Belayim Land field is one of the oldest and largest oil fields in Egypt. It was discovered in 1954. Its current daily production is about 80,000 BOPD. It produces oil from many sandstone reservoirs, Rudeis, Kareem, Belayim and South Gharib. Rudeis formation is the lowest reservoir in the Anticline structure that forming the field. The sandstone section of Rudeis formation is of an excellent reservoir quality. It is composed of quartz arenite with 22% average porosity and 800 md average horizontal gas permeability. The vertical permeability is about 0.9 of the horizontal permeability. The crude oil is of moderate quality with about 20 API.

Oil is produced from 10-30 ohm resistivity in Belayim Formation, while in Rudeis Formation; 70-80 ohm resistivity is producing water. A core was cut in Rudeis formation; the wettability of the reservoir rock was determined by Amott method and proved to be strongly oil wet. Electrical resistivity measurements were conducted on restored samples to determine Archie exponent. A constantly variable n values were obtained during the electrical measurements. Two saturation exponents (n values) were proposed to monitor the water saturation in the reservoir. This situation made it deem necessary to propose a certain resistivity cutoff for Rudeis formation in order to avoid perforating water zones.

Rudeis formation is an excellent oil reservoir. It is located in the Eastern side of the Gulf of Suez, figure (1). The sand thickness reaches about 300 meters. Recently, high resistivity intervals were perforated but the water cut was high and increased rapidly. To address the problem, it was decided to cut core in the Rudeis formation. A systematic core analysis program was designed to achieve a comprehensive reservoir rock characterization. The program includes porosity, permeability, grain density, pore throat and size distribution, petrographic analysis (including thin section description and SEM), and wettability of the reservoir rocks. The wettability characteristics of the reservoir is very important as it controls the fluids distribution within the pore spaces and this distribution will affect all the fluids-dependant characters of the reservoir. Based on the wettability results, the relative permeability and electrical properties measurements were measured on fresh-state samples.

Reservoir Rock Characterization
Porosity, horizontal and vertical permeability, grain density were measured every 25 cm. the porosity ranges from 20-26% with an arithmatic average 23 %. The horizontal gas permeability ranges between 80-2500 md with geometric mean of 800 md. Four samples were selected for petrographic description. The description revealed that the rock is mainly Dolomitic Quartz Arenite. The rock is mineralogically mature, the Quartz is the main detrial grains with little feldspathic grains that suffered partial 2 dissolution in some samples. The partial dissolution of the feldspar grains is the main reason for the relatively high microporosity in some samples. The thin section and the SEM photomicrograps (figures 2,3) show the excellent pore network (pore space and throat) with the patches of dolomite cementation.

The mineralogical model can be summarized in the following table:

Detrita grain
quart z
Detrita calys
Detrita grain
Detrita calys

The percentage of dolomite cement is the main factor that control the reservoir quality, where the porosity is increased with decreasing the dolomite cement percentage. The grain density ranges from 2.68 – 2.72 gm/cc. This high grain density of quartz arenite is compensated by the presence of dolomite as the main cement minerals.

Microporosity Evaluation
Four samples were selected to perform capillary pressure by mercury injection at 30,000 psi. the objective was to obtain the pore throat and size distribution in order to evaluate the microporosity. It is belived that microporosity is holding water and could be considered as the irreducible water saturation value in the reservoir rocks. The incremental distribution (red curve, figure 4) shows unimodal distribution with pore throat mode between 10 and 14 microns, which reflected in the measured high permeability. The amount of microporosity is indicated on the cumulative curve (blue, figure 4) and ranges between 10-20% with an average of 15%.

Wettability is defined as the tendency of one fluid to spread on or adhere to a solid surface in the presence of other immiscible fluids, (Craig, 1971). The importance of wettability in reservoir rocks is that it controls the distribution of fluids within the pore spaces. At initial conditions, when the oil migrated from the source rock and accumulated in the reservoir rocks, the wetting phase which is the water is distributed in the small pores and as continous film coating the grains, (figure 5). If the wettability has changed to be oil-wet, the grains will be coated with oil and the water will be accumulated as disconnected droplets in the centre of large pores, (figure 6). Seven samples were chosen for wettabiltiy measurements. Amott method, including the static and dynamic displacement, was used to determine the wettability tendency of the reservoir rock. Fresh well preserved samples were used in the test. The results of the wettability is illustrated in the following table:

2804 9
as pe m, md
14 8
Poro i y, %
Irredu ible water satur t on, pore spac
Water wettabili y ind x
0. 7
0. 7
0. 6
0. 8
0. 4
0. 4
0 05
Oil wettabil ty in ex
0 59
0 75
0 67
0 64
0 71
0 76

The Amott wettability results indicate that the Rudeis foramtion is strongly oil-wet with very little affinity towards water. Accordingly, the water will occupy the micropores and occur as disconnected droplets of water in the centre of the large pores.

Electrical Properties Measurements
The electrical properties of rocks have been used to calculate fluid saturations in reservoir rocks. The formation resistivity factor is defined as:

FF = RO/RW = Φ-m (1)

Where RO is the sample 100% water-saturated, RW is the resistivity of formation water. The formation factor can be related to porosity (equation 1), the slop of the line relating the porosity to formation factor is m, which is defined as porosity or cementation exponent. The wettability of rock has no effect on the m value as it is determined at one phase saturation, but m is affected by overburden pressure and it has to be measured at the net overburden pressure on the reservoir rock.

Eight samples were selected for formation factor measurements. The average calculated cementation factor was 1.80 at net overburden pressure 7000 psi.

Archie (1942), introduced another equation to relate water saturation to electrical resistivity:

RI = RT/ RO = SW (2)

Where RI, the resistivity index, is the ratio of the resistivity of the sample at specific brine saturation (RT), over the resistivity of one hundred percent brine saturation (RO). The resistivity index is related to water saturation of the sample (SW) and saturation exponent (n). the saturation exponent, n, should be determined by experimental core analysis.

RT is the resistivity of sample at two phase saturation (oil and water). The distribution of the two fluids is influenced by the wettability characteristics and saturation history of the measured sample. The eight samples were flushed with dead crude oil to establish the oil saturation at irreducible water saturation. The samples were aged for 40 days at reservoir temperature to restore the original wettability. During the production phase of the reservoir, the water saturation is increased. So to simulate the reservoir performance, the resistivity index was measured in steps with water saturation increases. The standard resistivity index measurements are performed on 100% water saturated, then the water saturation is decreased at steps and the electrical properties are determined.

For only one sample, the resistivity index was measured on clean-state with water saturation decreasing as the standard procedure. The calculated saturation exponent was 1.93 in agree with the standards of Archie, figure (7). The same sample was measured at restored-state while water saturation is increasing. A constantly variable saturation exponent, n, is obtained. It varies from 3 in the start of water flooding, to 4 and then 7 and finally 9 at the end of the test. The curve can be divided into two segment, the first where n ranges between 3 to 7 and it represents the mechanism by which the water droplets in the centre of the large pore are concentrated to form continous film. While the second segment of the curve starts at n=7 to n=9, the second segment represents the forming of continous film of water and as it increase in thickness, the resistivity decreases. The same phenomena was observed in all the measured samples. The inflection point on the resistivity index was choosen to select the Rt cutoff. This inflection point separate between the phase of disconnected and poorly connected film of water and continous film of water. For the purpose of applying the variable n values, an average value of n=3 was assigned to calculate water saturation for RT higher than 70 ohm, and an average value of n=6 for RT less than 70 ohm.

Case 1:
The well 113-81 was drilled to drain Rudies Formation, figure (9) show the open hole log response, the shadow area is the perforated interval in the well. Figure (10) shows the precessed logs using ELAN software of Schlumberger. The standared value of Archie constant was used in the precessing (m=1.85 , n=2). The calculated water saturation ranged between 15-30%. The calculated irreducible water saturation ranged between 10-20%. It means the presence of about 5-10% free water (moveable) in this interval. The interval was perforated, the water cut was about 87% after two weeks of production. The decision was to plug the perforated interval and perforate higher interval, figure (11). The new perforated interval produce oil with 0.1% water cut. The ELAN was reprocessed using variable n, figure (11). The n=6 was applied for the lower perforated interval, the calculated water saturation ranged between 50-70%, which is a higher value than the water saturation cutoff that applied in the field. This high water saturation compensate the high water cut in production.

Case 2:
The well 113-95 was drilled to drain Rudies formation. The open hole log response, figure (12) show the excellent reservoir quality. The resistivity ranged between 20-2000 ohm. The whole interval was perforated. The initial water cut was 52%. Figure (13) shows the ELAN using standard Archie constants. The calculated water saturation ranged between 10-30%, only 10 higher than the irreducible water saturation. The decision was to produce the interval indicated in figure (14). The water cut from the new produced interval was 0.5%. The ELAN was reprocessed using variable n. In the lower interval figure (14), n=6 was applied and the calculated water saturation was 50-70%, a higher value than the water saturation cutoff. In the upper interval the calculated water saturation ranged between 8-16%, a value within the irreducible water saturation range of the formation. The water cut of this interval was about 0.5%.

Wettability and saturation history must be considered during electrical resistivity measurements.

The electrical resistivity measurements of water-wet reservoir should be performed on fresh or cleaned-state samples, while in case of oil-wet reservoir rocks, fresh or restored-state samples should be used to compensate the effect of wettability. In both cases, the electrical resistivity should be measured while the water saturation is increasing to simulate the reservoir conditions.


  • Amott, observations relating to the wettability of porous rock, Trans. AIME, 216, PP 156-162, 1959.
  • Anderson,W.G., Wettability literature survey- Part 1: “Rock/oil/brine interactions, and the effects of core handling on wettability”, SPE 13932, 1984.
  • Anderson,W.G., Wettability literature survey- Part 2: “Wettability measurement”, SPE 13933, 1984.
  • Anderson,W.G., Wettability literature survey- Part 3: “The effects of wettability on the electrical properties of porous media”, JPT (DEC. 1986), Vol. 38, P. 1371-1378.

By S. Hassan, M. Sabra, A. Salah*
Belayim Petroleum Company, (PETROBEL)