, on line 3, encountered Gargaf Group basement. The Vp/Vs section derived from multi-component seismic data shows low values (blue), consistent with either reservoir or the Gar-gaf Group basement.

Final results such as the section displayed in Figure 7 must therefore be interpreted with care. The simplistic legend of blue for ‘reservoir’ and red for ‘non-reservoir’ indicates the trend only. On the one hand, seismic data quality and seismic arte-facts are limiting factors because the relative lateral variations have to be interpreted; on the other hand, the imperfection of the related Gargaf Group Vp/Vs as a differentiating physical parameter is also a limitation.

ConclusionsWell log data in the study area showed that the Vp/Vs ratio is the physical parameter that differentiates reservoir from non-reservoir units except in the case of the Gargaf Group, a highly fractured basement, that could not be discriminated by Vp/Vs.

Figure8Vp/Vs estimated from Dual Inversion of multi-com-ponent seismic data (red line) compared to up-scaled sonic log Vp/Vs (black line), together with lithology column. The data is from the oil well displayed on the right of Figure 7. Note the good correlation.

Figure9 3D view of Dual Inversion results for all eleven multi-component 2D lines.

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Multi-component surface seismic data were acquired, processed, and inverted for Vp/Vs sections. The availability of P- and S-wave velocities from shallow to target in one well was one essential ingredient for successful processing. Dual inversion, the most important new technology in this case, was another vital element. The process simultaneously inverts amplitude (AVO) and traveltime information. The inversion of traveltime information on its own did not provide valid results in this case.

In areas of good seismic data quality, it was possible to obtain results that correlate well with well log data. Even when seismic data were reduced to medium quality, the results match and can be interpreted laterally in a relative sense.

We believe that multi-component surface seismic is a sig-nificant step towards assessing the risk of encountering non-reservoir for a new well location. It should be emphasized that the reduction of a complex geological environment into one physical parameter displayed as a colour section (Figure 7) is also dangerous, because (as discussed) apparent simplicity may hide some complex facets of the problem. Nevertheless, the technology has major potential to help reduce the risk of dry wells in cases similar to the one discussed in this study.

AcknowledgementsThe authors acknowledge the National Oil Corporation (NOC) of Libya, Wintershall-Libya, and CGGVeritas for

permission to publish. We thank our colleagues Z. Ajub, M. Fleckenstein, R. Moeys (Wintershall), M. King (Monarch Technical Services), and many colleagues at CGGVeritas for their technical support in this project.

ReferencesDariu, H., Garotta, R., and Granger, P. [2003] Simultaneous inversion of PP and PS wave AVO/AVA data using simulated annealing. SEG Annual Meeting, Expanded Abstract, 120-123.Fornaciari, M., Seddiq, H. and Dakshi, A. [2003] Hameimat Trough (Sirt Basin-Libya) - Early Stage of Rifting - Depositional and Volcaniclastic Processes. 1st EAGE North Africa/Mediterranean Petroleum & Geosciences Conference and Exhibition, Expanded Abstract, S011.Garotta, R., Granger, P. Y., and Dariu, H. [2002] Combined interpretation of PP and PS data provides direct access to elastic rock properties. The Leading Edge, 21, 6, 532-535.Weihe, T., Porebski, S., and Dellepiane, S. [2004] Depositional Architecture of the Upper Sarir Sandstone Formation (Lower Cretaceous) in the Nakhla and Tuama Oil Fields, Hameimat Trough, East Sirt Basin, Libya. Third Symposium on the Sedimentary Basins of Libya, Geology of East Libya, Conference Manuscript.Wild, P. and Souffez, S. [2006] Engineering the future. Harts E&P, October, 104-106.

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