early hydrocarbons movement using capillary … · reservoir type. thomeer [2], brooks corey [3],...

JOURNAL OF INTERNATIONAL ACADEMIC RESEARCH FOR MULTIDISCIPLINARY Impact Factor 2.417, ISSN: 2320-5083, Volume 3, Issue 9, October 2015

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EARLY HYDROCARBONS MOVEMENT USING CAPILLARY PRESSURE DATA AND WIRELINE LOGS IN CLASTIC RESERVOIR IN SOUTH OF ALGERIA.

HASSI-GUETTAR FIELD

AMINA BOUNOUA* DR. HAKIM BENTELLIS**

*Ph.D., Student, University of Science and Technology Houari Boumediene, Algeria

**Professor, University of Science and Technology Houari Boumediene, Algeria

ABSTRACT

In tight reservoir evaluation, water saturation from logs is obtained with a relatively

high uncertainty. The combination with capillary pressure measurements acquired in

laboratory on samples taken from different reservoir levels generally leads to substantial

accuracy improvement when conciliation is successful. The operation is often challenging

particularly when translating the capillary laboratory measurements to reservoir conditions

and the stress relaxation induces some petrophysical properties variation on the cores. The

present study was conducted with data from a tight sand oil field located in the south of the

giant Hassi-Messaoud in Algeria. The combination of the two data sets gave an overall good

comparison and hence uncertainty was improved except for some particular wells. The

significant difference in water saturation was observed close to the transition zone and

indicates that the field was not in equilibrium and a communication with another neighbor

field is expected to explain the fluid movements for these wells causing saturation changes.

KEYWORDS: Tight Sand -Water Saturation -Capillary Pressure -Fields Communication.

1. INTRODUCTION

The combination of capillary pressure data and well logs gives a better results of water

saturation estimation compared to the case where only wireline logs are used. Particularly in

low porosity reservoirs (below 13 pu). Especially in oil base mud situation, where only the

induction tools can be used with a high uncertainty resistivity measurement.

In subsurface, the hydrocarbon’s migration process ends when the balance between the

buoyancy forces and capillary forces is reached. The hydrocarbons distribution in the

reservoir is then defined by Laplace equation [1] that allows the use capillary pressure data

for water saturation estimation.


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After laboratory capillary pressure data editing, a normalization and filtering step is done to

model the capillary pressure function. Different functions can be used depending on the

reservoir type. Thomeer [2], Brooks Corey [3], Leverett [4].

The studied tight sands of Hassi-Guettar (HGA) oil field, located in the south of Hassi-

Messaoud field in Algeria.

The stress relaxation have a significant impact on the core permeability. Consequently a

thorough analysis is conducted to correct the above phenomena when suspected.

Core-Logs depth shift and scale measurement effect are also challenging, are considered to

explain some anomalies.

The final results show that the water saturation derived from logs is up to 40% higher than

the one derived from capillary pressure. This difference is observed in the transition zone.

Leading to the conclusion that the field is not in equilibrium anymore and a communication

with other surrounding fields is suspected. This approach was used to assess the volume of oil

displaced.

2. Geology

A-Structure

Hassi-Guettar (HGA) field is located in the South of the Giant Oil field Hassi-

Messaoud in the south east on shore Algeria. It is part of the Hassi-Messaoud Mega Dome

structure generated during the Hercynian orogeny at the end of the Paleozoic. The upper part

of the Cambro-Ordovician reservoir is eroded with different degree from one location to

another.

B-Stratigraphy

The Cambro-Ordovician is the main reservoir, it’s stratigraphic sequence is a silicoclastic

series uncomfortably overlying an eruptive metamorphic basement. The sequence consists of

the following levels:

The Cambrian:

R3: Poorly consolidated micro conglomeratic clay sandstones inter bedded with clay

siltstone 300 m thick.

R2 : coarse sandstones with clay inter bedded shaly siltstones; the top part of this reservoir

has the best matrix properties and average thickness around 40 m.

In the studied area the units R2 and R3 are below the Oil Water Contact.


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Ra : the main reservoir, with thickness 100 to 130 m, the uppermost part of Ra, 40 to 60 m

thick with a relatively fine clayey sandstones containing skolithos. The lowermost part of the

Ra is 70 to 95 m thick, medium to coarse sandstones with interbedded siltstone.

The Ordovician :

It is represented by the Ri unit : 45 to 50 m thick with 3 sub units:

The 8 m lowermost part of the Lower Ri has the relatively the best petrophysical properties .

The Middle Ri is present with thin sandstone layers interbedded with siltstones. The upper Ri

is less clean than the lower Ri.

C-Depositional environment and diagenesis

The lower R3, R2, and the main part of the Ra units correspond to a vast complex of

braided channels, overlain by the upper Ra and Ri wich are a shallow marine sandstones

containing skolithos and many clayey siltstone levels.

The Ri and Ra very frequently show a predominance of silica; kaolinite is the main clay

mineral. A growth secondary silica is observed in the fault zones and as a fill for faults and

fractures.

The R2 and R3 show predominance in of detrital or authigenicillite in relation to silica.

2. Capillary pressure equations

For two immiscible fluids (air-brine) in equilibrium in a thin tube, the capillary pressure is the

pressure difference across the interface between the two fluids (Pg and Pw), expressed by :

Pc = Pg - Pw = 2.σ.cos θ / r ………….(1),

With σ, θ and r respectively the interfacial tension, the contact angle and the radius of the

capillary tube.

The interfacial tension is related by the Van Der Waals electric molecular interaction forces.

Near the liquid surface these forces are not compensated by symmetry anymore like they do

for points located inside the fluid, thus the resulting tension force is directed to the half plane

containing the center of the meniscus, figure 1 shows the effect on a capillary tube.

The contact angle is defined by the equilibrium state between the three surface tensions:

σsg, σsl, σlg existing in the various interfaces as mentioned in figure 2.

It indicates the solid wetting preference between the two immiscible fluids. The wettability is

obtained by the Amott Harvey or USBM tests [5]


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In real reservoir r represents the pore radius distribution, for the current study, it is estimated

using Kozeny Carman porous model [6]: r = [(2τ) (k /Φ)] 1/2 ………….(2)

At balance, the capillary pressure is equal to the buoyancy force: PC = Δρ.h.g ………(3)

Δρ is the density difference between the two fluids,

g is the gravity, and h is the height above the free water level ( FWL ) .

Thus, the height h is inversely proportional to the capillary radius :

h = 2.σ .cos ϴ / r. Δρ.g……. (4)

The above equation define the transition zone height above the FWL.

3. Laboratory measurement:

Samples were selected from the different reservoir zones, As the Kaolinite tends to

make the reservoir rock more oil wet in the oil zone, to simulate the primary drainage, a

series organic solvent were used to recover the initial wettability condition. Then used for

capillary pressure measurement with the air – brine porous plate equipment (figure 3).

The air is injected by pressure steps. For every step, the saturating water is displaced through

the low permeability porous plate (approximately 1 mD)until the equilibrium is reached. No

air leak through the sample (breakthrough) is observed until irreducible water saturation is

reached within the sample. The capillary pressure - pressure difference - is provided by the

measured air pressure and the atmospheric pressure for the water pressure, because of the

capillary contact between the sample and the plate.

The air displacing water mimics the primary drainage taking place during the oil migration

into the reservoir pore space.

4. Capillary pressure model (Leverett J function)

As the used technique is time consuming only several data points by samples are

acquired to covers the whole pressure range. Furthermore, as measurement, these data are

inevitably affected by some uncertainties that might have an effect on the output. The

mitigation approach is to match the data to one of the model published functions that

represents the formation type.

For the present case, as the studied sandstones are with a limited pore radius distribution

window the Leverett J-function is suitable for the interpolation and normalization.


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According to Kozeny Carman model (Carman, 1937) replacing the average pore radius

equation 2 in equation 1 :

Pc =2 (2τ)- 1/2.σcos ө.(k /Φ )-1/2=Δρ. g.h……(5)

And the Levrett J function is : J = C *(Pc/σcosө) *(K/Φ) ½ …………………………….(6)

With C = 3.081

Replacing Pc by Δρ. g.h, equation (6) became:

J = [C * h (ρw- ρo) *(K/Φ)1/2] / (σcosө) ………..(7)

For two given fluids and a rock type :

J = c * h …………………………………….(8)

With C and c constants

5. Application

Sampling and plug preparation:

Samples were collected from 3 wells A, B and C. The samples were visually

inspected and only these without apparent fractures are used for the initial wettability

condition restoration and capillary pressure measurement using a porous plate equipment

described in section 3. The global results are plotted in figure 4.

Leverett J function determination:

The porosity, permeability and the capillary pressure versus water saturation.

Sw versus J function becomes: SW = Swirr + a * Jb…………………….(9)

The above normalization removes the laboratory fluids and petrophysical properties effects,

Thus one function will be defined by rock type (figure 7).

Rock typing and permeability refinement:

On the porosity-permeability plot, 4 rock types are identified (figure 5).

A reasonable dispersionsis obtained for the reservoirs Lower Ri and Ra.

For the Upper Ri , the first two points show higher permeability than expected from the trend,

therefore not considered for the regression line calculation.

Unfortunately these core permeability anomalies are recurrent, a deep investigation indicates

the presence of microscale cracks, most probably induced by the stress release when lifting

the cores to the surface. Consequently a procedure is implemented for future coring.

For the Middle Ri reservoir, only 2 points are available, a simple trend obtained by joining

the 2 points gives a very high slope that generates very high values unrealistic for the field.

An alternative trend gives a slope similar close to other groups, as shown in figure 5.


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Knowing that the input permeability is prone to be affected by the micro-cracks effect, the

values used later in the present analysis have been recalculated from corrected trends with the

following equations:

Upper Ri: Log K = - 0.36 + 18.2Φ

Middle Ri : Log K = -0.79 + 18.6Φ

Lower Ri: Log K = - 0.25 + 19.1Φ

Ra: Log K = + 0.20 + 15.5Φ

With: K mD, and Φ in fraction.

Maximum capillary pressure

The maximum reservoir capillary pressure can be estimated from :

Pc Resmax = 0.1 (ρw- ρo) hmax…………………………9

With:

hmax: the maximum height above the free water level in the field (120 m),

ρo: the oil density (0.676 g/cc),

ρw: the water density (1.162 g/cc).

The calculated maximum capillary pressure in the reservoir value is :Pc Res max = 5.83 kg/cm2

corresponding to Pc Lab max = Pc Res max [σ·cos (ө)]Lab / [σ·cos (ө)]Res = 15.7 kg/cm2

Irreducible water saturation (Swirr) estimation

For equipment limitations in the porous plate the maximum pressure is 2.5 (Kg/cm2),

and Swirr corresponding to a Pc=15.7 kg/cm2 is estimated by linear extrapolation:

SWirr = (Sw)n + A * [PcLab max - (Pc)n ]

With A the slope of the curve for the last two measurements (figure 6).

A tolerated difference of 10% with the last measured Sw.

Saturation Height :

From equation 9: Swr = a * jb

With Swr = Sw- Swirr, the constants a and b are obtained by regression (figure 7).

From equation 8: J = c * h

Sw = Swirr + a * (c * h) b

withSw, Swirrare expressed in %,and h in meter.


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The previous estimated Swirr values are used to define a continuous Swirr function versus √K/Φ

for every rock types, figure 8.

For illustration, 4 curves per rock type h = f (Sw) are generated, corresponding to values of

√K/Φ of 5, 10, 20 and 50. The results are shown in figure 9.

For values √K/Φ = 5, in Ri and Ra reservoirs, Sw remains high even being sufficiently far

above the FWL (respectively Sw = 45 and 40% for h = 140 m). And it is mainly immovable

water.

Saturation profile:

Along the reservoir, for each depth, the porosity log and the rock type are used to

estimate the permeability then Sw is calculated using the saturation height model and with a

FWL 3378 m TVDSS. The results are presented in figure 10 for three wells A, B and C.

6. Comparison with the Saturation from logs

For the well A (figure 10a), the transition zone is along the reservoir Ra. The Porosity

logs varies between 8 and 12pu, with a global good match with cores. Minor differences are

observed locally due to the measurement scale, some core values are higher and other are

lower than log values. Above the transition zone, The log water saturation, blue curve on

track 6 from left, above the top of the transition zone (3352 m) is about 10%, consistent with

water saturation from capillary pressure Sw_J (red curve on the same track). The top Ra

3323-3332 m . The porosity decrease from bottom to top and the difference between the 2

saturation cures increases. Sw log is less accurate due to induction tool uncertainty, blue

curve in track 2. This water is immobile confirmed by the very low water cut of the

production delivered by the perforated sections. The transition zone is between 3355 and

3378 m TVDSS showing a significant difference between the two saturations reaching 70 %

difference for the most porous zone.

In the well B (figure.10b), as mentioned in section 2 the Middle Ri shows from 3350 to

3362m TVDSS a succession of thin sandstone layers interbedded with siltstones with high

Gamma Ray readings. The core porosity is up to 14 pu, these values are not captured by the

porosity log due to the vertical resolution of the neutron –density tools. Within this interval

the Sw log is optimistic due to horn effect on the induction resistivity curve (blue curve on

track 2 from the left) the main difference is located at 3355-3357 m. Similar to well A, just

above the FWL Sw log is up to 50 % higher than Sw core for the interval 3368-3377 m

TVDSS.


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For the well C (figure12c), the well was not cored, but porosity values for lower Ri and Ra

are pretty consistent with other cored wells. For the middle Ri the saturation difference is

related to the induction tool uncertainty and horn effect. A difference of about 27% between

Sw log and Sw core is observed from 3359 to 3369 m TVDSS. Just above the FWL the zone

3374-3377 m shows less difference (11%) due to lower permeability confirmed by the shale

content on track 1 from the left, No difference for the sand shale zone located between 3370-

3374m .

7. Conclusions and Recommendations

Combination of logs and laboratory capillary pressure data is useful to reduce water

saturation uncertainty for fields in equilibrium particularly low porosity reservoirs. A

particular focus is needed to ensure a core-logs depth match. For zone with porosity below 6

pu induction tool became less accurate and core calibration is required. For interbedded sand

shale thin layers a horn correction is recommended. For permeable zones above the free

water level showing Sw log higher than Sw core could indicate a communication with other

fields. A thorough investigation and detailed remaining volumes calculations are

recommended prior a field development planning.

References

1. Amyx, J.W., Bass, D.M. and Whiting R.L., 1960. Petroleum Reservoir Engineering- Physical Properties, Mc Graw-Hill

2. Anderson, W. G., 1986b, Wettability literature survey—Part 2, Wettability measurements: Journal of Petroleum Technology, v. 38, p. 1246–1262., 10., 2118/13933-PA

3. Brooks, R.H. and Corey, A.T. 1964. Hydraulic properties of porous media. Hydrology Paper No. 3, Colorado State University, Fort Collins, Colorado, 22–27

4. Carman, P.C. 1939 Permeability of saturated sands, soils and clays. J AgrSci 29 262-273 5. Leverett, M.C. 1941. Capillary Behavior in Porous Solids. Trans. of AIME 142 (1): 152-169 6. Leverett, M.C., Lewis, W.B., and True, M.E. 1942. Dimensional-model Studies of Oil-field Behavior.

Trans. of AIME 146 (1): 175-193. SPE-942175-G 7. Thomeer, J.H.M. 1960. Introduction of a Pore Geometrical Factor Defined by the Capillary Pressure

Curve. J Pet Technol 12 (3): 73-77. SPE-1324-G

List of figures

Figure 1: Pressures and surface tension applied to the meniscus of the oil - water interface in

a capillary tube.

Figure 2: Contact angle equation.

a-Balance between tensions surface σlg, σls, σsg.

b-Contact on a capillary tube angle.

Figure 3: Capillary pressure measurement by porous plate apparatus.


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Figure 4: Capillary pressure versus Water saturation plot.

Figure 5: Porosity –Permeability relation by Rock type.

Figure 6: Irreducible water saturation estimation in the laboratory.

Figure 7: Mobile saturation versus J function, power regression.

Figure 8: Irreducible water saturation estimation.

Figure 9a: Saturation Height Function for Upper Ri.

Figure 9b: Saturation Height Function for Middle Ri.

Figure 9c: Saturation Height Function for Lower Ri.

Figure 9d:Saturation Height Function for Ra.

Figure 10a: Saturation from Capillary pressure and logs Well A.

Figure 10b: Saturation from Capillary pressure and logs Well B.

Figure 10c: Saturation from Capillary pressure and logs Well.

Figure 1: Pressures and surface tension applied to the meniscus of the oil - water interface in

a capillary tube.

Figure 2: Contact angle equation . a-Contact Angle as a result of equilibrium between

tensions surface σlg, σls, σsg. b-Contact Angle on a capillary tube angle.


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Figure 3: Porous plate apparatus for capillary pressure measurement.

Figure 4: Capillary pressure versus Water saturation plot.


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Figure 5: Porosity-Permeability relation by Rock type

Figure 6: Irreducible water saturation estimation in the laboratory.


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Figure 7: Mobile saturation versus J function, power regression.


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Figure 8: Irreducible water saturation estimation.

Figure 9a: Saturation Height Function for Upper Ri.

Figure 9b: Saturation Height Function for Middle Ri.


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Figure 9c : Saturation Height Function for Lower Ri.

Figure 9d :Saturation Height Function for Ra.

Figure 10a: Saturation from Capillary pressure and logs Well A.


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Figure 10b: Saturation from Capillary pressure and logs Well B.

Figure 10c: Saturation from Capillary pressure and logs Well C.

early hydrocarbons movement using capillary … · reservoir type. thomeer [2], brooks corey [3],...

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