الفهرس 
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Abstract
Baltim fields are important gas fields in the Nile Delta. It is located in the northern part of the Nile Delta, between Latitudes 31, 42’, 21.71’ and 31, 59’, 07.22’’ N and Longitudes 31, 6’, 42.55’’ and 31, 16’, 49.42’’ E. Baltim fields embrace the northern portion of Abu Madi paleovalley, in the offshore Nile Delta, about 15 Km off the Egyptian coast, where water depth of the Mediterranean Sea varies between 45-60 m. The length of Baltim fields is about 30 km and its width is about 5 km.
Baltim gas fields are a stratigraphic / structural combination trap with shale out against incised valley sides and fault-bounded in the Northern and Southern part. Gas and condensate production are obtained from two main sandstone reservoirs in Abu Madi Formation: level III Main and level III Lower. Reservoir effective porosity is generally in the range 15-25% and reservoir permeability is high in level III Lower (typically 400-1000 md) and somewhat lower in level III main (50-300 md).
Sidi Salim Formation is considered the most likely source rock for gas and condensate in the field.
Baltim fields are located in the Central sub-basin which separated from the eastern and western lows by set of faults trending NW-SE & NE-SW direction respectively. This basin yielded great both facies and thickness variations which also were controlled by tectonic event.
The stratigraphic sequence in Baltim area comprises the following formations arranged from older to younger:
- Tineh Formation: It is composed mainly of dark gray shales with thin interclations of siltstone and sandstone particularly in the upper part and alternated with thin beds of limestone in the lower parts.
- Qantara Formation: is exclusively clastic sediments composed of shales and sandstones interbeds and marl of marine environment with water depth ranging from the shelf to slope.
- Sidi Salim Formation: is widely distributed throughout the Nile Delta and it represents remarkable rock unit of the Middle Miocene (Langhian – Serravallian) section of the Nile delta covering conformably the Qantra Formation.
- Qawasim Formation: The upper limit of Qawasim Formation is rather difficult to define, it can be defined through fossils or sedimentological criteria which can be applied where there is a passage from a predominantly conglomeratic sequence to a succession with alternating sand and clay layers or when a fining–upwards sequence with marine clays can be found at the top.
- Abu Madi Formation: is the most important formation through all sections where it represents the main gas producing reservoirs in the Nile Delta.
- Kafr El-Sheikh Formation: composed mainly of deposition of deep marine shales and sometimes includes turbiditic sands.
- El Wastani Formation: is of Pleistocene age represented by more sandy facies and consists of thick sand beds interbeded with thin clay levels which become thinner toward the top of the formation.
- Baltim Formation: It consists of thick layers of sand and pebbles, which represents the filling of the basin by coastal sands or by deposits from Nile flooding.
Petrophysical evaluation is an essential and important step for hydrocarbon reserve calculation. The integration between log response and core data is an effective way to have a good interpretation, accurate and calibrated results.
The petrographic analysis was performed for two-cored wells Baltim North 5st and Baltim East-1. Petrographic study has revealed that, level III Main reservoir rock name in Baltim East field is sublithic srenite (from the cored well
Baltim East-1), while reservoir rock name in Baltim North field is subfeldspathic srenite (from the cored well Baltim North-5st), due to the difference in the mineralogical composition which indicate different depositional source .
Level III Lower reservoir rock name is calcitic sublithic arenite in Baltim fields because it has the same mineralogical composition in all Baltim fields which indicate the same depositional source.
Matrix grain density values are used to compute porosity from density curve. The level III Main reservoir matrix grain density value is 2.7 gm/cc due to the presence of the ferroan calcite as a cement, while level III Lower reservoir matrix density value is 2.67 gm/cc.
The clay type was determined from the XRD analysis as mainly kaolinite and chlorite. The chlorite percentage is about 1.5 % and the Kaolinite percentage ranges between 1-5 %.
The cementation factor value (m) for level III Main was equal as 1.94, while it was equal as 1.91 for level III lower.
The saturation exponent value (n) for level III Main was equal as 1.96, while it was equal 2.05 for level III lower
The petrophysical evaluation for 9 wells were reviwed and calibrated with the core data. The shale was decreased which had a direct effect on the effective porosity, wreservoir and pay thickness. The effective porosity was increased and matched the core porosity (corrected to the overburden) also, calculated water saturation was enhanced and decreased .
In well Baltim North-1, the effective porosity was increased in level III Main from 0.14% to 0.22% due to the decreasing in clay content from 0.32 % to
0.06 %. The netpay thickness was increased from 8 meter to 9 meter.
Also, in level III Lower, the effective porosity was increased from 0.15% to 0.21% due to the decreasing in clay content from 0.20 % to 0.03 %. The netpay thickness was increased from 30 meter to 35 meter.
In well well Baltim North-2, level III Main effective porosity was increased from 0.16% to 0.19% due to the decreasing in clay content from 0.23 % to 0.07 %
In well Baltim North-5 st, level III Main effective porosity was increased from 0.17% to 0.23% due to the decreasing in clay content from 0.26 % to 0.01
%. The netpay thickness was increased from 24 meter to 30.5 meter.
In well Baltim North East-1, level III Main effective porosity was increased from 0.15% to 0.24% due to the decreasing in clay content from 0.24 % to 0.01 %.
In well Baltim East-1, level III Main effective porosity was increased from 0.17% to 0.20% due to the decreasing in clay content from 0.05 % to 0.03 %. The Netpay thickness was increased from 7 meter to 16 meter. In level III Lower, the effective porosity was increased from 0.14% to 0.23% due to the decreasing in clay content from 0.07 % to 0.03 %. The Netpay thickness was increased from 12 meter to 20 meter.
In well Baltim East-2, level III Main effective porosity was increased from 0.18% to 0.20% due to the decreasing in clay content from 0.23 % to 0.07 %
In well Baltim East-3, level III Main effective porosity was increased from 0.20% to 0.21% due to the decreasing in clay content from 0.06 % to 0.03 %.
The netpay thickness was increased from 28 meter to 37 meter.
In Baltim East-4, level III Main effective porosity was increased from 0.20% to 0.23% due to the decreasing in clay content from 0.05 % to 0.03 %.
In well Baltim East-5, level III Lower effective porosity was increased from 0.16% to 0.25% due to the decreasing in clay content from 0.24 % to 0.02 %.
the Netpay thickness was increased from 14 meter to 15 meter.
In Baltim East field, the gas/water contact was defined from logs
@ 3670 TVDss in level III lower which match gas/water contact from RFT in well Baltim East-1, while the gas/water contact for level III Main was defined from logs between Gas Down To (G.D.T) @ 3645 TVDss and Water Up To
(W.U.T) @ 3681 TVDss in well Baltim East-3. The RFT has proved G.W.C
@ 3645 TVDss.
In Baltim North field, the gas/water contact was defined from logs
@ 3757 TVDss in level III lower which match with the RFT in well Baltim North-1, while the gas/water contact was defined from logs @ 3676 TVDss in level III Main and matched with the RFT in well Baltim North-2.
Although, Level III Lower has a different gas water contact through Baltim fields (East and North), It is important to mension that there is a communication between Level III Lower in Baltim North and East fields through aquifer as they have the same water gradient, while Level III Main has different gas water contact with different gradient which indicates the separation between level III Main in Baltim North and East fields.
Statisticala analysis were performed for the petrophysical outputs data (Phie, Sw, VClay, VSand and VLime) were represented individually as Histograms or cross plots to outline the general trends and distributions of these parameters.
The effective porosity histograms showing positive skeweed bimodal distribution, the first mode reflect low effective porosity value with very low frequency and it is always lower than porosity cutoff (7%), while the second mode reflect high effective porosity value with very high frequency.
from the histogram of the leve III main effective porosity, the effective porosity major values ranges from 10-26% in Baltim North field and it ranges from 13-30% in Baltim East field.
from the histogram of the leve III lower effective porosity, the effective porosity major values ranges from 12-27% in Baltim North field and it ranges from 13-25% in Baltim East field.
from the histogram of Kaolinite volume, the Kaolinite volume values ranges from 7-19% in all the fields (except in well Baltim East-2, it reach to 34%) while the chlorite values from the histogram ranges from 2-12% (except in wells Baltim
North-1 and Baltim North-2, it reach to 17%). It shows positive skeweed bimodal distribution
from the crossplots between porosity and clay volume (total clay volume, chlorite volume and kaolinite volume), the relation between effective porosity and total clay volume ( chlorite volume and kaolinite volume) is a reverse relation in all the wells ( level III main and level III Lower) with good regression coeffecient ( 0.91 in well Baltim North-2, 0.97 in well Baltim North-5st and 0.94 for level III main in well Baltim East-5).
The relation between effective porosity and chlorite volume is a reverse relation in all the wells ( level III main and level III Lower) with bad regression coeffecient less than 0.50 in all wells ( ececpt in well Baltim North-2, the regression coeffecient is 0.67) which indicates the low effect of chlorite on effective porosity.
The relation between effective porosity and kaolinite volume is a reverse relation in all the wells ( level III main and level III Lower) with good regression coeffecient ( 0.89 in well Baltim North-2, 0.97 in well Baltim North-5st and 0.94 for level III main in well Baltim East-5).
from the crossplots between effective porosity and sand volume, the relation is a propotional relation in all the wells ( level III main and level III Lower) with generally good regression coeffecient ( 0.67 in well Baltim North-2, 0.89 in well Baltim Norht-5st, 0.90 in well Baltim East-4, 0.90 for level III lower in well Baltim East-5 and 0.97 for level III main in well Baltim East-5) and it can be used as indication for the reservoir cleanliness.
from the crossplots between effective porosity and lime volume, the relation is a reverse relation in all the wells ( level III main and level III Lower) with generally bad regression coeffecient (ececpt in wells Baltim North-5st, Baltim North East-1, Baltim East-4 and Baltim East-5, the regression coeffecient was reflect good relation).
Core data was integrated with the logs to enhance petrophysical evaluation, to perdict permeability and to determine whether the high water saturation is movable or not.
Winland (r35) and El Sayied (Kr36) were used to classify Abu Madi reservoir (level III Main and level III Lower) into several flow units.
Although the Kr36 is dependant only on the permeability, the obtained results from the two methods (Kr36 and r35) are matched and very similar in shape but the pore radii values obtained from Kr36 are slightly lower lower than that from r35.
Based on Martine classification, Abu Madi reservoir (level III Main and Level III Lower) classified into four flow units, each flow unit has its similar petrophysical characteristics.
FU4 is the best quality characterized by high r35 value (~12 µm), high porosity (~22 %) , high permeability (~500 md) and low grain density ( 2.67 gm/cc).
FU3 characterized by r35 value ~4 µm, porosity value is ~21 %, permeability value is ~68 md and grain density value is 2.68 gm/cc.
FU2 characterized by r35 value ~1 µm, porosity value is ~18 %, permeability value is ~6 md and grain density value is 2.69 gm/cc.
FU1 is the lowest reservoir quality characterized by r35 value ~0.28 µm, porosity value is ~10 %, permeability value is ~0.24 md and grain density value is
2.70 gm/cc and FU1 cannot considered as a reservoir.
The comparison between r35 and Kr36 versus Ø and K were established to see the relation between the two methods with the petrophysical parameters.
The relation between r35 and Kr36 with the porosity are a propotional relation, indicates that both r35 and Kr36 depend on porosity.
The relations between r35 and Kr36 with the permeability for all flow units are a propotional relations, indicates that both r35 and Kr36 depend on permeability.
The flow units were predicted in uncored intervals / wells through the relation between core flow units and the difference between Neutron- Density porosities in the cored wells Baltim North-2, Baltim North -5st, Baltim East-1 and Baltim East-3.
The FU4 (which characterized by high porosity and high permeability) was correlate with the high difference between (ØN – ØD) and the FU1 was correlate with the small difference.
Based on the last observation, Log Flow Unit was predicted (LFU) from the relation between effective porosity from petrophysical evaluation (Ø) and the difference between calculated porosity from Neutron and Density (ØN – ØD) in all the cored intervals/wells (Indication for separation between Density and Neutron) using core flow units codes.
The predicted log flow units (LFU) are in a good match with the core flow units (CFU) against the cored intervals in addition the uncored intervals have a continuous estimated flow units (LFU).
The definition and the standard practical unit, Darcy, of permeability used in petroleum industry was adapted by the American Petroleum Institute (API, 1960), while the up to date permeability unit is the SI unit, m² (El Sayed, 1981).
Permeability was estimated for level III Main in Baltim North field from the
core porosity- permeability relation according to core flow units in wells Baltim North-2 and Baltim North-5st. Level III Main has a different mineral composition and different reservoir rock name in Baltim East field so, Another relation between Core Porosity- Permeability according to core flow units in wells Baltim East-1 and Baltim East-3 was established to estimate permeability for level III Main in Baltim East field.
For Level III Lower, core porosity- permeability relation according to core flow units in well Baltim East-1 (the only cored well penetrated level III Lower from the studied wells) and well Baltim North-1 used for permeability estimation for level III Lower in Baltim fields as level III Lower has the same composition.
The previous equations were used to estimate permeability in uncored intervals/wells using predicted log flow units.
The log porosity- permeability cross plot ( using log effective porosity curve and continuous predicted permeability curve) was established for all the studied wells to show that, Abu Madi reservoirs (Level III Main and level III Lower) were classified in to different flow units, each flow unit has its characteristics.
The MICP was used to calculate the irreducible water saturation from core data and to calibrate NMR T2 cutoff. T2 cutoff value was changed from the standard value 33.3ms to be 150ms.
Mercury injection capillary pressure (MICP) measurements are available in well Baltim North-5 st only, represent FU3 and FU4.
FU4 was characterized by 33 % irreducible water saturation compared with 35% water saturation from logs and it is increased in FU3 reach to 45% compared with 50% water saturation from logs which indicate that the free water saturation is very limited and it will not produce . For FU2 and FU1, it is not represents by any MICP measurements but the irreducible water saturation can expected 60% for FU2 reaching to 90% for FU1 from the petrophysical evaluation.
from the cross plot between initial daily production rate and the average predicted permeability, it is clear that the higher daily production was related to the higher permeability and the lower production coming from lower permeability and this conclusion is supporting the current model.
Organic rich shale of Sidi Salim Formation and Kafr El Sheikh Formation are considered the most likely source rock in the Nile Delta.
There are two main oil families have been found to be present in the Nile Delta region, the first one (i.e. El Temsah, Baltim, Abu Madi fields) is characterized by the presence of a specific age biomarker Oleanane (Upper Cretaceous/Tertiary source rock), a mainly continental organic matter input and clastic lithology (mainly shaly); the second one (i.e. Mango oils) is characterized by the absence of Oleanane, the presence of markers typical of a more marine organic matter input and shaly lithology.
The migration index measured on the available oil samples along the Abu Madi paleovally indicate that the distances coved by the oils during the secondary migration increase from north to south, suggesting that the structures were predominantly charges from north.
Baltim fields comprise two reservoir levels named III Main and III lower within the Upper Messinian Abu Madi Formation.
The generation and migration of the hydrocarbons are thought to have reached their peak by the end of the Miocene time.
3D simple reservoir model was established in order to represent the vertical and lateral heterogeneity and create a framework of the reservoirs in Baltim fields.
There are two main faults, the first fault was located at south and separated between Baltim South and Baltim East fields while the second fault was located at the north and separated between Baltim North field and Baltim North East field.
The boundaries of Baltim fields have been obtained also from seismic interpretation of Belayim Petroleum Company on both Level III Main and Level III Lower, and then loaded in Petrel to define the area of interest.
Level III Main and Level III Lower were divided into 40 and 100 layers respectively based on the thickness and the different properties coming from the interpretation of well log and to reflect the same figure of the flow units.
The different petrophysical properties (ɸ, K and Sw) were used wells scale and distributed between the wells at reservoir scale to represent the reservoir
heterogeneity using Sequential Gaussian Simulation and it was matched the well data in the cells of the grid.
There were general cross sections for level III main and for level III lower established to show the flow units lateral distribution through the structure line between Baltim fields.
Wells cross sections were constructed to show the porosity, permeability and water saturation distribution and the relation between petrophysical parameters (porosity, permeability and water saturation) with the flow units.
The well Baltim East-5 was located at the boundary between Baltim East and Baltim North fields. Level III Main reservoir Quality is very bad and considered as a stratigraphic barial between Level III Main in Baltim East and Baltim North fields.
Based on this work, it was highly recommended to perforate Level III Main in well Baltim North-6 although the higher water saturation.
After the 3D reservoir model, it is easy to check the best locations for the next development wells.