Imaging the Eastern Mediterranean

Transcription

1 Imaging the Eastern Mediterranean Imaging new opportunities and play concepts in the Adriatic Sea and Levantine Basin David Peace (EastMedCo) and Theodore Stieglitz (Spectrun Geo Inc) Abstract There is significant opportunity in re-working older data with modern geophysical technology to develop new plays and concepts in the Eastern Mediterranean. New exploration success and higher commodity prices have encouraged both majors and independents to reconsider the Mediterranean as a viable entry point to North African and Southern European energy markets. Two case studies in the Adriatic Sea and Levantine Basin are examined for play concepts and leads using vintage seismic data re-imaged using modern imaging techniques integrated together with a geologically driven workflow. The Adriatic was selected based upon maturity of hydrocarbon discovery; in comparison the Levantine basin ranks as a region of new territory which we are only just beginning to understand. Overview of Levantine Basin The Levantine basin is located in the greater Eastern Mediterranean. Figure 1 shows the location of the Levantine basin in relation to the Nile delta on its SW side and the Larnaca-Latakia ridge systems to the North which mark the Southern extent of the Anatolian plate where it collides with the African plate. Prior to the recent success of Noble Energy, the only significant activity in the basin being located offshore Israel and Gaza were the discovery of several modest post salt Pliocene gas fields. Despite the proximity to European markets, the basin until recently could be described as very under-explored. First new exploration success in the Levantine basin was found in 2009 by Noble in the deep water sub-salt area of the southern part of the basin has resulted in the discovery of 3 new gas fields Tamar and Dalit and Leviathan with more than 25 Tcf mean reserves of natural gas (Noble Announcements 2011). In addition there is some compelling evidence to suggest that a deeper light oil play may exist. These new gas discoveries prove the exploration potential of the region, with significant implications for the whole Levantine basin region as a productive hydrocarbon province. As a result of these recent new discoveries, renewed interest in the region has increased with the prospect of new license rounds in Cyprus, Lebanon in 2012 and the current new round in Syria closing in Q4 this year. The vintage dataset re-imaged and analyzed in support of the analysis presented here consists of 12,303 km subset of a vintage 2D multiclient program covering the offshore areas of Cyprus, Israel, Lebanon and Syria (Figure 2). This survey was acquired during 2000 and was originally processed during 2000 and 2001 using a time migration processing workflow based upon (at the time) best in class technology. The data was later re-processed with refined techniques and taken to depth in 2006/2007. Overview of Adriatic Sea The Adriatic Sea is sandwiched between the heel of Italy and the coastline of Croatia/Bosnia-Herzegovina to the East. Figure 2 shows the greater regional structure features of the basin both on and offshore. Italy has a long history of hydrocarbon exploration. As far back as years, it would be fair to say that the offshore Adriatic Sea was a very active exploration region, particularly in Zone A of the Northern Italian offshore marine coast. Over the last 20 years, active exploration has slowed. In 1987 there were some 332 exploration permits in effect, but by 2007 this had shrunk to only 90,in similar vein in 1987 there were 19 offshore exploration wells drilled which had dwindled to just one in 2007, with a similar decline in production wells in the same period from 41 in 1987 to 12 in As exploration business objectives change, the main focus of exploration in the last decade has shifted from shallow very successful Pliocene gas plays to the deeper more challenging Mesozoic oil plays. The Italian gas market has remained attractive and strong through ebbs in the exploration and production business. In 1994 peak gas production was at a level of 20.6 billion Sm3 or 751 Bcf of which about 75% was from offshore Italy with 53% of that coming from Zone A. Current demand for gas is around 70+ billion Sm3/year and forecast to rise to around 95+ billion Sm3 this year. Consequently, Italy faces a huge shortfall in gas supply which has been augmented by huge imports of gas typically from North Africa. Transportation is attractive, as the high demand for gas generated a sificant pipeline infrastructure. Italy may be also considered as a gateway to the European energy market. Given the proximity to hungry European neighbors, Italy maintains fiscal terms and conditions conducive for exploration. Furthermore, many plays have been proven in shallow coast water from the Pliocene to the upper Miocene. Consequently, historical development and production costs have traditionally been low. Future opportunities exist in even heavily explored offshore provinces, The current map of licenses offshore Italy in the Northern Adriatic illustrate that outside of Zone A about 70-80% of the area is open and unlicensed (Figure 3). As gas and oil prices continue to increase, we expect a high level of exploration activity in this region. The geological cross sections in in Figure 3 show typical W-E structure in the northern part of the Adriatic which is heavily influenced by the West to East thrusting of the Apennine overthrust belt. This over thrust dramatically influences the offshore structure of the region, allowing numerous play types to be found in the region from 4-way anti-clinal dip closures at several levels, structural-stratigraphic plays around the highs and more subtle stratigraphic plays often with associated amplitude anomalies. Some of the more recent discoveries such as Barbara, Anna Maria, Andreina have been in this latter play type and are multi TCF sized fields. The vintage data analyzed in the Adriatic was obtained by Spectrum with the support and blessing of Videpi and UNMIG. Spectrum was able to access and copy all of the old regional 2D Adriatic field data, digitize the raw recorded records and reimage the data from scratch. The data existed in three vintages spanning 1967 to The process of transcribing and sorting the mostly

2 raw SEGY and paper section data was non-trivial and labor intensive. Full re-imaging from field tapes of 8500 km was finally completed by mid-year Much of the original data was previously only available in paper sections. The new transcriptions enabled full re-processing and imaging using modern techniques such SRME and Kirchhoff prestack imaging from field tapes. Fig 5 and 6 illustrate the dramatic uplift in image quality. The re-imaged seismic data quality is generally very good and detailed interpretation is possible from 2D (Note Seismic interpretation is presently being completed on this dataset), similarly amplitude anomalies are frequently seen on seismic data, and are very diagnostic of significant biogenic gas presence. II Geologically Driven Imaging Workflow The data analysis presented here in the Levantine and Adriatic was based upon a unique proprietary data processing workflow. The industry standard for re-working vintage data is often without consideration for extracting maximum petrophysical value. We propose that superior imaging results may be achieved by considering the complex interaction between the seismic experiment and sub-surface lithology. We call this process geologic driven imaging. Geologic driven model building of complex structures involves imaging in stages. In describing this process, Bednar (2009) correctly draws the analogy between imaging and model building as conjugate pairs where the definition of velocity is implicitly tied to the operator used to analyze the seismic reflection data. Selecting the best operators from the appropriate processing and imaging toolkit is paramount for laying the imaging groundwork in developing existing hydrocarbons or exploring new plays. The choice of imaging operator is ultimately tied to the assumptions regarding the propagation medium. In the most simple terms we often reduce this to seismic velocity. Even in pre-processing we rely on seismic velocity to generate brute stacks for both data qc and noise attenuation such as statics and Radon. The typical modern seismic processing workflow often includes several iterations of stacking velocity analysis intermixed with various pre-processing phases. In building a smoothly varying stacking velocity field it is important to take care to capture lateral base-line variations in regional background geologic trends; several iterations of 1-D manual velocity analysis may be required. Although numerical methods hold great sway, the gold standard is still manual velocity analysis for building the initial background trends predicated upon known geology and log analysis (where available). Once a background velocity model has been defined, only under specific conditions where spatial and temporal sampling is sufficient should automatic velocity analysis and tomography be explored for refining the velocity model. Wanton application of automatic velocity analysis where it is unsupported by temporal and spatial sampling of the data will result in non-geologic models and sub-par imaging. Model building predicated purely upon gridded velocity models may fail at impedance boundaries such as faults, erosional surfaces, or even sequence boundaries which may constrain matrix fluids and significantly alter rock properties. Although not a requirement in clastic environments, horizons may be used to isolate pressure regimes where a local grid based solution is more stable for resolving fine grained perturbations in lithology. Developing a refined model based upon an inter-play of layers, guiding horizons and local grid based solutions is a very interpretative process. Many false starts may be necessary before a proper solution is found which satisfies regional and sub-regional geologic trends. Often the seismic data itself will dictate the spatial and temporal limitations imposed by the field acquisition operator. The model complexity should be deliberately controlled by the choice of imaging operator (time or depth). Care must be given to considering whether the choice of imaging operator is able to handle the level of detail imposed by the geologic interpretation. The level of detail in the geology should directly correlate to the geophysical assumptions imposed by the choice of imaging algorithm. Developing the Geologic Image There is a long history of mathematics for modeling the propagation of seismic wavefields through the Earth. Time and depth processing or imaging operators come in a wide array of permutations depending on the theory used to model the seismic data. Under simple acoustic assumptions, time migration operators are based upon smoothly varying rms velocities whereas depth imaging requires the use of interval velocities which may impart significant detail in geologic structure. Fortunately linear relationships may be assumed for relating rms and interval velocities such that the geologic information generated in time may then be used as a guide for the depth imaging workflow. In our staged model building approach we leverage the value of each successively complex migration algorithm to extract the most value from imaging. As we improve the operator accuracy so does our ability to resolve finer features of the sediment structure. Initial focus is placed on estimating a simple background trend based upon vertical variations in velocity structure as a function of lateral position. Our understanding of the geology is tied to our understanding of the imaging as we transition from simple isotropic time migration to more complicated pre-stack depth imaging. For example, we often expect complex structure seen in a Kirchhoff pre-stack time product to improve and focus when the imaging operator is upgraded to Kirchhoff pre-stack depth (Figures 1 and 2). Further enhancement of the depth model might be improved by incorporating corrections for lateral and vertical variations in velocity related to spatial changes related to structure or stratigraphy. Such details in lithology may be incorporated into the appropriate seismic velocity model through simultaneous inversion of anisotropic properties. Older inversion workflows required holding one anisotropic parameter constant while searching for another. Care must be applied to ensure that the operator used to generate the input ensembles for tomography matches the operator employed for the simultaneous inversion. More often than not, casual assumptions are made to account for differences between the imaging and model building operators. For example, the operator employed in the tomography may be based on isotropic Kirchhoff theory while the imaging may be based upon reverse time migration (RTM). Such incongruities between model building and imaging may be overcome

3 with apriori care in established good ground rules for data resolution expectations. The seismic wavefield will often endure severe distortion in the presence of strong impendance contrasts (such as salt or gas). In the case of salt which is often exhibits faster seismic velocities than clastics, the wavefield is dispersed. In the case of methane (gas), which exhibits slower seismic velocities than clastics or carbonates, the seismic wavefield will collapse. In either case, the elastic nature of the impedance boundary will result in mode conversion which become difficult to image. In the case of mobilized salt, we resolve the background sediment trend first. Once we have defined the clastic background trend, we pick the top of salt horizon which is then used to generate an intermediate model where seismic velocities below the top salt are replaced with a constant salt velocity. As seen by the bit, salt is often heterogenous; however, the overall mineral properties as seen by the seismic wavefield are reasonably homogenous. By incorporating a constant salt velocity we are usually able to see the base of salt impedance boundary and pick a lower salt horizon. Once we replace our intermediate model with a salt top and base, we are then able to attempt to resolve the sub-salt model from the background trend using tomographic inversion methodologies. Salt bodies are often extremely complex structures which severely distort the seismic wavefield into multiple branches. Reverse time migration (RTM) is currently the standard for addressing complex multi-valued wave propagation through and beneath the salt. Outboard of salt, RTM is typically avoided in favor of more cost effective Kirchhoff migration. Exceptions to this case include examples of dirty salt which is present in the Levantine Basin. In the case of dirty salt, the modular approach to salt model building will fail. In this particular situation guiding horizons to separate slower homogenous clastics from the presence of of interbedded salt become imperative. Once isolated, we can then resolve the interbedded salt model by tomographic inversion. Imaging Limitations The chosen imaging approaches presented here occasionally do not resolve complex local anomalies such as igneous intrusions. Igneous rocks are often highly complex bodies with limited internal impedance boundaries for satisfying conventional seismic imaging assumptions. Often in such examples it becomes necessary to balance the imaging expectations of using seismic data to resolve geologic structure. Simple model building solutions often work best for resolving complex 3D seismic problems where conventional seismic velocity analysis fails. For example, in the case of the Eratosthenes Sea Mount, fast mafics may be modeled by inserting a high velocity slug (Figure 9). Although far from ideal, the stack results using such a practical solution may result in a general improvement over the original pure grid and layer based imaging. Alternatively, passive and active potential field methods may respond to other igneous properties to resolve the proper seismic parameters to incorporate in to the final imaging model. Hydrocarbon Implications Seismic data when properly imaged may be used not only for developing a control on structure, but may provide a direct relationship for linking the presence of hydrocarbons in the well bore to broad regional features. The relationship between seismic reflection amplitudes, lithology and matrix fluids has been well documented in the literature (Castagna, 1993, 2001). The viability of seismic data to be used for hydrocarbon detection is completely hinged upon the assumptions used to acquire, prepare, process and image the data used for hydrocarbon detection. Without care for the fundamental assumptions, seismic data may be limited in application to simple structural assessment. Although there is no such thing as true amplitude processing, we can begin with relative processing operators which preserve the overall bulk properties of the local seismic reflectivity. Using care to preserve relative amplitude properties it becomes possible to reduce the risk associated with relating seismic amplitudes to fluid properties whether they be brine or hydrocarbon. III Conclusions Levantine Basin The PSDM re-imaging effort of all the Spectrum data in the Levantine basin 2001 survey provided significant improvements over the original time processing. Improved noise attenuation has created uplift in producing a better starting product for imaging; more importantly, more sophisticated imaging techniques used in depth processing have produced a much clearer and more interpretable results across the entire survey. Most places have seen notable uplift below the salt layers and increased detail in the complex shallow structures. Improved resolution has allowed the identification of new play types by interpreters as well as helping better understanding of the deeper Cretaceous and Jurassic levels and structuring which is often unlear on the time data. It is generally agreed that the Eastern Mediterranean basin formed during the disintegration of Pangea; however, there is disagreement on the history and nature of the Levantine Basin and whether the rifting resulted in the formation of oceanic crust (e.g Garfunkle 1998, 2005, Robertson et al 1998) or stretched continental/transitional crust (e.g Vidal 2000, Gardosh 2005). Reported geophysical estimated of depth to the Moho (~20km vs ~35-40km for the true continental crust to the East) can be used to support either model. However, evidence from an examination of our modern seismic reimaged data leads us to believe that the crust of the Levantine basin is more than likely to be transitional in nature since no evidence is seen of oceanic crust on the deep seismic lines. Instead these re-imaged lines show a faulted terrain of at least Jurassic and possibly Triassic age. This is illustrated in Figure 4 which is from the south central portion of the basin and is approximately orthogonal to the basin margins (ie parallel to the assumed Mesozoic extensional direction). The history of 14,000m of Mesozoic to Recent sediments in the Levantine basin may be summarized as follows: 1. Disintegration of the Pangea supercontinent in the Permian to Middle Jurassic; the rifting being caused by stretching and thinning of the lower and uppoer parts of the lithosphere (Flexer et al 2000) [or if the ocean crust hypothesis is to be followed, the opening of the Tethyan ocean]. Deposition of clastics, carbonates and evaporates in grabens occurred during this period. 2. Formation of a passive continental margin from the Middle Jurassic to Late Cretaceous; characterized by normal faulting

4 sub parallel to the present day East Mediterranean coastline and basin subsidence during this period. The area was dominated by shallow to deep marine carbonate deposition, alternating with clastics on the basin margin. 3. Compression in the Late Cretaceous to Paleogene due to plate convergence. This leads to the inversion of the previously formed NE-SW grabens and to strike faulting due to differential plate motion. 4. Isolation of the Mediterranean sea from the oceans at the end of the Miocene (~6.8M years ago); its drying up and the deposition of up to 1500m of evaporates in the LB (Gradmann et al, 2005) during a ~1.5M year period known as the Messinian salinity crisis (Butler et al 1999). This was followed by inundation of the basin with oceanic waters and Pliocene to recent sedimentation. Evidence from a recent satellite seep study undertaken by Infoterra over the East Mediterranean sea correlated well with Spectrum s newly re-imaged seismic data has shown that seep features are widespread (over 200) and diverse (Peace and Johnson 2001). Often the seeps are seen to have a close correlation to Direct Hydrocarbon Indicators (DHI) seen on the seismic data and can be seen to be associated with clear migration pathways such as deep seated faults (Figure 10). DHI s seen on the seismic data comprise of gas chimneys, bright spots and flat spots. Numeous new potential hydrocarbon plays have been recognized in the newly re-imaged seismic data. Ranked from younger to older these include: Channel sands and mounds in the late Tertiary Sub-Messinian salt plays Intra-Messinian salt sand plays Anticlines and faulted anticlines in the Cretaceous to Tertiary Onlaps in the Cretaceous to Tertiary (including onlap onto the Eastern region) Fault and combined fault/stratigraphic tranps in the Cretaceous to Tertiary Large Inversion structures in the Cretaceous-Tertiary Carbonate build-ups (ie Rudist reefs) in the Cretaceous to Tertiary Onlap and drape onto Jurassic highs Jurassic carbonates in anticlines/horsts Jurassic carbonate buildups on highs Jurassic Karst plays Triassic plays Adriatic Sea Italy has been explored for many decades. There are many onshore gas fields in the Po Valley and the Apennine forefront., and many offshore Pliocene and Tertiary gas fields in zones A and B exist; there is extensive gas production both on and offshore. Production facilities are plentiful as there is good pipeline infrastructure. Oil may be found in the deeper parts of Po Valley and onshore in the Southern Appenines as well as the southern part of the offshore Adriatic region south of Gargano peninsula.. Both Onshore and offshore, the main structural elements of interest are located in and around the Apennine overthrust front. A large number of both structural and stratigraphic play types surround the overthrust structures in the basin. A wide range of proven gas and oil plays ranging from reservoir sands within the overthrust units to sands around/over/pinching out around thrusts have been proven and are in production There are some recent multi-tcf gas discoveries in ripple fold and stratigraphic plays and numerous gas fields producing from Pliocene and Tertiary Turbidite sands. Aquila oil field in the South Adriatic contains heavier oil in carbonates of Cretaceous and Jurassic age. There are several reasons for the Italian Adriatic exploration decline. More interest has been refocused on emerging onshore oil plays and other global opportunities. Local delays and bureaucracy have slowed production especially since the Macondo disaster, with subsequent. increased interest in environmental implications of oil and gas exploration which have raised environmental concerns.. The lack of availability of suitable offshore seismic data especially regional data has been a significant problem for new companies wishing to explore the region; close to shore within 12 miles it is currently not possible to record new seismic data. Conclusions The Levantine basin is a large thick sedimentary basin with rocks most likely from the Triassic to Recent age which has exhibited passive margin processes and sedimentation over a 100 My interval. Over this period, subsidence, uplift and tectonic processes have created a favorable regime for hydrocarbon generation and trapping. Offshore Cyprus, Lebanon and Syria is very much an underexplored petroliferous province with numerous plays from the Triassic to Tertiary in shallow to deep water. These plays have been highlighted by newly re-imaged modern seismic data whose availability will spur on exploration efforts in the area and aid the authorities and oil companies in future petroleum licensing rounds. In comparison, the Adriatic Sea is a proven hydrocarbon province with potential for both oil and gas. There are a number of structural and stratigraphic plays with ties to important wells. The Italian licensing structure is very open. Many missed opportunities exist; there are a number of undrilled structures. The newly re-imaged vintage Adriatic seismic data presented hear demonstrates that there are still many opportunities to explore for hydrocarbons in the Adriatic. A new regional infill seismic survey is planned by Spectrum to complement this reprocessing project. Data is expected to be acquired in 2012 over much of the Italian Adriatic Sea region. Using a geologically driven imaging workflow for both the Levantine basin and Adriatic sea, a high quality imaging product has been generated in very difficult structural regimes. The imaging products generated from the vintage multi-client dataset have been successfully used to add value towards understanding the exploration potential of the mature Adriatic hydrocarbon province and the newly discovered Levantine Basin. References Bednar J.B Modeling, Migration and Velocity Analysis in Simple and Complex Structure, Castagna, J, Petrophysical Imaging using AVO. The Leading Edge, pp

5 Castagna, J, Recent advances in seismic lithologic Analysis, Geophysics, 66, pp42-46 Peace, D. and M. Johnson, The Regional Structure, Some Play Styles and the Exploration Potential of the Eastern Mediterranean and Levantine Basin Area, Proceedings of the Geological Society of London New and Emerging Plays in the Eastern Mediterranean Peace D, and M. Johnson, The Adriatic Sea a Good Time to Revisit This Prolific Region of Europe, Proceedings of the Geological Society of London New and Emerging Plays in the Eastern Mediterranean Peace D, The Hot New Exploration Region, GeoExpro, 8, 1, pp Stieglitz, T., Spoors, R., Peace, D. and M. Johnson, An Integrated Approach to Imaging the Levantine Basin and Eastern Mediterranean, Proceedings of the Geological Society of London New and Emerging Plays in the Eastern Mediterranean Stieglitz, T., 2011, Picture Perfect, Oilfield Technology, 4, 2, pp Figure 1: Regional Tectonic Features of the Eastern Mediterranean.

6 Figure 2: Main Strucutral Elements of the Adriatic It would be good to use aq different map which doesn t have the A and C areas marked on it this was an old one cribbed from a freind

7 Figure 3: Open Adriatic Acreage Please add in the second map which shows the area south of this one

8 Northern Apennines Central Apennines Southern Apennines Figure 4: E/W Structure across the Italian Adriatic Sea

9 Figure 5: Scan of old data Integrated Imaging in the Eastern Mediterranean

10 Figure 6: Fully Reprocessed Line shown in Figure 5 Integrated Imaging in the Eastern Mediterranean

11 Integrated Imaging in the Eastern Mediterranean Figure 7: Kirchhoff Pre-stack Time Migration Figure 8: Kirchhoff Pre-stack Depth Migration with interpretation

12 Integrated Imaging in the Eastern Mediterranean Figure 9: Eratosthenes Sea Mount

13 Figure 10: Examples of amplitude anomaly leads Integrated Imaging in the Eastern Mediterranean