petrophysical characteristic and effect on reservoir fliud

BALWOIS 2010 – Ohrid, Republic of Macedonia – 25, 29 May 2010 1

The Petrophysical Characteristics and their Effect on the Reservoir Fluids for Mheiherrat Formation at the Central Part of

the Gulf of Suez, Egypt

M.Ghorab

Egyptian Petroleum Research Institute

ABSTRACT

The present work for determined the petrophysical characteristics of the

Mheiherrat Fomation which is formed generally of carbonates and other case from

sandstone. These include twelve wells (HH 84-1, GG 85-1, WFA-1, WFB-1, GS

216-1, GS 206-1A, GS 207-1A, GS 197-2, GS 196-1A, TANKA-1, TANKA-3 and

TANKA-4) were selected for applying the present technique of the reservoir

performance for Mheiherrat Formation in the considered area.

In this respect, shale volume is needed for correcting the porosity

and water saturation results for the biased effects of shale. It is considered as

an indicator of reservoir quality, in which the lower shale content usually reveals

a better reservoir.

These petrophysical parameters (Фe, Vsh, Sw, Swir, Swre, Sh, Shr and

Shm) are represented horizontally in the form of iso-parametric maps to illustrate

their areal distribution within the evaluated formation across the area of study. The

result of this study illustrate that, the hydrocabon quality increases gradullay

outward the area of study where the movable hydrocarbon shows low content

where it varies from 0% to32% at GS 216-1 well.


INTRODUCTION Mheiherrat Formation in WFB-1 well possess many sandy dolomite

intervals. These intervals are composed of dolomite, sandy dolomite, grading into

sandstone. It contains quartz and feldspars with shale intercalation. The dolomite

is sandy and glauconitic with local vuggy porosity. The resistivity curves are

deflected towards high levels with positive separation. The glauconite is

prevailing in these intervals. The limestone of this formation is dolomitic, sandy

and shaly in parts. In some limestone intervals, the glauconite is present. The

marl is light gray, silty, calcareous and grading to limestone. A thick sandstone

bed is also present in GS 207-1A well. It is described as white, light brown, fine

grained, subrounded-subangular, poor to fair sorting, high matrix/grain ratio, highly

calcareous, grading into high sandy limestone and occasionally glauconitic with

yellow florescence ,figure( 2 ).

The core description for limestone and sandy limestone intervals in GS

207-1A well is as follows: the limestone is gray, with no visible porosity,

glauconitic slightly sandy with no oil shows. The sandstone streaks is highly

calcareous. Dark brown oil strains (OSTN) are reported in many sandy limestone

streaks, described as well sorted and slightly pyritic.

1- Shale Volume Determination:

The shale content is determined using different shale indicators, the

minimum of all these methods has been used in this interpretation. The following

methods were used to define the shale volumes in the present work.

1- Gamma-Ray Method: Gamma-ray log is considered one of the best tools used for identifying and

determining the shale volume. This is principally due to its sensitive response for

the radioactive materials normally concentrated in the shaly rocks. The following

equation is used to determine the shale volume:

IGRGR GRGR GR

=−

−log min

max min (1)

Where: IGR is the Gamma-ray index,


GRlog is the Gamma-ray reading for each zone, and

GRmin and GRmax are the minimum Gamma-ray value

(Clean sand or carbonate) and the maximum Gamma-ray

Value (shale), respectively.

Then, the shale volume can be calculated from the Gamma-ray index, by

the following formulae (Dresser Atlas, 1979).

1- Older rocks (Paleozoic and Mesozoic), consolidated:

Vsh = 0.33 [2(2 x IGR) − 1.0] (2)

2- Younger rocks (Tertiary), unconsolidated:

Vsh = 0.083 [2(3.7 x IGR) − 1.0] (3)

Accordingly, the second formula was applied in the present work.

2- Neutron Method: It can be used in case of high clay content and low effective porosities,

from the formula:

VNN

Xshsh

≤ =( )( )

logΦ

Φ (4)

Where: (ΦN) log is the neutron log reading for each studied zone,

and (ΦN)sh is the neutron log reading in front of a shale

zone.

3- Resistivity Method: It can be utilized to calculate the shale volume in case of high clay contents

and low (Rt) values from the relation:

V RRtsh

sh≤log

(5)

If this ratio is more than (0.5) (i.e., 0.5 ≤ Vsh ≤ 1), then:

Vsh ≤ (Rsh / Rt) = X (6)


If this ratio is less than (0.5) (i.e., Vsh ≤ 0.5), then:

VRRt

R RtR R

Xshsh cl

cl sh≤ −

−

−

⎡

⎣⎢⎢

⎤

⎦⎥⎥

=log

log/B1

(7)

Where: Rsh is the resistivity of a shale zone,

Rcl is the resistivity log reading for a clean zone,

Rtlog is the resistivity log reading for each zone, and

B is a constant, ranging in value between 1 and 2.

B-2-2- Correction of Shale Volume: The value of (X) obtained previously must be corrected by valid formula to

obtain the optimum value usable in the log interpretation.

The first formula is:

V Xsh = − − +17 3 38 0 7 2. . ( . ) (Clavier et al., 1971) (8)

The second formula is:

V XXsh =

−0 515

..

(Steiber, 1973) (9)

Then the different zones were classified into clean, shaly and shale zones

according to the following bases:

- If Vsh < 10 % This means clean zone,

- If Vsh from 10 to 35 % This means shaly zone, and

-If Vsh > 35 % This means shale zone.

ISO-PARAMETRIC MAPS OF SHALE FOR MHEIHERRAT FORMATION:

The shale percentage map (Fig. 14) illustrates an increase of shale content

in the southeastern and northwestern parts of the area which, reaches its highest

value of 30% at GG 85-1 well in the south eastern corner of the studied area while

it decreases to 7% at TANKA-4 well locality in the southwestern part.


2- Porosity Determination:

Porosity is the volume of non-solid portion of the rock that is filled with

fluids, as divided by the total volume of the rock. Primary porosity is the porosity

developed during the original sedimentation process by which the rock is created.

Porosities in the reservoir rocks usually range from 5 % to 30 %, in which

the porosity of carbonate rocks is somewhat less than that of sandstones. In

general, porosities tend to be lower in deeper and older rocks due to the

cementation and overburden pressure stress on the rock. Shale porosity

decreases more with depth than sand, this is because the shale is compressed

more easily than sand. These basic trends of porosity changes vs. depth are not

noticeable clearly in the carbonates as compared to the sandstone and shale,

where porosity is more affected by the depositional environments and secondary

processes, both unrelated to the depth of burial.

Secondary porosity is created by processes, which synthesize vugs or

coverns in rocks by ground water (Crain, 1986). In most cases, secondary

porosity results in such higher permeability than primary granular porosity.

However, the porosity derived directly from logs without correction for shale

content is termed apparent or total porosity. In a zone of no shales, the total

porosity in this case equals the effective porosity.

2-1- Total Porosity (Φt):

• Porosity from One-Log Method. It can be determined from the sonic, density and neutron logs, in both clean

and shaly zones.

1-Porosity From Sonic Log: The total porosity can be diversified, according to the clean and shaly

zones.

a- In Clean Zones:


In the shale free formations, the determination of the total porosity depends

on Wyille’s et al. (1958) formula as:

ΦΔ Δ

Δ ΔSma

f ma

T TT T

=−

−log (10)

If the compaction factor is considered, then:

ΦΔ Δ

Δ ΔSma

f ma

T TT T CP

=−

−×log 1 (11)

In such a case: CPT Csh=

×Δ100

(12)

where: C is a constant normally equals 1.0 (Hilchie, 1978).

b- In Shaly Zones: In the shaly formations, the total porosity is determined from the formula of

Dresser Atlas (1979) as:

ΦΔ Δ

Δ ΔΔ ΔΔ ΔS

ma

f mash

sh ma

f ma

T TT T CP

V T TT T

=−

−×

⎡

⎣⎢

⎤

⎦⎥ −

−−

⎡

⎣⎢

⎤

⎦⎥

log 1 (13)

2-2-Porosity From Density Log: a- In Clean Zones:

The porosities derived from density log (ΦD) are calculated from the

relation:

ΦDma b

ma f=

−−

ρ ρρ ρ

(Wyille, 1963) (14)

where: ρma is the matrix density.

b- In Shaly Zone: According to Dresser Atlas (1979), as follow:

ΦDma b

ma fsh

ma sh

ma fV=

−−

⎡

⎣⎢

⎤

⎦⎥ −

−−

⎡

⎣⎢

⎤

⎦⎥

ρ ρρ ρ

ρ ρρ ρ

(15)

where: ρsh is the shale zone density.


2-3-Porosity From Neutron Log: Neutron logs give directly the porosity values on the log track in clean

formations. Correction of the log data for the different factors affecting it must

be taken into consideration. These factors include bore hole size, mud cake

thickness, borehole and formation water salinities, pressure and temprature.

However, the CNL neutron log in the usable data is designed to minimize the

effect of the borehole parameters (Schlumberger, 1989). If shales intervene,

their effect must be corrected through the following equation:

ΦNc=ΦNlog-VshxΦNsh (16)

Porosity from Density-Neutron Combination:

The combination of neutron and density is considered as a good

approach for calculating the comparable porosity in clean and shaly zones.

1- in clean zones:-

Φ(N-D)= ΦN+ΦD/2

(17)

2- 1n shaly zones:

Φ(N-D)=√(ΦNc2+ΦDc

2)/2 (18) where:

Φ ΦΦ

NC NNsh

shV= − ⎡

⎣⎢⎤

⎦⎥× ×

0 450 30

.. (19)

Φ ΦΦ

DC DNsh

shV= − ⎡

⎣⎢⎤

⎦⎥× ×

0 45013

.. (20)

For clean and shaly zones, the values of porosity obtained from sonic,

density, neutron logs and the dia-porosity density-neutron methods are termed

ΦS, ΦD, ΦN and ΦD-N respectively, and their average (Φt) is calculated for each

zone to get the optimum total corrected porosity value .

\ISO-PARAMETRIC MAPS OF POROSITY FORMHEIHERRAT FORMATION:

Generally the porosity distribution of Mheiherrat Formation decreases

gradually southeastern ward (Fig. 15) in which the minimum porosity value is (9%)


is represented at WFB-1 well in the southeast part till reaches its maximum value

(31%) at TANKA-4 well.

3- Determination of Fluid Saturation:

This part exploits the formerly deduced petrophysical parameters to

calculate the fluid saturation and to complete the information needed about the

reservoir characters. The determination of the fluid saturation involves principally

the discrimination between the various fluid components (water and

hydrocarbons) filling up the pores of the flushed and uninvaded zones.

3-1- Calculation of Rock Variables and Exponents: -

The rock variables and exponents include the cementation

factor "m", the saturation factor "n" and the tourtosity exponent "a". The

importance of these factors lies in the need for the optimum estimation

of the total water saturation. In the present work, Pickett's method

(1963) was utilized for calculating these parameters.

The Pickett crossplot can provides some useful information on

formation characteristics. This plot utilizes a basic rearrangement of the Archie

equation,

Swn = aRw / Φm Rt

(21)

logRt = -mlogΦ + log(aRw) - nlogSw, (22)

if Sw = 100% this reduces to:-

logRt=-mlogΦ+log(aRw) (23)

this is a straight line plot on log-log grid for Rt Vs Φ where Y= mx+b is the

equation of a line. The slope of the 100% water saturation line determine "m"

whereas the value of "aRw" is derived from the intercept of such a line with the

porosity axis at Φ = 1, of course if Rw is known "a" can be calculated, as shown in

Fig. (6). A crossplot of this type works best in clean formations of a resonably wide

porosity range and constant Rw in the zone, (figures from 3 to 13) contains the

Pickett's plot of Mheiherrat Formation for the study area.


Data from the studied wells are averaged for each formation to

obtain a good value of "a" and "m". The porosity exponent "m" equals the

saturation exponent "n", as shown by Pickett (1973). Table (1) shows the different

values for these parameters and their average values for each formation in the

studied wells.

TABLE (1) THE ESTIMATED VALUES OF THE EXPONENTS "a" and "m"

FOR THE STUDIED FORMATION IN THE DIFFERENT WELLS.

GS

197-2

GS

216-1

GS

207-1A

TANKA

-4

TANKA

-3

GS

206-1A

GG

85-1

GS

196-1A

WFA

-1

WFB

-1

TANKA

-1

HH

84-1

AVERAG

E

.1 87 83 .1 .2 .1 66 96 73 68 .3 96

MH

EIIH

ER

.5 .1 .3 .0 .4 .2 .2 .4 .3 .0 .1 .2

3--2- Water Saturation:

1) Uninvaded Zone Water Saturation (Sw):

Archie’s formula was chosen to determine the water saturation (Sw) in the

clean zones, on the other hand, the average of Simandoux equation (1963) and

Schlumberger equation (1972) was used for the shaly zones.

a- Clean Zones : The uninvaded zone water saturation determination from resistivity logs in

the non-shaly formations with homogeneous inter-granular porosity is based on

Archie's equation (1942), as follows:


S a RRw m

w

t

n

= ×⎡

⎣⎢

⎤

⎦⎥Φ

1/

(24)

Where: Φ is the formation porosity,

a is the tortuosity factor .

m is the cementation factor . and

n is the saturation exponent.

b- Shaly Zones : It is determined utilizing the average of the Simandoux and Schlumberger

equations, shown as fallows:

Simandoux method 1/Rt = ((Vsh/Rsh)Sw) +( (Φm/aRw)Swn) (25)

• Schlumberger equation

1 1 2 22

RV

R aRS

t

shV

sh

m

ww

nsh

= +⎡

⎣⎢⎢

⎤

⎦⎥⎥×

−( / ) //Φ (26)

where : Rsh is the resistivity of a thick shale unit.

2) Flushed-Zone Water Saturation (Sxo):

The estimation of Sxo is essential for the definition of the residual

hydrocarbon saturation (Shr) in clean and shaly zones.

The flushed zone water saturation is determined as follows:

a) Clean Zones: It is calculated using the Archie's equation (1942), as follows:

S a RRxo m

mf

xo

n

= ×⎡

⎣⎢

⎤

⎦⎥Φ

1/

(27)


b) Shaly Zones: It is determined utilizing the average of the Simandoux and Schlumberger

equations, shown as fallows:

Simandoux method :1/Rxo=((Vsh/Rsh)Sw)+((Φm/aRw)Swn)

(28)

Schlumberger equation: 1 1 2 22

RV

R aRS

xo

shV

sh

m

mfxo

nsh

= +⎡

⎣⎢⎢

⎤

⎦⎥⎥×

−( / ) //Φ (29)

3- Irreducible Water Saturation:

It is a thin film of water around the grains of rocks, which can not

be move out with oil or water. It can be estimated by crains method

(1986) from the general formula:

Swir=(ΦtxSw)/ΦE (30)

B-4-3- Hydrocarbon Saturation:

The hydrocarbon saturation is calculated through the formula:

Sh = 1 − Sw (31)

Such hydrocarbons are normally differentiated into their residual (Shr) and

movable (Shm) habitates, as shown:

Shr = 1 − Sxo (32)

Shm = Sh − Shr (33)

ISO-PARAMETRIC MAPS OF MHEIHERRAT FORMATION:

The water saturation map (Fig. 16) shows that, the water proportion attains

its maximum value of 81% at TANKA-3 well and the minimum value of 48% at GS

196-1A well localities. The irreducible water map Fig. (18) illustrates generally

high irreducible water component with general trend of increasing towards the


central part of the area. The reducible water type increases in the opposite

direction of the irreducible one as shown in Fig. (19).

The hydrocarbon saturation map (Fig. 17) reveals its maximum record of

52% at GS 196-1A well and the minimum value of 19% at TANKA-3 well with a

general trend of increasing towards the northeast direction in the opposite

direction of the water saturation trend for that body. The residual hydrocarbon is

generally higher than the movable one that increases gradually towards the north

direction (Fig. 20). Figure (21) reflects that the movable hydrocarbon increase to

the east of the study area, which varies from 25% at WFB-1 well in the east of the

study area to 0% at TANKA-4 well in the west.

Total Porosity Distribution Map of Mheiherrat Member:

Generally, the porosity distribution of Mheiherrat Member decreases

gradually southeasternward (Fig. 14), in which the minimum porosity value (9%) is

represented at WFB-1 well in the southeastern part, till reaches its maximum

value (31%) at TANKA-4 well.

SUMMARY AND CONCLUSIONS The present work deals with the computerized well-log analysis for twelve

wells (HH 84-1, GG 85-1, WFA-1, WFB-1, GS 216-1, GS 206-1A, GS 207-1A, GS

197-2, GS 196-1A, TANKA-1, TANKA-3 and TANKA-4.), which are distributed in

the centeral part of the Gulf of Suez, Egypt. Such an analysis was carried out for

Mheiherrat Formation selected in the Lower Miocene sequence. These formation

are very important from the point of view of the petroleum exploration in this

province.

The available open-hole well-log data, used in the analysis of these unit,

are in the form of resistivity logs (deep and shallow), porosity tools (density,

neutron and sonic) and the gamma-ray log. Added, the composite logs and other

geologic data are given for the geological interpretation of the deduced

petrophysical model of the studied area. A qualitative interpretation for the


composite logs was done to get a preliminary idea about the lithology, porosity

and fluid saturations of the evaluated units.

Well-log system, followed, is started by the determination of the formation

temperature, then correcting the fluid and rock resistivities to the actual

temperature at correspondence depth and also the other environmental

corrections.

The shale percentage is increase in the southeastern and northwestern

parts of the area which, reaches its highest value of 30% at GG 85-1 well in the

south eastern corner of the studied area while it decreases to 7% at TANKA-4 well

locality in the southwestern part.

Generally the porosity of Mheiherrat Formation decreases gradually

southeastern ward in which the minimum porosity value is (9%) is represented at

WFB-1 well in the southeast part till reaches its maximum value (31%) at TANKA-

4 well.

The water saturation of Mheiherrat Formation shows that, the water

proportion attains its maximum value of 81% at TANKA-3 well and the minimum

value of 48% at GS 196-1A well localities. The irreducible water map of

Mheiherrat Formation shows high irreducible water component with general trend

of increasing towards the central part of the area. The reducible water type

increases in the opposite direction of the irreducible one .

The hydrocarbon saturation map of Mheiherrat Formation shows reveals

its maximum record of 52% at GS 196-1A well and the minimum value of 19% at

TANKA-3 well with a general trend of increasing towards the northeast direction in

the opposite direction of the water saturation trend for that body. The residual

hydrocarbon is generally higher than the movable one that increases gradually

towards the north direction .The movable hydrocarbon increase to the east of the

study area, which varies from 25% at WFB-1 well in the east of the study area to

0% at TANKA-4 well in the west.

However, it can be concluded that, the reservoir quality increases to the

east direction .


REFERENCES

Archie, G.E. (1942): "The Electrical Resistivity Logs as an Aid in Determining Some Reservoir Characteristics ";

Trans. AIME. \/01. 146.P.54- 67

Clavier, C., Huyle, W.R. and Meunier, D. (1971) : Quantitative Interpretation of

T.D.T. Logs; Part I and II, Journal of Petroleum Technology, No. 6.

Crain, E.R. (1986) : The Log Analysis Hand Book; Penn-Well, Publ. Co., Tulsa,

Oklahoma, U.S.A.

Dresser Atlas (1979) : “Log Interpretation Charts”; Houston, Dresser Industries,

Inc.

Hilchie, D.W. (1978) : “Applied Open Hole Interpretation”; Golden Colorado, D.W.

Hilchie, Inc.

Hilchie, D.W. (1982) : “Advanced Well Logging Interpretation”. Golden Colorado,

D.W. Hilchie, Inc.

EGPC (Egyptian General Petroleum Corporation) (1996) "Gulf of Suez oil fields (A comprehensive Overview)" EGPC, Cairo: 387.

Pickett, G.R; (1963): "Acoustic character logs and their applil:ation in formation evaluation"; Jour. Pet Tech., Trans.. AIME. Pickett,G.R. (1973):" Pattern recognition as a mean of formation evaluation". Paper presented at the 14th Annual logging Symposium. SPWLA, May.P.6-9. Schlumberger (1972) : “The Essentials of Log Interpretation Practice”,

Schlumberger Publication.

Schlumberger (1974) : “Log Interpretation, Volume II, Application”; Paris, France.

Schlumberger (198 7) : “Log Interpretation Manual”.

Schlumberger Ltd, (1989) : Log Interpretation Principles and Applications.

Simandoux, P.(1963) "Mesures dielectriques en milieu poreux, application a mesure des saturation en eau, etude du comportement des massifs argileux. revue de I institut francais du petrole", supplementary issue.

Steiber, R.G. (1973) : “Optimization of Shale Volumes in Open Hole Logs”; Jour.

Pet. Tech.


Wyllie, M.R.J. (1963) : “The Fundamentals of Well Log Interpretation”; New York

Academic Press.


HEIHER

HEIH

FIG. (2) GENERALIZED STRATIGRAPHIC COLUMN

OF THE GULF OF SUEZ. (after EGPC,1996)

petrophysical characteristic and effect on reservoir fliud

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