Influences of Asphaltene Deposition on Rock/Fluid Properties of Low Permeability

Influences of Asphaltene Deposition on Rock/Fluid Properties of Low Permeability

Carbonate Reservoirs

Shedid A. Shedid, United Arab Emirates University, Al-Ain City, P.O. 17555, U.A.E.

Abstract

Asphaltene deposition has profound effects

on oil flow through porous medium. The

investigation of the influences of asphaltene

precipitation on carbonate reservoir rocks has minor

interests in comparison to studies investigated

sandstones ones. Therefore, this study is

undertaken to provide accurate insights, especially

for carbonate reservoirs of low permeability.

In this study, two groups of experiments are

undertaken. The first experimental group

investigates effects of asphaltene precipitation on

(a) petrophysical properties of carbonate rocks,

including absolute permeability, effective porosity,

and hydraulic radius, and (b) on oil-water relative

permeability and water flooding performance. The

second group searches for the effects of asphaltene

precipitation on capillary pressure and pore size

distribution of low permeability carbonate

reservoirs. Conducted experiments are achieved

using actual reservoir liquids of crude oil and brine,

flowing through actual carbonate cores under

similar reservoir conditions of temperature and

pressure.

The results indicated that asphaltene

precipitation damages absolute permeability and

hydraulic radius drastically, reduces effective

porosity, and improves relative permeability of

water for different asphaltene contents of crude oil

flowing through carbonate reservoirs. In addition,

oil reservoirs of high asphaltene content have

shown higher values of irreducible water saturation

than that ones of low asphaltene content in their

crude oils. Precipitation of asphaltene in carbonate

rock causes changes in the position of capillary

pressure at high mobile oil saturation and reduces

values resulted for pore size distribution curves,

especially for small pore radii carrying crude’s of

high asphaltene content.

Neglecting the proven influences of

asphaltene precipitation may lead to erroneous

description of carbonate reservoirs. Therefore,

analysis of petrophysical properties and pore

size distribution of carbonate reservoirs has to

be updated during the extended life of oil

reservoir and based upon accurate values of

asphaltene content of the flowing crude oils.

Applications of the attained results of

this study are expected to provide real

improvement in reservoir description, more

reliable estimation of oil reserves, accurate

predicted values of reservoir rock damage, and

also better descriptive functions for future

reservoir simulation studies.

Introduction and Review

Asphaltene deposition in oil reservoirs and/or

production facilities causes a remarkable reduction

of formation productivity/injectivity. Asphaltenes

are described in terms of their solubility in nalkanes

and defined as the complex molecules,

which are soluble in benzene and insoluble in low

molecular-weight n-alkanes as shown by Long1 and

Speight et al2 . Asphaltenes are also defined as that

fraction which is soluble in toluene and insoluble in

n-pentane or n-heptane at a dilution ratio of 40

volumes of solvent per one volume of petroleum

sample as explained by Speight et3. Asphaltene

deposits are unwanted in petroleum industry

because of many problems related to their

deposition.

Kamath et al4. studied the effect of

asphaltene deposition on permeability, pressure

drop, and displacement performance of oil by water

using one core of consolidated Berea sandstone and

two unconsolidated sandpacks. The used cores and

sandpacks had porosity in the range of 27.86 to

32.67 %, respectively and permeability in the range

of 236 to 2380 md, respectively. The results

showed that asphaltene deposition caused

permeability reduction and improvement of oil

displacement by water due to improvement in oil

relative permeability. It is also well documented for

sandstone reservoirs that asphaltene deposition

reduces permeability (Minssieux5 1997, and

Minssieux et 6. 1998) and/or alters wettability (de

Pedroza et7. 1995). Minssieux (1997) studied the

influence of using different asphaltene contents (in

the range of 0.1 % to 6.0 wt. %) on oil permeability

of sandstone and clayey (containing kaolinite)

sandstone rocks. This study showed that asphaltene

deposition caused permeability reduction similar to

the formation damage caused by solid migration of

fine grains.

With respect to carbonate reservoirs, little

interest is devoted for investigating this problem.

Ali and Islam8 presented an experimental and

numerical study about the effect of asphaltene

deposition on permeability reduction. They used

powdered limestone samples having average

porosity of 35 % and average permeability of 11.3

md. The results showed that asphaltene deposition

reduced permeability and its consequent pore

plugging were strongly dependent upon flow rate

and the existence of a continuous plugging regime

at a high flow rate.

It is difficult to correlate the problems due to

asphaltene deposition with the asphaltene content of

the crude oil. The reason is the existence of the

Venezuelan Boscan crude with 17 wt. % asphaltene

content which produced nearly trouble free as

reported by Leontartits and Mansoori9 while the

Algerian Hassi-Messaoud crude with only 0.062 wt.

% asphaltene content met with severe difficulties

during production8,10. This problem may be

overcome by development of separate correlation

for each reservoir and also for each asphaltene

content of the flowing crude oil. Therefore, this

study is designed to investigate the influences of

asphaltene deposition for different asphaltene

contents of crude oil on petrophysical rock

properties and/or on description of United Arab

Emirates carbonate reservoirs.

Experimental Models and Procedures

Models

The experimental model used to carry out

flow runs is schematically described in Fig. 1. This

experimental set-up consists of two constant rate

pumps, a vacuum pump, radial core holder, two

fluid barrels, seven pressure transducers, back

pressure regulator, an effluent condenser, rigid

valves, and collector tubes. The core holder has a

rubber sleeve with a size of one-inch in diameter

and two-inch in length. A constant overburden

pressure of 450 psia is applied around the core

sleeve to prevent fluid(s) leakage or bypass around

the core sample at constant temperature of 150 oF.

The selected pressure and temperature conditions

are similar to many of the United Arab Emirates

carbonate reservoirs.

The pump is operated at constant rate of 1.0

cc/min during all dynamic flow experiments of this

study. This model has been used to conduct

experiments investigating effects of asphaltene

deposition on absolute permeability, effective

porosity, relative permeability and waterflood

performance.

Designed experiments to investigate the

influence of asphaltene deposition on reservoir

description (using capillary pressure and pore size

distribution curves) have been performed using

capillary pressure apparatus (Core Lab. Inc.,

Catalog No. 118). The apparatus is mainly consists

of fluid reservoir, ceramic plate, and low and highpressure

gauges/regulators. This technique is

called a semi-permeable disk measurement of

capillary pressure11.

Procedures

With respect to the flow experiments

investigating the effects of asphaltene deposition

on absolute permeability, effective porosity,

relative permeability, and waterflood performance,

the following procedure is applied:

1. Actual consolidated carbonate rock samples

are cut (1.0 inch in diameter and 2.0 inch in

length) from local pay formation, Table 1.

The cores are evacuated for almost 24 hours

and then saturated with brine of 100,000 ppm

NaCl (similar to water formation salinity of

the reservoir under investigation).

2. Initial effective porosity of the used cores

(samples 1, 2, and 3) is measured from the

weight difference of dry and saturated core.

3. The core is inserted into the flood system and

a constant flow rate of 1.0 cc/min is applied

to attain a steady state flow condition.

Absolute permeability of brine is calculated

using Darcy’s Law.

4. Cyclohexane is used to flood the core (flow

rate = 1.0 cc/min) until connate saturation

condition is well established.

5. Reservoir fluids of certain asphaltene

content are used to flood the core

(asphaltene content (AC) of 0.06, 0.87, and

1.50 wt. %) and the pressure drop is

carefully monitored. Permeability damage of

the core is calculated. In addition, equal

volumes of outlet oil/water are collected,

measured, and their asphaltene content are

determined using IP 143 method. The

deposited volume of asphaltene is subtracted

from effective pore volume to calculate

reduction in effective porosity.

6. The core is again flushed with cyclohexane

at the same constant flow rate (1.0 cc/min)

to determine the final permeability and to

evaluate the core damage due to asphaltene

deposition.

7. The same core samples 1, 2, and 3 are

cleansed with toluene to extract the residual

crude oil with its asphaltene for almost 2

days (using Lab-Line Multi-Unit Extraction

Heater, Melrose, ILL). Then the core is

dried. For measurements of relative

permeability and evaluation of waterflood

performance, the above-described steps 1, 2,

3 and 5 are identically repeated while steps

4 and 6 are excluded. After the core is

completely cleansed, then it is saturated with

crude oil of specific asphaltene content.

Waterflood is started and continued until no

more additional oil is produced. The

collected samples of oil and water are

measured and used to calculate fractional

flow of water and also to calculate oil-water

relative permeability. The alternate method12

is used as a steady-state method for

estimating the relative permeability.

Asphaltene content of the collected crude oil

samples is measured using IP 143 method.

With respect to the influence of asphaltene

deposition on capillary pressure and pore size

distribution, the following experimental method is

used to measure the capillary pressure:

1. The above-described steps 1, 2 and 3 are

identically followed for core samples 4, 5, and

6, sequentially.

2. The core is inserted properly into the capillary

pressure apparatus. The cell of the apparatus is

completely filled with crude oil to eliminate

air entrapment. The used crude oils have

different asphaltene contents of 0.06, 0.87,

and 1.50 wt. %, respectively.

3. The applied pressure of the displacing oil is

increased in small increments.

4. After each pressure increment, the

corresponding outlet volume of oil/water is

monitored and collected at static equilibrium.

Water saturation is estimated by dividing

residual water volume by pore volume of the

used core sample.

5. Capillary pressure is plotted versus calculated

water saturation for different asphaltene

contents of the used crude oils.

Results and Discussion

1. INFLUENCE OF ASPHALTENE

PRECIPITATION ON

1.1 Absolute Permeability and Effective

Porosity

Three dynamic flow experiments were carriedout

using carbonate core samples 1, 2, and 3,

respectively inserted into the experimental model,

shown in Fig. 1. Three different asphaltene contents

of a crude oil (AC = 0.06, 0.87, and 1.50 wt.%)

produced from different pay zones of the same local

oil reservoir were used. Table 1 presents

petrophysical properties of the used core samples.

The obtained results of oil permeability damage

were dictated and compared in Fig. 2. Three

empirical correlations in the form of: K= A*(PVI)2 –

B*(PVI) + C were developed with very good

correlating coefficients in the range of 0.95 to 0.98,

Appendix A. Where A, B, and C are correlating

coefficients, depending upon the asphaltene content

and pore volume injected of the crude oil. The

results indicated that permeability damage increases

continuously as the pore volume injected of the

crude oil increases for different asphaltene content of

the crude. It is shown that higher asphaltene content

of the crude oil causes more permeability reduction

of carbonate rocks. Permeability damage factor is

given by K ( o d ) o DF = K − K / K .

Table 2 presents permeability damage factor for

different asphaltene content. In addition, remarkable

permeability damage occurs after almost 20-pore

volume injected. The ratio of deposited asphaltene

concentration on carbonate rock surface to its initial

one (C/Co) is plotted versus pore volume injected

(PVI), as shown in Fig. 3.

With respect to the effect of asphaltene

deposition on effective porosity, The same data

extracted from experiments 1, 2 and 3 were used to

calculate the damaged porosity (by subtracting

volume of deposited asphaltene (by dividing

deposited asphaltene by asphaltene density = 1.15

gm/cc) from initial pore volume of the used core

sample) versus pore volume injected of crude oil,

Fig. 4. It is clear that porosity damage is a function

of flowing time (or PVI). The higher the pore

volume injected of crude oil leads to more reduction

in porosity. Damage factor of porosity is defined as:

1.2 Relative Permeability and Waterflood

Performance

Relative permeability was calculated using

data extracted from experiments 4, 5, and 6 under

steady-state conditions. The obtained relative

permeability curves are shown in Fig. 5. This graph

shows a reduction in oil permeability when

asphaltene content of the crude oil increases. This

conclusion violates the conclusions obtained for

sandstone reservoirs4. The reason may be attributed

to the change in rock wettability since Berea

sandstones and sandpacks are almost strong waterwet

than carbonate rocks, which have intermediate

to strong oil-wet. The collected volumes of oil

and/or water are used to calculate fractional flow of

water (fw), which is plotted versus water saturation,

as shown in Fig. 6.

Analysis of the water flood performance

shows that the higher of asphaltene content of the

crude oil accelerates water breakthrough and may

degrade waterflood performance. This analysis is

based upon obtained values of water saturation prior

to breakthrough (Swb) versus asphaltene content, Fig

7. A tangent13 is drawn to the fractional flow curve

from irreducible water saturation. Extrapolation of

the tangent until it intersects the horizontal line

corresponding to Fw = 1.0, the intersection provides

values of Swb. This plot, Fig. 7, shows that the

increase of asphaltene content of the crude oil leads

to lower values of water saturation prior to water

breakthrough occurs (earlier water breakthrough).

Fig. 7 can be used to predict expected values of Swb

, based upon the asphaltene content of the reservoir

located in the same/adjacent region. Using curvefitting

technique, the following equation is

developed foe the same purpose of prediction water

saturation values for oil reservoir of asphaltene

deposition problems. This equation is given by:

Swb = -15.558* AC + 71.769, R2 = 0.9965.

2. INFLUENCES OF ASPHALTENE

PRECIPITATION ON

2.1 Capillary Pressure

Three experiments using carbonate core

samples 4, 5, and 6, Table 3, were undertaken to

study the effect of asphaltene deposition on

capillary pressure curve for different asphaltene

content of crude oil. Fig. 8 dictates the obtained

results and shows dominant effect of asphaltene

content on capillary pressure, especially at lower

values of water saturation. A conclusion can be

drawn from this figure, Fig. 8, which higher

asphaltene content of crude oil of the reservoir

shows higher values of its irreducible water

saturation. This results is also confirmed during

water flood experiments (run 1, 2, and 3), Fig. 6.

This figure shows fractional flow of water versus

water saturation and proves that as asphaltene

content of the crude oil increases, the irreducible

water saturation of carbonate reservoirs increases.

Therefore, It is expected to have higher values of

irreducible water saturation in oil reservoirs having

higher asphaltene content than these reservoirs of

lower content of asphaltene. On the other side,

different asphaltene content of oil in carbonate

reservoirs does not affect the threshold pressure of

that reservoir, as shown in Fig. 8.

2.2 Pore Size Distribution

Determination of pore size distribution is

considered as key parameter for many fluid

transport properties of porous medium14. The use of

individual parameter such as porosity or

permeability, or bi- lateral parameter such as

hydraulic radius (defined as permeability divided by

porosity) does not represent the key variable that

provides better description/interpretation of the

damage caused by asphaltene precipitation. The

current study suggests and uses pore size

distribution as an important parameter to analyze

damage of carbonate reservoirs caused by

asphaltene precipitation. The pore size distribution

involves the extracted data from capillary pressure

and petrophysical properties of the rock.

The maximum pore throat of the sample is

calculated at maximum water saturation Sw-max = 1-

Sor while minimum pore throat of the sample is

calculated at irreducible (minimum) water

saturation Sw-min = Swirr .

Pore size distribution can be used to analyze

reduction in permeability caused by deposition of

asphaltene. The obtained results are plotted as

surface average area distribution (or pore size

distribution) versus pore radius, as shown in Fig. 9.

It is obvious that the increase of asphaltene content

of the crude oil from 0.06 to 1.50 wt. % reduces

surface average area from 0.60 to 0.22 m2 (almost

63 % reduction) for pore radius of 2 micron. The

trend of reduction in surface area decreases as pore

radius increases, especially for pore radius greater

than 9.0 microns. This provides more interpretation

to permeability damage since small pores (less than

9.0 micron in radius) shows higher sensitivity to

more asphaltene deposition. Pores having pore

radius bigger than 9.0 micron show almost the same

distribution since asphaltene deposition may reduce

surface area open to flow. This interpretation again

provides good tool for choosing the required

particle size for any EOR, mud, and any other

material(s), which may be injected into the

reservoirs. In addition, the precipitation of

asphaltene does not distort the shape of pore size

distribution curve since all investigated asphaltene

contents of the crude or different rock

permeabilities show the same trend shape of pore

size distribution.

CONCLUSIONS

This experimental study was carried out to

investigate the influences of asphaltene deposition

using different asphaltene contents of the crude oil

on petrophysical properties and pore size

distribution of carbonate reservoirs. The following

conclusions are obtained:

1. Asphaltene deposition decreases the

petrophysical properties of absolute

permeability and effective porosity of low

permeability carbonate rocks for different

asphaltene contents of the flowing crude oils.

Permeability and hydraulic radius damage

factors of carbonate rocks are much more severe

than porosity damage one for the same

rock/fluid properties and under identical flow

conditions.

2. Asphaltene precipitation in carbonate reservoirs

improves water relative permeability for

different asphaltene contents of crude oil and

therefore accelerates water breakthrough during

waterflood of oil reservoirs of higher asphaltene

contents.

3. Asphaltene deposition decreases capillary

pressure values with respect to their assigned

water saturations. Higher asphaltene content of

the crude oil shifts capillary pressure curves in

the direction of more irreducible water

saturation values. Therefore, capillary pressure

curves have to be updated during the extended

life of oil reservoirs having asphaltene

deposition problem.

4. Pore size distribution has been used for

interpretation of asphaltene deposition in

carbonate porous rocks. It provides good

microscopic explanation for rock damage.

Acknowledgement

The author expresses his sincere thanks to

the administration of Abou Dhabi National Oil

Corporation (ADNOC), United Arab Emirates

(UAE) for financial support of this study and also

for providing required fluid(s) and reservoir data.