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The Nile Delta basin is the most prolific, prospective gas and condensate province in Egypt. Nile Delta is the main gas producing province in the northern part of Egypt with approximately 62 TCF proven reserve. The geology and the entrapment mechanism of Nile Delta are still under discussion because the delta does not have any outcrops of old rocks where it is covered by the Holocene soils. The area of study is Taurt Field which located in the Ras El-Barr concession approximately 72Km from offshore in the East Nile Delta area at a fault block to the northeast of Ha’py Field and northwest of the Denise Field in 108 m water depth.
The main aim of this study is to integrate the well logs evaluation,3D seismic data interpretation and seismic attribute analysis for constructing 3D static reservoir modeling including facies, petrophysical and saturation models and its impact on the hydrocarbon reserve estimation for sand reservoir units in the eastern offshore Nile Delta. This objective has been accomplished by evaluating well logs in Taurt wells (T-01, T-02, T-03, T-04 and T-05) for petrophysical analysis and facies discrimination of S10, S20 and S30 reservoir units in Mit Ghamr Formation. Also this aim has been accomplished by 3D seismic data interpretation, mapping different seismic attributes and 3D reservoir modeling. These tasks were followed by statistical correlation between the petrophysical results, seismic attributes and reservoir modeling to evaluate lithology and hydrocarbon distribution within these reservoir units.
The available data set for this study consists of borehole and seismic data. Borehole data include a full set of well logs for five wells in addition to core data for two wells. The seismic data is reflectivity (MAZ volume) with check-shot data of T-01 and T-02 wells. Techlog (2013.2), Petrel (2014.1), HRs (10.0.2) and OpendTect (6.0.0) Softwares have been used in this study.
Well logging analysis of the S10, S20 and S30 Mit Ghamr reservoir units in five wells in the study area led to the following conclusions:
1. from facies discrimination using GR log analysis; sand reservoir units are deposited in form of sand bar in shallow marine depositional environment. S10, S20 and S30 reservoir units have low shale content (0 to 4%), high effective porosity (30 to 40%) and high gas saturation (40 to 80%) with main lithology is sand with shale intercalations.
2. from MDT analysis, there are vertical connection between S20 levels (S20.1, S20.1-Base, S20.2, S20.2-Base, S20.3 and S20.3-Base) and S30 levels (S30.1, S30.1-Base, S30.2, S30.2-Base, S30.3 and S30.3-Base). So Pleistocene Mit Ghamr Formation has three pay zones; pay zone 1 (S10) with GWC equal 1170m TVDSS, pay zone 2 (S20) with GWC equal 1370m TVDSS and pay zone 3 (S30) with GWC equal 1450m TVDSS.
3. For pay Zone 1(S10 unit), it has low shale content (0%) is in NW and SE part of the study area at T-03 and T-05 wells, while shale content (3%) increase in southern part of the area at T-01 well. Highest effective porosity values (37%) are at T-03 and T-05 wells in NW and SE part of the study area, while effective porosity values (31%) decrease toward southern part of the area under investigation at T-01 well. Gas saturation (60 to 84%) distribution of S10 unit increases toward SE direction at T-05 well. Net pay thickness distribution map shows the variation in effective thickness values from minimum value (24m) in NW part at T-03 well where sand bar reservoir is pinched out and a maximum value (33m) in SE part of the study area at T-05 well.
4. For pay Zone 2 (S20 unit),shale content (4%) increases in SE direction at T-01 and T-05 wells, while shale content (0%) decreases in the central part of the area. A lowest effective porosity value (30%) is in NE direction at T-06 well, while highest effective porosity values (42%) toward SW part of the study area. Gas saturation (83 to 95%) distribution of S20 unit increases toward SW direction. Net pay thickness distribution map shows the variation in effective thickness values from minimum value (5m) in North direction at T-07 well and a maximum value (150m) in southern part of the study area at T-01, T-04 and T-05 wells. So sand bar reservoir units is pinched out toward North direction of the study area.
5. For pay Zone 3 (S30 unit), lowest shale content (0%) is in SW part of the area under study at T-03 well, while highest shale content (2%) is at T-02 well in North direction. Highest effective porosity values (39%) increase at T-06 well in NW part of the study area, while effective porosity values (27%) decrease toward SW direction at T-03 well. Gas saturation (48 to 60%) and net pay thickness (30 to 38m) distribution of S30 unit increases toward North direction at T-06 well. So S30 unit is pinched out toward southern part of the area under investigation.
3D seismic data interpretation involved DHI analysis for recognition the presence of gas on seismic section, seismic interpretation for detecting geometry and fault patterns of sand reservoir units, in addition to mapping horizons and faults. To start seismic section interpretation, synthetic seismogram was constructed for seismic to well tie. Horizon mapping included mapping of six different horizons and the faults. These horizons are Top and Base of S10, S20 and S30 reservoir units. Horizon maps have been constructed in time domain and in depth domain.
Seismic interpretation concludes the presence of three major normal faults in NW-SE and NE-SW directions which affected on all reservoir units. Four ways dip closure for S10 and S20 units with maximum thickness (S10 equal 48m and S20 equal 180m) located in southern part of the area due to sand deposition in accommodation space created in the hanging wall to the Taurt south bounding fault trending in NW-SE direction. Two way dip closures for S30 unit with maximum thickness (60m) located in the central part of the area.
Seismic amplitude extractions focused on the following derived attributes:
• Time-based (isochron) attributes.
• Amplitude-based (RMS amplitude and maximum negative amplitude) attributes- Physical attributes.
• Post-stack instantaneous attributes (trace envelope) - Physical attributes.
• Waveform-similarity (variance volume) attributes - Geometrical attributes.
• Frequency-based (spectral decomposition) attributes.
• Geo-body extraction attribute
Isochron maps have been constructed for the Top and Base S10, S20 and S30 units by subtracting the base interpolated horizon from the top interpolated horizon of the mapped events. They reflect the changes in thickness of these three units in the study area. S20 unit owns Maximum thickness, while S10 unit holds Minimum thickness.
RMS and Maximum negative amplitude maps were created for Mit Ghamr reservoir units by using the seismic volume for the Top S10, S20 and S30 with time widow 10 msec. below and above it. These maps clearly show amplitude anomalies ”bright spots” due to gas effect and sand fairways at the top gas sand units of Mit Ghamr Formation aligned in NW-SE direction.
Trace envelope attribute is achieved to help imaging of sand bar in Mit Ghamr Formation, faults pattern affected on it and lateral extension of sand reservoir units.
Variance attribute maps generated using the second-generation coherence algorithm at different time slice; in the start (S10), in the middle (S20) and in the end (S30) of sand bar. These maps show the termination of high-coherence gas-charged reservoir units against the southern bounding major NW-SE fault. Also lateral extension of the sand reservoir units is in NW-SE direction.
Spectral decomposition (SD) is a technique that breaks down seismic signal into narrow frequency sub-bands. When these sub-bands are examined in a spatial context (i.e., plan view of a 3D survey) they reveal interference that is occurring across the available bandwidth of signal so that it makes use of much lower seismic frequencies to image the reflective nature of the subsurface rock mass. Such decomposition provides greater resolution and detection of the layer stacking heterogeneity, boundaries, and thickness variability than are possible with traditional broadband seismic attributes. A tuning cube has been created for each interval (S10, S20 and S30 reservoir packages) by using SD-tuning cube of OpendTect6.0.0 Software. The frequency ranges that were used in tuning cube calculations were set to 5-65 Hz. The software extracts and flats this slab of data then discrete Fourier transform was applied to this slab of data to produce the tuning cube.
from the amplitude spectrum window the seismic has been split into different frequency ranges, as Low Frequency range (5–25 Hz), Medium Frequency range (25–50 Hz) and High Frequency range (50–65 Hz). An amplitude maps has been created at each frequency at 15 Hz increments. from observations of these maps, the most representative maps for the reservoir fairway definition are at frequencies 5, 35 and 65 Hz. Red Green Blue (RGB) color blended maps were created mixing these three frequencies into the same map. A set of RGB color blended maps for S10, S20 and S30 reservoirs have been created. from the RGB maps, a number of well-defined reservoir fairways more or less with a consistent NW-SE trend.
Geo-body extraction attribute was creating by blending different frequency cubes at 5, 35 and 65 Hz then adjustment opacity threshold value and amplitude window. Geo-body extraction attribute delineate structural, stratigraphic features, lateral and vertical extension of S10, S20 and S30 reservoir units.
By combining between well logging analysis and seismic interpretation;3D static reservoir modeling was carried out including structure, facies and petrophysical (Φeff and Sw) models. These models clarify geometry imaging, faults framework, facies and petrophysical parameters distribution within sand units in Mit Ghamr Formation. Also fluid contact model give general idea about hydrocarbon volume in place.
Petrophysical evaluation and log analysis of Taurt wells in the study area shows the presence of hydrocarbons within the Pleistocene Mit Ghamr sand units (S10, S20 and S30) with good reservoir parameters. The analysis of the Modular Dynamic Tester (MDT) pressure data is concerned mainly with locating the different fluid contacts, vertical connection between sand levels within S20 and S30 units and determining the pressure gradients of the gas-bearing zones. Observations on the different types of seismic attributes and reservoir modeling results led to the following conclusions:
1. There is good negative correlation between VSh (shale volume) and RMS amplitude where areas of low VSh content correspond to areas of high amplitude anomalies due to gas saturation.
2. There is good correlation between effective porosity and RMS amplitude because areas of high effective porosity correspond to areas of amplitude anomalies.
3. There is good correlation between gas saturation and RMS amplitude where high amplitude anomalies reflect areas of high gas saturation.
4. There is good correlation between net sand thickness and RMS amplitude where areas of high sand thickness match with high amplitude anomalies.
Final step is hydrocarbon reserve estimation for OGIP calculation for each sand unit using 3D reservoir models and petrophysical parameters. It is clear that the southern closure at S20 unit holds the highest volumes of hydrocarbons (726 bcf), while the central closure of S30 unit hold less volumes (47 bcf).