الفهرس 
GEOLOGIC SETTINGOnly 14 pages are availabe for public view
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Abstract
The present study aims to characterize the reservoir anisotropy of the Bahariya Formation and Abu Roash Members by investigating their geological and the petrophysical characteristics. For this aim, two fields have been studied. The first field is BED-1 field in Badr El Din concession in north Western Desert, which is approximately bounded by long. 26° 29`-28° 35` E and by Lat. 29° 35`-30° 10` N, this field has been represented by BED1-11 well which represents only the lower part of the Bahariya Formation (Lower Cenomanian-Upper Cretaceous). The second field is GPTSW field in Abu Sennan area, north Western Desert which is approximately bounded by Long. 28° 00`-29° 00` E and by Lat. 29° 25`-29° 48` N, this field has been represented by the following wells: TSW-7, TSW-13 and TSW-15 which represent the upper part of the Bahariya Formation (Lower Cenomanian-Upper Cretaceous), TSW-8 well which represents Abu Roash `F` Member (Upper Cenomanian) and TSW-21 well which represents mainly Abu Roash `G` Member (Upper Cenomanian) and to less extent the Upper part of the Bahariya Formation. Fourty seven (47) and sixty three (63) core samples have been collected from BED-1 and GPTSW fields respectively. For BED-1 field all the samples (47) represent the lower part of the Bahariya Formation. For GPTSW field (38) samples represent the upper part of the Bahariya Formation, (11) samples represent Abu Roash `F` Member and (14) samples represent Abu Roash `G` Member. All the samples have been subjected to different laboratory techniques. These techniques comprise petrographical technique to show the characteristics and diagenetic alterations of the studied clastic and carbonate rocks, petrophysical techniques which include porosity, permeability and capillary pressure measurements to investigate the petrophysical properties of the studied samples and finally Scanning Electron Microscope technique (SEM) which has been used for some samples to show the pore geometry which affects the petrophysical parameters. The petrographic study revealed that quartz grains represent the dominant framework grains in the Bahariya Formation (Upper and Lower Members) and Abu Roash `G` Member samples with occurrences of glauconite rock fragments and minor occurrences of allochems as: foraminifera and molluscan shells in Abu Roash `G`, two sandstone facies have been recognized:
A-Quartz arenite which divided into five types: calcareous quartz arenite, glauconitic quartz arenite, laminated sublithic quartz arenite, subfeldspathic quartz arenite and glauconitic subfeldspathic quartz arenite.
B-Quartz wacke which divided into three types: massive quartz wacke, laminated quartz wacke and glauconitic quartz wacke.
These sediments have been suffered from diagenetic processes as: cementation, quartz overgrowth, clay authigenesis, dissolution and fracturing, the depositional environment is shallow marine (upper and lower shore). On the other hand the petrographic analysis of samples Abu Roash `F` Member exhibited one carbonate facies (foramineferal mollusan packstone) with common occurrences of allochems as: foraminifera and molluscan shells, these sediments have been suffered from different diagenetic processes as dissolution and recrystallization, depositional environment is deep marine (offshore) with slow sedimentation. SEM technique has been used for some samples to show the pore geometry which affects the petrophysical properties. This technique displayed a number of the diagenetic processes that have affected the reservoir quality as carbonate cementation, quartz overgrowth, clay authigenesis, framework grain dissolution, recrystallization of calcite inside the foram and fracturing. Concerning the petrophysical studies, (47) and (63) core samples have been drilled into cylinders of 2.54 cm in diameter and about 3 cm long for the petrophysical measurements. These cylinders have been cleaned then dried at temperature of 85 °C. Porosity data have been determined by use of both matrix-cup helium porosimeter for grain volume estimation and DEB-200 instrument which follow Archimedes law for bulk volume determination. Also bulk density has been determined as biproduct of porosity measurements. Permeability measurements have been done by using steady state air permeameter. Porosity-permeability relations have been displayed for each well separately and then the same relation has been displayed for each formation and member. Some relations have higher correlation coefficients, others have no relations as the relation between porosity and permeability in TSW-8 well (Abu Roash Member) and this may be due to the very close values of porosity and permeability of the samples. Also it was found that the studied samples of the lower part of the Bahariya Formation in BED1-11 well are differentiated into three groups (A, B and C). Group (A) has an average porosity 7.3% and average permeability 0.02 md (poor reservoir), group (B) has an average porosity 11.9% and average permeability 1.04 md (fair reservoir) and group (C) has an average porosity 15.4% and average permeability 28.8 md (good-moderate reservoir). The petrographical investigation of the different groups show that all the samples are highly cemented sandstones but there are two factors responsible for the anisotropy between the samples that reflected on the values of porosity and permeability of the different groups. The first factor is the diagenesis (cementation) which is high amount in group (A) which has the lowest values of porosity and permeability then become medium in group (B) which has moderate values of porosity and permeability and reach to lowest quantity in group (C) that has the highest values of porosity and permeability. The second factor is the clay content (lamination) where we found the samples of group (A) are laminated samples. On the other hand the samples of group (B) vary between laminated and non-laminated, but samples of group (C) are non-laminated samples. Kaolinite, chlorite and illite are the clay types that have been recognized in this section. On the other hand, the studied samples of the upper part of the Bahariya Formation obtained from TSW-wells are classified into two groups (A and C). Group (A) has an average porosity 13.6% and average permeability 0.18 md (fair-poor reservoir) where group (C) has an average porosity 21.9% and average permeability 123.9 md (very good-good reservoir). The petrographical description of the studied samples in the two groups exhibit that, samples of group (A) are highly argillaceous, laminated sandstone but samples of group (C) are slightly argillaceous or clean sandstones. The presence of detrital clays in different ratios and lamination are the main factors responsible for the anisotropy between the samples that reflected on the values of the porosity and permeability of the two groups. Also samples of Abu Roash `G` Member in TSW-21 well are classified into two groups (A and C). Group (A) has an average porosity 13.5% and average permeability 0.37 md (fair-poor reservoir), on the other hand group (C) has an average porosity 25.7% and average permeability 13.4 md (very good-moderate reservoir). The petrographical investigation of the studied samples in the two groups displayed that, the samples of group (A) are highly argillaceous, laminated sandstone, but samples of group (C) are less argillaceous sandstones. Also the difference in the clay content is the main factor responsible for the anisotropy between the samples as the previous case. where samples of Abu Roash `F` Member in TSW-8 well display one group in porosity-permeability relation has an average porosity 16.9% and average permeability 0.013 md (good-poor reservoir). The petrographical investigation of the studied samples showed all the samples have the same lithology (marl) that affects the permeability values. Also the porosity-bulk density relations have been displayed for each well separately and then the same relation has been displayed for each formation and member. (47) and (63) samples were selected from BED1-11 well and TSW-wells respectively for the capillary pressure measurements by mercury injection to determine the pore size distribution and many derived parameters which affect the reservoir quality. Tracing the different groups that originated from the porosity-permeability relations has been done through the results of the capillary pressure which confirmed that, group (A) in the different studied units always has the lowest, narrow range of the pore size distribution and this reflected in higher values of displacement pressure and unsaturated pore volume (Swirr) and also lower values of several parameters derived from the pore size distribution as mean hydraulic radius (MHR), median (R50) and (R35). In contrast, group (C) always has the highest, wide range of the pore size distribution and this reflected in lower values of displacement pressure and unsaturated pore volume (Swirr) and also higher values of mean hydraulic radius (MHR), median (R50) and (R35). Group (B) has moderate properties between (A) and (C). In the present study, a new concept has been introduced which is the effective porosity or (refined porosity) and defined as that part of rock pore spaces above certain pore throat cutoff. It was found out that all porosity-permeability relations have been improved when applying the refined porosity instead of the unrefined one. Finally many correlation charts have been constructed among the petrophysical parameters (porosity, permeability, displacement pressure, water saturation, pore size distribution, MHR, R50, R35 and PVC), they are very useful for the reservoir evaluation in the studied areas where we can predict one of previous parameters by knowing the others.