3rd EAGE North African/Mediterranean Petroleum and Geosciences Conference and Exhibition

This oral presentation discusses a holistic set of ingredients used to deliver deep water gas exploration success in the Nile Delta of Egypt. An exemplary of BP's renown exploration method as applied in North Africa.

The paper describes the regional tectonic setting and evolution of the Levantine basin in the Eastern Mediterranean. Thereafter the majority of the paper focuses on the hydrocarbon prospectivity and play types in the basin derived from an interpretation of 20,000 km of modern, high quality seismic data.

Our analysis of the Libya region was built on foundation of previous proprietary and published studies and employed recent proprietary research on concepts and tools and newly available data and a new age model that included significant thicknesses of Mesozoic strata offshore. These allowed calibration of the seismic character of source and reservoir facies and their stratal packaging in proven onshore areas, and extrapolation to similar seismic facies & stratal packaging seen in offshore data. We concluded that the Libya region was in a favorable setting for accumulating source, reservoir, and seal-prone strata throughout the Mesozoic and Cenozoic, due to the: 1) common occurrence of shelfal water depths and paleogeographic restriction, 2) low-latitude setting, 3) warm, dry to sub humid paleoclimate, commonly with low seasonality, 4) some coastal upwelling, along with water mass mixing under ITCZ & tropical cyclones, 5) dominantly quartz-sand-prone provenance lithotypes, and 6) late development of shelf-bypass clastic dispersal systems. The incorporation of paleo-environmental reconstructions is a powerful tool in exploration, enabling evaluation of numerous frontier areas in less than 10 weeks of work by using our fundamental understanding of the dynamics of basin formation integrated with the regional paleo-environmental context.

Mesozoic tectonism in NE Africa was locally, but significantly, impacted by older Neoproterozoic and Hercynian structures. During the Permo-Triassic to Neocomian, the dominant control on deformation was the newly formed Neotethyan margin to the north. From the late Aptian onward, stress fields represented the combined effects of distant plate boundaries, producing both extensional and compressional deformation.

The NC41 area belongs to a polyphasic pull-apart basin in the western side of the Libyan offshore. The early stage of the basin was upper Cretaceous in age. The local troughs of the pull-apart were affected by restricted conditions that gave origin to the cretaceous source-rock (Kef Fm.). The deposition of the cretaceous source is a peculiar feature of the deepest part of the Sabratah-Misrata basin. The geochemical properties and evolution of the cretaceous source led to the generation of gas that largely contributed to most important accumulation of the area. The trap-forming processes started during the late Cretaceous transpressional phase. The early faults were reactivated later, sometime evolving into attractive exploration features. The present structural style, characterized by faulted anticlines, results in particular from late Cretaceous and Oligocene events. The two major exploration plays are the Eocene shallow-water carbonates and the Cretaceous carbonate platform. The former is the most successful play of the area. The latter is presently largely unexplored in spite of the close concurrence of effective source and reservoir units but it shall represent a challenging target for next future exploration.

Basin modelling results can be very sensitive to (paleo-)temperature uncertainties. For frontier basins, in particular for deep water settings, the thermal signature of the basin is poorly constrained, as data from wells are lacking. This may lead to wrong heat flow assumptions if these are extrapolated from the shallow offshore or onshore. Furthermore large uncertainties can exist when dealing with constructing paleo-heat flow. The potential errors in spatial and temporal extrapolations are especially large in settings with strong spatial and temporal variations in tectonic regime. This is in particular true for the Mediterranean and North Africa. Heat flow modeling can be improved considerably through numerically modeling lithospheric processes underlying basin deformation. For this purpose we have developed a probabilistic tool which is capable of calculating tectonic heat flows calibrated to observed data and which can be used as input for maturation modelling. For various basin settings we will show the effect of adopting tectonic heat flows for improving spatial and temporal constraints on the temperature and maturation history in deep water exploration settings. Case studies include the Morrocan Atlantic margin and the Valencia Through (Spain).

In Basin and prospect evaluations we always deal with the assessment the Petroleum System elements. The Petroleum System is defined as the sequence of all the geological combined elements and processes which, from a source rock to one or several reservoir / seal pairs and using a common plumbing system leads to the formation of a genetically related family of hydrocarbon accumulations. We need to improve the seal efficiency studies: investigate the sealing sections as carefully as we do for reservoir intervals by a detailed mapping of their petrophysical parameters, thicknesses, the occurrence of hydrocarbon shows from mudlogs etc. We must also progress on hydrocarbon type predictions: We can use sophisticated simulators and calculators but only as sensitivity tools thanks to computers becoming more and more powerful, but we must not forget the geological and naturalist reasoning for helping to find new hydrocarbons! We need to come back to the geologic reflexion, following the key steps of the evaluation workflow and gather and integrate the knowledge and data even it becomes more and more complex to manage.

Fluid inclusions can provide hard evidence for the presence of hydrocarbons in a ‘dry’ hole and fluid inclusion screening of cuttings forms a routine part of a dry hole analysis in many oil companies. Subsequent microscopic and chemical analyses provide additional compositional information via cryo-optical and quantitative fluorescence techniques, constrain the timing of migration or reservoir filling (from paired analyses of coeval petroleum and aqueous inclusions) and can identify the source of the hydrocarbons via GCMS and/or isotopic methods. A particularly useful technique is compound specific isotope analyses (CSIA) of the gas components of the fluid inclusions. For instance, in many basins in North Africa and the Mediterranean, there is uncertainty about the presence of the Silurian Tannezuft (Qusaiba) source rock. This source rock was deposited after the Silurian deglaciation and source rock quality depends on the anoxia and stratification of the water column, which varied regionally with the topography at that time of deposition. With CSIA analyses of fluid inclusions, the presence of Silurian generated gas is easily recognized from the carbon isotopes that are characteristic for the Silurian generated gases. In this presentation, we describe recent applications of the fluid inclusion geochemistry from Libya, Syria and Oman.

Identifying of source rocks is essential for the evaluation of the petroleum potential of the sediments dominated by terrestrial organic matter in exploration areas. This will improve the modeling of the generation history of the source rock sediments.The knowledge of the petroleum generation and the characteristics of the source rock sediments is one of the main factors in the exploration success of an area. Geochemical data were used to examine the amount, type, and maturation of organic matter and Hydrocarbon potentials of source rocks within the Block NC98. Block NC98 source rock intervals have been identified in Lower and Upper Cretaceous group. The source rocks have been determined by identification of various organic Geochemical and palyonologyical methods and techniques. The data obtained indicates that both petroleum systems have a very good source section with high potential for oil and gas generation. Both petroleum systems have organic facies derived from marine and terrestrial organic input. This was confirmed by the optical examination, and organically rich TOC. The Geochemical analysis including carbon isotope, GC, and GC - MS indicates that the Hydrocarbon extracted from Lower Cretaceous group have a positive correlation with Hydrocarbon found in the Upper Nubian sandstone.

Forty eight high resolution stratigraphic sections and more than 850 thin sections were used to study the Eocene of Cyrenaica. Sections are located on the northern limb of Al Jabal al Akhdar inversion anticlinorium that formed a series of submerged Cretaceous structural highs and islands. These played an important role in the development of the Eocene nummulitic ramp complex. Evolved regionally parallel facies belts consisted of outer ramp mudstone clinoforms and mass transported facies, mid-ramp nummulite facies and inner ramp miliolid-orbitolites, coral-coralgal and skeletal facies respectively. Progradation of these belts led to an upward shallowing mega-sequence constituting Apollonia and Dernah Formations. It consisted of three correlatable nummulite dominated sequences in Ras al Hilal area. The top two of which pass eastward into structurally controlled reefal-coralgal-discocyclinid dominated facies. Reworking of nummulite bodies by waves and currents over structural highs led to improvement of primary porosity. Syndepositional reactivation of the structures not only triggered mass transport of the mid-ramp deposits, but also controlled nummulite body geometry, internal heterogeneities and diagenesis by spatially shifting high-energy and subaerial exposure zones through time. There no single nummulite ramp model that would characterize this active inversion setting, as depositional parameters changes in space and time.

Base on 3D seismic analysis an outcrops occurence an extensive reefal barrier is described in the Gabes Gulf including all the morphological elements that are known in the modern complexes.

The Trias Carbonaté overlying the TAGI is present in the Berkine Basin and comprises mainly dolomitic shales, with interbedded dolomite layers. The interval is essentially non-reservoir, although thin channel sandstones (often oil stained) are occasionally encountered. Some fluvial terrigenous input is still important at this stage, with the influence of sea level fluctuations and probably regional tectonic events. Sandstones are fine to medium-grained and very thin in the central part of Berkine Basin (where marine conditions are dominant), but they may become thicker to the south of the basin (Turner et al., 2001). Based on core analysis, these sands are interpreted as high sinuosity fluvial/estuarine channels cutting a coastal plain. The purpose of this study is to identify vertical changes in facies, depositional environments and their distribution, sequence stratigraphy and relative sea level controls (Sabaou, 2003). Correlation of the stratigraphic successions with the regional sequence stratigraphic framework, based on 120 wells (Turner et al., 2001), shows that the vertical change in coastal plain character can be related to relatively high-frequency base level cycles that are expressed as transgressive-regressive marine cycles in downdip areas.

El Feel reservoir is characterized by high impedance fluvio-glacial Ordovician sandstone sealed by soft shales. Recognition of seismic responses at Top reservoir cannot provide information on reservoir quality due to simultaneous changes of reservoir and sealing acoustic properties. Acoustic inversion, integrating well and seismic data was therefore a crucial step to derive a 3D seismic reservoir characterization and a robust prior model is required. A limited number of the utilized wells are vertical and the rest are mostly slanted (borehole dips >40°), therefore acquired velocity measurements are mostly biased by shale anisotropy. Also input seismic data fidelity is an issue; it was managed by adopting CRS-stack volume, superior for interpretative and quantitative uses. A geostatistical-based proprietary methodology was developed to integrate seismic and well impedance trends, horizons interpretation, and conditioning wells. Thomsen’s anisotropy parameters estimates from well data were used to reduce velocity measures to vertical wells conditions. The followed approach improved data reliability for Petro-Acoustic analysis, well-seismic tie, prior model generation, and inversion. Impedance-Porosity analyses suggested inversion results calibration feasibility by linear or non-linear (Neural Network) approaches. Output Porosity cube, useful for reservoir modelling, captured sedimentary features highlighted by visualization techniques.

The use of outcrop analogs for constraining stratigraphic interpretations has often been presented for mature fields with seemingly inexhaustible data and tight well spacing. In contrast, a viable fourth-order stratigraphic interpretation of a mixed carbonate siliciclastic system is proposed for a Sirte Basin field with only twenty wells on 640-acre spacing. The objective was to squeeze as much information regarding the depositional environments from scarce well data, integrate observations within an outcrop analog, and develop a play concept to prioritize a potential field acquisition candidate. The result is an outcrop-driven depositional model and stratigraphic framework that honors observations made from core, thin sections, accommodation trends, and paleogeographic setting. A “best fit” analog was identified from Albian outcrops along the Lower Canyons of the Rio Grande in the Big Bend region of Texas. Lithofacies, fossil assemblages, and accommodation trends were analyzed for comparison and were found to be remarkably similar. Actual and comparative evidence suggests this field was situated atop a shallow, current-swept, intrabasin platform, characterized by localized ramps onlapping basement highs. Clastic-rich, radiolitid buildups and associated grainstones developed along the inner ramp, onlapping basement highs, and grade offstructure into chalky Inoceramus-globigerinid wackestones and shales.

Case Study - The Triassic Formation of the Hassi R’mel Field (Algeria). In the sedimentary recordings, clays, if inherited can give a fundamental a reliable and fundamental indication on the continental contributions. The examples studied come from central sahara wells of various basins. The triassic shale sandstone formation of the central sahara is about 200 meters thick, made of two series of the shale sandstone separated by volcanic rocks. The clay fraction was studied by using diffractometer and the following results were obtained: - from the point of view of the clay fraction constitution a) in oued mya basin the principal minerals are illite, chlorite and mixed layers; b) on the other hand in the berkine basin, there is an association of illite, chlorite mixed layers and kaolinite -from the point of view of the characteristic of clay: during the interpretation of the diffractogramms and by superimposing them we remark that: the intensity of illite peak (I001) and chlorite peak (I002) vary considerably with the depth. The peak variation does not occur at the random. In fact, as observed the intensity of the illite peak (I001) decrease from the bottom to the top in a metric level or profile. Thus, it was observed that at the bottom of the profile, illite shows a high intensity (I001) peak, with a good cristallinity, and as one goes up in the profile(i.e.a decrease in the depth) the peak intensity becomes weaker and sometimes, nothing can be noticed on the diffractogramm. The explanation of the loss of the intensity is not due to the reduction in the partiules but to the worse cristalline organisation of the crystalline system. Indeed the climate which characterized the triassic period is arid or semi arid, he is marked by alternation of wet and dry period. The state of the clay fraction, which depends of the source of the sedimentary material that is homogenous in the sedimentary environment system. In period of dryness, the evaporation is intense, concentrates the solutions which become more agressive and start to initially deteriorate the sedimentary unit with the contatc water sediment then penetrates in the sedimentary unit according to its permeability. This proves that the substance analysed is amorphous by XRD, revealing thus a high weathering of the clay fraction. This decrease in the intensity of the I001 peak of illite from the bottom to the top of the level is spectacular. This phenomenon is observed both in the clay fraction content in the sand and shale samples. The repetition of this phenomenon in the space et time and at the regional scale shows the regularity of the climate.This evolution of the clay fraction is similar to the present day pedogenetic one. Thus, degradations or tranformations by degradations seem to be an overall mechanism in the meteoric alteration and pedogenetic process. This permits us to define sections in the sequence called genetic sequences.

The use of high-resolution bio- and chronostratigraphy to delineate and subdivide the strata of the Sirt Basin. Investigations utilizing varied microfossil data and unique biostratigraphic software techniques to construct chronostratigraphic frameworks for use in exploration and exploitation in the Sirt Basin. Identification of depositional sequences and correlation and calibration to other sedimentological and stratigraphic interpretations.

Understanding the distribution of fractures in carbonate reservoirs can greatly improve modeling of production rate and flow anisotropy. Seismic anisotropy may be a cost-effective technique sensitive to open fractures affecting flow, and can provide volumetric information on fracture properties. This talk focuses on azimuthal AVO effects at interfaces between fractured and unfractured rocks. We calculate AzAVO attributes for a Cretaceous limestone reservoir in East Texas. The workflow integrates inversion results with rock physics, forward seismic modeling, dipole sonic and image logs, and core to interpret azimuthal attributes relative to geology and production data. AzAVO inversion results for the field show anomalies that broadly tie to fracture indicators and are geologically reasonable. Anisotropy magnitude aligns with many NE-trending faults, which is consistent with fault-related fracturing. AzAVO orientations generally parallel ENE-trending fractures in core, maximum horizontal stress from image logs, and fast-velocity direction from a dipole sonic log. However, moderate to poor seismic data quality and sparse geologic well control limit our confidence in quantitative fracture prediction. Overburden effects manifested by amplitude dimming degrade AzAVO inversion quality over the structural crest and highlight the sensitivity of the inversion algorithm to amplitude artifacts.

A thin but complex layer of partially eroded anhydrite and other facies lie at a depth of around 3km across large areas of the Nile Delta, offshore Egypt. Wavefield distortion, attenuation and the generation of complex multiple diffraction noise cause the quality of the underlying seismic image to be highly variable. In this paper we describe the problem and then demonstrate how multi-azimuth seismic is able to improve the Pre-Messinian image

The case history presented here is for a desert environment and contains a strong lateral velocity variation (up to 1500 m/s) across a major fault with a throw reaching 3 km. The results from this study show that the new velocity model buiding approach improved imaging in the shadow zone of the fault where traditional methods failed.

A seabed logging R&D study was conducted on the Troll Field in December 2003 – January 2004. Different EM waveforms and frequencies were tested to optimize the hydrocarbon response from this shallow water gas and oil field. The survey consists of 41 receivers, deployed along a line crossing the Oil Province, the Western Gas Province and the Eastern Gas Province of the Troll Field. All receivers recorded two orthogonal components of the horizontal electric field, and 12 receivers measured in addition two orthogonal components of the horizontal magnetic field. The R&D study was carried out as an attempt to qualify seabed logging for shallow waters (less than 500 m) and optimize acquisition parameters for such cases. Up until now the marine controlled source EM method has been qualified for use in deep waters (more than 1000 m water depth) mainly because of the disturbing influence from the air wave in shallower water areas. The Troll Field seabed logging data is of excellent quality and helps in solving problems related to shallow water applications of this method.

has been created from the available well, seismic and published map data, the gravity effect has been forward modeled and subtracted from the observed gravity. The remaining gravity field has been inverted to derive a first basement depth map. The results of this work will be used in basin-SR charge modeling which should further our understanding of the Sirte basin’s petroleum system.

With the seismic and rig markets being very tight in Libya, and in light of the 5 year EPSA-IV licence period, any chance to fast-track the work programme should be examined. For BG Libya, the ‘sparse’ 3D acquisition design discussed in this paper should allow acquisition of high quality 3D data, whilst retaining an efficient survey acquisition schedule and pricing. Use of the existing 2D data and acquisition of a test line ahead of the survey design was a great advantage in the design optimisation, and should be considered as best practice in ‘sparse’ 3D design.

Seismic survey design balances the complex interaction of many factors against the objective of delivering a cost-effective and fit-for-purpose dataset, on time, to the seismic interpreter. The availability of new technology allows reevaluation of this balance of factors to best realize the value the technology can provide. Traditional assumptions in terms of fold requirements and source and receiver effort can be revisited. A case history is presented from a 2000-km2 3D Vibroseis survey in the Western Desert of Egypt. Availability of a high-channel-count point-receiver acquisition system and associated source and processing technology allowed a significant rebalancing of the field acquisition parameterization relative to an existing, successful, conventional technique. The resulting dataset, though acquired with a reduced field effort, compares favorably with the existing data both geophysically and economically.

Krechba is one of eight fields in the In Salah Gas Development in Central Algeria, operated jointly by BP, Sonatrach and Statoil. The field is in the northern part of the acreage retained for development, and consists of reservoirs in the Carboniferous and Devonian. The Carboniferous, Tournasian C10.2 sands are the main contributor to the gas production to date, being developed for first gas in 2004. The original field discovery made in 1957 was based on 2D seismic. Due to uncertainty on the top reservoir and the thin reservoir, a 3D seismic dataset of approximately 600 km2 was acquired in 1997. Seismic amplitudes were used to define accurately the presence and quality of the estuarine sands very well developed over the field. This reservoir consists of several stacked thinner sands, at depths ranging from 2800 m to 3400 m. With this challenging task, to improve the seismic resolution and the seismic quality lead to reprocessing of the 3D volume which was finalized in 2006. This paper reviews the main steps of the seismic depth conversion process with the use of seismic velocity on this field using the reprocessed seismic, and draws some conclusions regarding the future development of the field.

A worldwide look at long-term trends reveals that new discoveries of conventional oil fields are declining while demand for oil is estimated to increase approximately 1.5% per year from the current levels of approximately 85 million bopd. A portion of the increased demand will be met by increasing supplies from non-conventional deposits but the majority will need to come from improved rates and recovery in conventional oil fields. Industry experience and performance to date indicates that while considerable opportunities exist, there will also be fundamental challenges facing our ability to increase light oil recovery. This means increasing attention on fundamental parameters driving increased field offtake rates and recovery factors. This paper will discuss both basic technical parameters that need to be addressed and the IOR/EOR technologies that can be deployed (or developed) to meet this challenge. It also covers the pros and cons of various types of enhanced oil recovery injection fluids. Attributes of enhanced recovery cost elements that need to be considered in fiscal regimes that are mutually beneficial to both host governments and the international partners will also be summarized.