الفهرس 
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Abstract
The Aghar oilfield constitutes a part of the West Razzak concession. It is located in the Western Desert, about 70 km south of the Northern Coast between Longitudes 28º 18’ and 28º 24’ E and Latitudes 30º 27’ and 30º 30’ N along the NE-SW trending of Qattara-Alamein ridge in the Alamein basin, Western Desert. Egypt.
The structure of the area is complex three-way dip fault closure at top Bahariya level. The main clastic reservoir levels belong to the Bahariya Formation of Cretaceous age.
This study focused on characterization of the Upper Cretaceous clastic reservoir of Bahariya Formation in Aghar-4 field by using an integrated study of the petrophysical analysis of well logging data and the sedimentological analysis of five core sections from well Aghar 4-1, which are 364 ft long have been recovered from depth interval between 5618 ft to 5982 ft MD.
The petrographical analysis of the selected samples from different lithofacies allowed their classification in order to their majority as subfeldspathic wackes, glauconitic subfeldspathic arenites, kaolinitic subfeldspathic wackes, glauconitic sideritic subfeldspathic arenites, pyritic subfeldspathic wacke, subfeldspathic arenite, quartz wacke, bioclastic calcitic subfeldspathic arenite, sublithic arenite, glauconitic sublithic arenite, glauconitic quartz arenite, glauconitic sublithic wacke, kaolinitic subfeldspathic arenite, bioclastic sideritic green sand, bioclastic green sand, sideritic green sand, molluscan sandy wackestone, sandy mudstone, ooidal sandy packstone, sandy dolomitic wackestone, molluscan dolostone and pelletal sandy dolostone.
The detailed core petrographical analyses were applied to total 38 samples including 32 clastics and 6 carbonates samples from three reservoir levels, Upper Upper Bahariya, Lower Upper Bahariya, and Upper Lower Bahariya, which are belonging to Bahariya Formation. All samples of clastics levels are very fine to fine grained and good to moderately sorted. More or less half of the samples are characterised by low cement and detrital matrix amount, while the other half generally have a variable content of matrix, occasionally very high, and sometimes combined to a high amount of authigensis. A part from some Lower Upper Bahariya and one Upper Upper Bahariya samples that are mainly constituted by abundant glaucony, associated only in one case even to a high amount of carbonate lithics.
from the compositional point of view, the main component is quartz, a part from the samples that contain a large amount of carbonate, that represent more or less 25% of the total number of samples. The carbonate can be either calcite or siderite; just in one case, the carbonate is dolomite. Clay and mica content is variable, even though only few samples can be considered clays, as they contain more than 50% of clays. The feldspar and plagioclase content is always low. The clay minerals analysis indicates the presence of smectite, smectite-illite, kaolinite, and chlorite. The different clay minerals are almost always all present, in some samples chlorite is absent. The Lower Upper Bahariya is the one with more illite and mix of illite and smectite, while the Upper Lower Bahariya is the one with more kaolinite and chlorite. The Upper Upper Bahariya is intermediate between the two other levels.
The detailed core petrographical analyses revealed that the sedimentary succession from Aghar 4-1 well was affected by several diagenetic processes, which have influenced porosity and permeability. A few processes that have produced modifications in the structure regarding both the mineralogical composition and the interstitial space. The mechanical compaction phenomena generally seem to have acted poorly to moderately. After these, dissolution took place as confirmed by some partly dissolved feldspars grains that produce secondary porosity. The dissolution produced ions that precipitated as microporous aggregates of kaolinite, sometimes neomorphosing on the unstable grains. It is followed by the phase of carbonate precipitation, consisting of siderite and calcite, then the silica diagenesis followed producing the formation of widespread quartz overgrowths.
The sedimentological analysis revealed the presence of about more than 20 facies concluded to main nine lithofacies which are grouped into seven main facies associations, interpreted in the terms of tidal Flat, tidally influenced channel, shoreface, inner shelf, restricted inner shelf, mid to outer shelf and outer shelf. The lithofacies types are arranged in a distinct facies stacking pattern, which may be attributed to seven deepening cycles. All over the core, tidal flat deposits occasionally mixed with fore-shore sandstones, are followed upward by inner-shelf siliciclastics. These siliciclastics locally are replaced by inner-shelf carbonates. Two flooding surfaces were described represented by glauconite rich sandstones. Tidal channel deposits are mainly represented by deposit lags of reworked clasts. The facies stacking patterns revealed that these shallow marine to marginal marine successions consists frequently of thin beds with rapid upward shifts in facies, reflecting the shallow sea level at the time of deposition and the variability and evolution of the depositional system was captured from the use of subsequent facies. It reflects in general upward deepening over each cycle. In addition, the abrupt facies shifts are expected to be laterally over relatively short distances.
The overall depositional setting of the cored successions has been interpreted as tidally influenced estuarine-shoreface to shallow marine shelf.
Considering the porous system, Primary interparticle and secondary inter-and intraparticle forms of porosity are the dominant pore types reaching up to 13% by volume. The samples with the highest permeability and porosity by image analysis mainly belong to the Lower Upper Bahariya zone and, only in few cases to the Upper Upper Bahariya and Upper Lower Bahariya zones. Reservoir quality is ranging from very poor reaching up to very good.
Bahariya is a shaly reservoir with tight streaks and cemented sands, the lithology interpretation and the cut-off value of the volume of shale alone for the net sand definition, were not directly evident from simple cross plots. Core of Aghar 4-1 which have a higher resolution for thin beds were integrated for better interpretation of lithology and net sand cut-off, as well as provide a sharper cut-off for the reservoir and non-reservoir zones.
The volume of shale was calculated using Neutron –Density for better calculation since Gamma ray method given not representative values against sand- shale interlamination. A volume of shale cut-off of 0.5 v/v was estimated from porosity versus volume of shale cross plot, which used to differentiate shales and sands.
Reservoir porosity was calculated using the density log method, Log derived porosity was calibrated to stressed core porosity where data was available. All air core porosity available was corrected to in-situ conditions using a correction factor of 0.99 based on SCAL data from Aghar 4-1 well. Average matrix density value of 2.66 g/cc was selected from core grain density. The apparent fluid density is representing the density of the mixture of the mud filtrate and the formation fluid. The log bulk density versus in-situ core porosity x-plot was used to estimate the apparent fluid density of 1 g/cc.
Water saturation have been calculated from open hole logs (Archie equation), thin bed analysis module on Techlog.
Archie model indicated high water saturation average of 58 % at the shaly sand interval which lead to underestimate the volume of hydrocarbon in place and hence the reservoir development strategy. Therefore, unconventional saturation calculation models has to be used for more realistic results.
Thin bed evaluation or Low Resistivity Pay model “LRP” employs a Thomas-Stieber based low resolution approach and is more versatile than earlier shaly sand evaluation modules, enabling the user now to incorporate a wide variety of today’s formation evaluation data sets such as NMR logs, the horizontal and vertical resistivity from array induction tools or even a net sand count from core or image logs, just to name a few. The Thomas-Stieber approach is a cross plot technique for deriving formation properties such as net-to-gross and the porosity of the sand lamination in laminated thin-bedded formations.
The available core air permeability indicated the permeability ranging from 0.1 up to 1000 mD. A POR-PERM transform have been created using the available routine core air-permeability measurements in Aghar 4-1 well. The stressed core porosity was plotted against air core permeability.
Different water saturation model shows similar results against clean hydrocarbon bearing sand due to the fact that the shale conductivity is negligible. The Archie’s equation shows a tendency of overestimating the water saturation in oil-bearing of Aghar-4 wells. This will lead to potentially hydrocarbon bearing zones being missed due to its ability to restrain the resistivity when the clay distributions are present. The LRP model are used to overcome the issue of the clay effect on reservoirs in the shaly sand interval and show a very good and consistent results and they confirmed that the need for clay correction in the Bahariya formation.
It is important to point out that the results obtained in the sedimentological study, only derive from the study of five core sections from one well Aghar 4-1, further studies, from the same cores and adjacent cores should be conducted for a quality check of the results found during this study and more investigation.
As a recommendation, based on the integration of petrographical study, facies analysis and petrophysical evaluation, are highly recommended to use the shaly sand water saturation models to get accurate calculations of water saturation and to overcome the water saturation issue in clastic reservoir of Bahariya Formation, the spacing between the wells to be drilled in the field should be reduced in order to achieve the ultimate recovery for Bahariya reservoir and the multi-stage hydraulic fracturing is highly recommended in this kind of thin bed reservoirs due to low vertical connectivity.