pet524 3a saturation

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Chapter 4 – Saturation

4.1

4.1 Saturations

The pore spaces in underground rocks that form oil and gas reservoirs are always

completely saturated with fluid. In the pores of the reservoir, there is never an occasion or

location where nothing exists (i.e., truly "void space”). The pores are completely filled with

some combination of the following fluids: (1) oil and its associated impurities in the liquid

phase; (2) natural gas and its associated impurities in the vapor phase; (3) water--either

connate water or water that flowed or was injected into the reservoir.

During deposition, when sediments were being deposited (usually in an aqueous

environment), the pores were completely saturated with water (i.e., water saturation was

100% of the pore space). Later, during deep burial, compaction, and partial cementation, the

water may have changed in composition, but the saturation remained 100% unless

hydrocarbons entered the pores and forced the water out.

If the water-saturated pores happen to be near an active hydrocarbon source rock,

such as organic-rich shale, and the pores are in pressure communication with the source rock,

hydrocarbons can enter the pores and occupy space. Normally, the hydrocarbons are less

dense than the water, and the resulting buoyant force causes the oil or gas to migrate through

the porous, permeable rock until it escapes at the surface or is stopped by an impermeable

layer that forms a seal. If there is sufficient closure the hydrocarbon accumulation may result

in a commercial oil or gas reservoir.

In the pores of oil or gas reservoirs, there always remains some water that was there

before the hydrocarbon entrapment. At any time during the life of an oil or gas reservoir, the

following relationship must hold true.

0.1g

Sw

So

S (4.1)

where:

pV

gV

volume pore

volumegasg

S

pV

wV

volume pore

volumewater w

S

pV

oV

volume pore

volumeoilo

S

(4.2)




4.2

It is common for oil or gas saturation to be zero, but water saturation is always greater than

zero.

Saturation is a direct measure of the fluid content of the porous rock. It therefore

directly influences the hydrocarbon storage capacity of the reservoir. Other uses are the

identification of gas/oil or oil/water contacts by changes of residual saturation with depth,

and indirectly it is used as a correlation variable to estimate the productivity of reservoir

rocks.

4.1.1 Saturation distribution in reservoirs

During hydrocarbon accumulation in the reservoir, water saturation can be reduced to some

small value, typically 5-40%, after which no more water can escape from the pores. This

occurs when water saturation becomes immobile, at the irreducible water saturation.

Petroleum literature contains several symbols for water saturation; Swi, Swc, Swir .

Care must be taken to ensure correct interpretation of the symbol. The following definitions

should help.

1) Swir -irreducible water saturation, below which water cannot flow.

2) Swc -connate water saturation existing on discovery of the reservoir. It may or may not be

irreducible. Be careful!

3) Swi -may mean irreducible, connate, or interstitial, which means saturation among the

interstices, or pores. Interstitial may or may not signify irreducible. It may be the

value on discovery of the reservoir, or the value at any time thereafter. S wi may also

mean initial or original, which truly means the water saturation on discovery, but it

may or may not be irreducible.

Density differences between gas and oil as well as between oil and water result in normal

reservoir situations in which oil floats on water. If there is a free gas phase, the gas floats on

the oil. Keep in mind that there will be some water saturation (at least the irreducible water

saturation) throughout the reservoir, even in the pores at the very top.

Figure 4.1 shows a typical cross section of a reservoir where all three fluid phases are

at mobile saturations. If a container were filled with oil, water, and gas with no porous

medium in the container (porosity = 100%), the fluid interfaces would be distinct and fluid

saturations would be:

gas cap – Sg = 100%;




4.3

oil zone - So = 100%;

aquifer, water zone – Sw = 100%.

Figure 4.1 Cross section of reservoir showing vertical segregation of fluids

However, in actual reservoirs composed of porous rock, the fluid interfaces are not so

distinct. Not only does water exist throughout the oil and gas zones at a saturation of at least

irreducible water saturation, but the fluid contacts are generally spread over a distance of a

few feet to tens of feet, depending on the density difference between the fluids and the

permeability of the rock.

Figure 4.2 shows the spreading of fluid contacts and the normal distribution of fluids in a

reservoir.

Figure 4.2 Normal initial fluid distribution in a reservoir of uniform permeability and static equilibrium




4.4

In Figure 4.2, note the following important points: (1) OWC at 4245 ft.; (2) oil-water

transition zone, 4238.5 to 4245 ft.; (3) GOC at 4233.5 ft.; (4) gas-oil transition zone, 4232.5

to 4233.5 ft.; (5) thickness of oil-water transition zone, 6.5 ft; (6) thickness of gas-oil

transition zone, 1.0 ft; (7) irreducible water saturation, 20%; (8) free water level at 4248 ft.

and the free oil level at 4234 ft. (the levels at which the OWC and GOC would occur in the

wellbore in the absence of a porous medium, or in the reservoir if it were an open container

with 100% porosity).

The spreading of transition zones is a microscopic phenomenon which will be

discussed more in Chapter 5. Figure 4.3 is a close-up of the saturation distribution across the

OWC and through the oil-water transition zone.

Figure 4.3 Microscopic cross section of OWC and transition zone

Factors Affecting Fluid Saturations

A common method of obtaining fluid saturations is from measurements taken on core

samples. Unfortunately, the fluid content in the core is altered by two processes:

1. the flushing of mud and mud filtrate into the adjacent formation, and

2. the release of confining pressure as the core is pulled to surface.




4.5

Figure 4.4 illustrates on a microscopic level the invasion process of a water-based mud into

an oil-bearing formation. The top diagram is prior to being penetrated by the bit, therefore

the saturations present are the connate water and oil. The middle diagram is after the bit has

penetrated the formation and fluid invasion has flushed the original reservoir fluids. Note the

increase in water saturation during this time. The final diagram shows the gas expansion as

the core is brought to the surface.

Figure 4.4 Saturations in Characteristic sand during coring and recovery [CoreLab, 1983]




4.6

An example of saturation changes occurring in the core from insitu to surface conditions is

shown in Figure 4.5. Note the significant decrease in oil saturation due to the invasion

process. Also, note the gas expansion as the core is brought to surface, subsequently

expelling the fluids in the core. In this illustration, primarily water is expelled. Finally, as

the pressure and temperature are reduced, the oil will shrink in volume, therefore also

reducing the saturation.

Figure 4.5 example of saturation changes occurring in the core from insitu to surface conditions

[Helander,1983]




4.7

Several solutions have been proposed to address these problems. To minimize the invasion

problem, it is suggested to use oil-based muds (OBM) as the coring fluid. Figure 4.6 shows a

comparison between two different examples, one using water-based mud and the second

using oil-based mud. A significant improvement in obtaining original reservoir saturations

occurs using oil-based mud.

Oil67.6%

Wtr 32.4%

Oil53.4%

Oil

26.7%

Wtr 46.6%

Wtr 38.5%

Gas

34.8%

Original After

flushing

At

surface

Water-based Muds

Oil50.9%

Wtr 49.1%

Oil

32.9%

Oil

26.7%

Wtr 49.1%

Wtr 47.7%

Original After flushing

At surface

Oil-based Muds

Filtrate18%

Gas 25.6%

Figure 4.6 Comparison of water- and oil-based muds on the saturation distribution

Other research has lead to using empirical factors to correct measured core saturations to

original conditions [Amyx, et al.,1963]. Furthermore, as an alternative to core analysis,

geophysical well logs provide accurate and continuous measurements for the calculation of

insitu saturations. Also, capillary pressure measurements on samples provide saturation

results.

Selection of the proper coring fluid is essential to obtaining meaningful results. The

objectives and desired tests on the core shown in Table 4.1 below provide a guide for using

suitable coring fluids.




4.8

Table 4.1 Coring objectives and suitable mud types [CoreLab, 1983]

Measurement of Fluid Saturations

In determining the fluid saturations from a core sample, two techniques are

commonly employed; evaporation of the fluids in the pore space, known as the retort method,

and the leaching of fluids in the pore space, known as the Dean-Stark extraction method.

In the retort technique the sample is sealed inside an aluminum cell and then heated in

stages from 400 F to 1100 F. Figure 4.7 is an illustration of conventional retort apparatus.




4.9

Figure 4.7 Picture of a conventional retort [CoreLab,1983]

The advantages to this method is the time for the experiment is short, typically less than 24

hours, and multiple samples can be run simultaneously. The disadvantages are heating

process burns oil to the pore surfaces. This is known as the coking effect and thus results in

oil recovery less than the initial amount in the sample. A correction factor (Figure 4.8) has been empirically developed to overcome this problem.

Figure 4.8 Retort oil correction curve [CoreLab, 1983]




4.10

A second disadvantage of the heating process is the removal of both pore water and water of

crystallization. The later is the bound water in clays and other hydrates. Subsequently, the

water recovery is too high. Figure 4.9 presents an example of water recovery vs. time and

temperature. The first plateau represents the volume of water in the pores. The second

plateau is the additional water due to the vaporizing of the crystallized water. In this way,

the retort can be calibrated for the given samples. A final disadvantage of this method is it

destroys the sample, therefore no further testing can be achieved.

Figure 4.9 Retort water calibration curves [CoreLab,1983]

Example 4.1

The corrected volumes of oil and water recovered from the retort method were 4.32 and 1.91

ml, respectively. Prior to this experiment, the bulk volume was measured to be 34.98 ml and

the grain volume was 26.34 ml. Determine the saturations of this sample.




4.11

Solution

The following stepwise procedure is presented.

a. The pore volume of the sample is, V p = V b – Vg = 8.64 ml.

b. The porosity of the sample is 24.7%.

c. Applying Eq. (4.2), the oil and water saturations are:

%2264.8

91.1

pV

wr V

wS

%5064.8

32.4

pV

or V

oS

d. The gas saturation cannot be measured and therefore is determined by the volume

balance (Eq. 4.1),

%28w

So

S1g

S

The Dean-Stark extraction method uses the vapor of a solvent to rise through the core

and leach out the oil and water. The water condenses and is collected in a graduated

cylinder. The solvent and oil continuously cycle through the extraction process. A typical

solvent is toluene, miscible with the oil but not the water. Figure 4.10 is an illustration of the

apparatus.

Figure 4.10 Dean-Stark Apparatus [CoreLab,1983]




4.12

The volume of the water collected relative to the pore volume provides an estimate of the

water saturation. The oil saturation is determined by,

o* pV

wtr W

dryW

wetW

oS

(4.3)

that is, by the weight loss not accounted for by the water. Equation (4.3) requires:

a. the weight of the core prior to the test (not cleaned!)

b. the weight of the core after the test, cleaned and dried

c. the pore volume from other methods

d. an estimation of the oil density

Example 4.2

The following procedure illustrates the usefulness of the extraction method.a. Obtain the mass of the saturated sample = 57 gms.

b. Determine the bulk volume by nondestructive means= 25 cc

c. Determine the oil density = 0.88 gm/cc

d. Place the sample in the extraction apparatus and heat the solvent. Record the

volume of water collected and when the reading becomes constant – stop. Vw =

1.4 ml

e. After cooling, remove the core and dry, obtain dry weight = 53 gms.

f. Using the saturation method, resaturate the sample with fresh water ( = 1.00

gm/cc) and weigh. 58 gms.

g. Calculate the pore volume and porosity,

%2025

5

cc500.1

5358

pV

h. Calculate the water saturation (Eq. 4.2),

%285

4.1w

S

i. Calculate the oil saturation (Eq. 4.3),

%5988.0*5

00.1*4.15357o

S




4.13

j. Calculate the gas saturation (Eq. 4.1),

%1359.028.01g

S

The advantages of the Dean-Stark method are the accuracy, the oil and water

measurement are on the same sample and the core can be used for further analysis. The

primary disadvantage of this method is the long time it takes to complete the measurement;

sometimes weeks. Also, it has been suggested oil in small pore throats and channels are

bypassed.

pet524 3a saturation

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