Introduction to Well Log Interpretation

Elias Abllah

Log interpretation, or formation evaluation, requires

synthesis of logging tool response physics,

geological knowledge

wellsite interpretation

Wellsite interpretation

Rapid approach to scanning an available set of logging measurements

To identify and draw some conclusion about zones of possible interest

These zones will warrant a closer and more quantitative analysis, by the

inclusion of additional knowledge and measurements

INTERPRETATION PRINCIPLES

INTRODUCTION

1. Does the formation contain hydrocarbons, and if so at what depth and are they oil or gas?

2. If so, what is the quantity present?

3. Are the hydrocarbons recoverable?

Three most important questions to be answered

Identify the zones with a low-volume fraction of shale (Vshale), also known as clean zones

the gamma ray

The gamma ray signal will generally increase in magnitude according to

the increase in shale content

spontaneous potential(SP)

SP is to become less negative with increases in formation shale content

Can the formation contain hydrocarbons?

If the formation is porous

density tool

neutron tool

acoustic tool

NMR

If the porous formation contains conductive brine, its resistivity will be low

If it contains a sizable fraction of nonconducting hydrocarbon, then the formation resistivity will be large

Effect of porosity on the resistivity

As porosity increases, the value of Rt will decrease if the water saturation

remains constant

Can the formation contain hydrocarbons?

Porosity Saturation Sw Water saturation Sw is a function of both formation resistivity Rt and porosity .

What is the quantity present?

If the value of Rxo is same as the value of Rt , then it is most likely that the original formation fluids are present in the flushed zone, indicating that no formation fluid displacement has taken place.

If Rxo is different than Rt , then some invasion has taken place, and the fluids are movable.

or

If the ratio of Rxo to Rt is the same as the ratio of the water resistivities in the two zones (Rmf and Rw),any hydrocarbons are unlikely to be producible in this case.

If the ratio of Rxo to Rt is less than that of Rmf to Rw, then some hydrocarbons have been moved by the drilling fluid and will probably be producible.

Are the hydrocarbons recoverable?

A summary of phenomenological interpretation

The generally overpressured wellbore causes invasion of a porous and permeable formation by the drilling fluid

Degradation of the formation during and after drilling. Overpressured mud is indicated to be invading porous and permeable sand formations with the formation of a mudcake.

The mud circulation also causes borehole washout in the shale zones.

THE BOREHOLE ENVIRONMENT

Distribution of pore fluids in zones around a well which initially contained hydrocarbons.

normal linear presentation, with the grid lines in all three tracks having linear scales each with ten divisions.

READING A LOG

The middle figure shows the logarithmic presentation for tracks 2 and 3. Four decades are drawn to accommodate the electrical measurements, which can have large dynamic ranges

hybrid scale with a logarithmic grid on track 2 and a linear one in track 3. Electrical measurements that may spill over from track 2 into track 3 will still be logarithmic even though the indicated scale is linear

The depth is shown by the numbers in the center track and the horizontal lines.

In Figure above the depth scale is 1/240, or 1 ft of log for 240 ft of formation.

The logs have a thin horizontal line every 2 ft, a medium thick line every 10 ft, and a thick line every 50 ft.

Depth

The bottom presentation shows the caliper, a one-axis measurement of the borehole diameter, and the gamma ray, which are also generally presented in track 1.

Note that the SP decreases to the left. The rule given for finding clean sections was that the SP becomes less negative for increasing shale, so that deflections of the SP trace to the right will correspond to increasing shalecontent

The GR curve, as it is scaled in increasing activity API units to the right, will also produce curve deflections to the right for increasing shale content.

Thus the two shale indicators can be expected to follow one

another as the shale content varies.

ILD corresponds to the deepest resistivity measurement and will correspond to the value of Rt when invasion is not severe.

ILM is a measurement of intermediate depth of penetration and is highly influenced by the depth of invasion.

SFLU is a measurement of shallow depth of investigation and reads closest to the resistivity of the invaded zone Rxo

The porosity is expressed as a decimal

(v/v) or in porosity units (p.u.), each

of which corresponds to 1% porosity.

The top heading shows the format for

porosities derived from neutron and

density measurements

simultaneously.

In this Example, porosity is shown

from 0.15 to 0.45 v/v.

The middle example shows an

additional correction curve for the

density log, which can be used to get

some idea of the mudcake and

rugosity of the borehole

The bottom heading is for the traditional sonic log

with the apparent transit time t increasing to the

left. In all three presentations, the format is such

that increasing porosity produces curve deflections

to the left.

For the neutron and density logs, the matrix

setting is listed as SS. If the formations being

logged are indeed sandstone, then the porosity

values recorded on the logs will correspond closely

to the actual porosity of the formation.

However, if the actual formation matrix is

different, then the porosity values will need to be

corrected in order to obtain the true porosity in this

particular matrix

The intervals of high SP above 8,500 ft and below 8,580 ft are generally identified with shale sections

The value of the typical flat response is called the shale base line, as indicated on the figure. Sections of log with greater SP deflection (i.e., with a more negative value than the shale base line) are taken as clean, or at least cleaner, zones.

One clean section is the zone between 8,510 and 8,550 ft

EXAMPLES OF CURVE BEHAVIOR AND LOG DISPLAY

Caliper (broken) and GR (solid) traces are shown for the same section of the well. Note the similarity between the GR trace

In the clean sections, the gamma ray reading is on the order of 15 to 30 API units, while the shale sections may read as high as 75 API units.

Note also that the caliper, in this example, follows much of the same trend. This trend results from the fact that the shale sections can wash out, increasing the borehole size compared to the cleaner sand sections that retain their structural integrity.

The zone below 5,300 ft is possibly water, because of a number of assumptions.

The effect of the resistivity of the mud can be seen by sighting along the shallow resistivity curve, which for the most part stays around 2 ohm-m.

At a depth of 5,275 ft, a possible hydrocarbon zone is noted. It is clear that the deep-resistivity reading (ILD) is much greater than in the supposed water zone.

However, this increase in resistivity may not be the result of hydrocarbon

Increase in resistivity may not be the result of hydrocarbon presence, why?

A decrease in porosity could produce the same effect for a formation saturated only with water.

The real clue here is that even though the Rxo reading has also increased (this indicates that the porosity has decreased), there is less of a separation between the Rxo and Rt curves than in the water zone.

Means that the value of Rt is higher than should be expected from the porosity change alone. By this chain of reasoning, we are led to expect that this zone may contain hydrocarbons.

log of a neutron and density device in combination. In addition to the density-porosity estimate in solid and the dotted neutron porosity, the compensation curve is also shown.

Note, once again, the built-in assumption that the matrix is sandstone. Where the density and neutron derived porosity values are equal, the presence of liquid-filled sandstone is confirmed

This is the case for the 20 ft section below 700 ft. Separation of the two curves can be caused by an error in the assumed matrix or by the presence of clay or gas

In the simplest of cases, gas is indicated in any zone in which the neutron porosity is less than the density porosity

Shale produces the opposite effect; the neutron porosity may far exceed the density porosity.

All of these generalities are true only if the principal matrix corresponds to the

matrix setting on the log. The effect of having the wrong matrix setting on the log(or having the matrix change as a function of depth) is shown in here

Several sections show negative density porosity. These are probably due to anhydrite streaks, which, because of their much higher density, are misinterpreted as a negative porosity.

Exercise 1

1. Identify the clean and possibly permeable zones

2. Resistivity readings in the selected zones are examined

3. Look at the neutron and density curves

Answer

G. E. Archie of Shell was making electrical measurements on core samples, with the aim of relating them to permeability

His measurements consisted of completely saturating core samples with saltwater of known resistivity Rw and relating the measured resistivity Ro of the fully saturated core to the resistivity of the water.

He found that, regardless of the resistivity of the saturating water, the resultant resistivity of a given core sample was always

related to the water resistivity by a constant factor F

(1)

Formation Factor

The formation factor is a function of porosity and can be expressed as a power law of the form:

(2)

where the exponent m is very nearly 2.

This empirical observation can be used to describe the variation in formation resistivity for a fixed water resistivity when the porosity changes.

The lower the porosity, the higher the resistivity will be.

The exponent m is the cementation exponent, as it was observed to increase with the cementation of the grains. In general, it was recognized that m increased with the tortuosity of the electric path through the pore space

Formation Factor

The exponent n, called the saturation exponent, is very nearly 2 for the data considered.

An approximate expression for the water saturation is

(4)

On loglog paper, the data of water saturation versus relative resistivity plotted as a straight line, suggesting a relationship of the form (3)

(5)

However, the fully saturated resistivity Ro can be related to the water resistivity using the previously discovered Archie relationship. So the expression becomes

(6)

However, a more general form, is

(7)

where the constants a, m, and n need to be determined for the particular field or formation being evaluated.

In order to interpret a resistivity measurement in terms of water saturation, two basic parameters need to be known:

porosity

resistivity of the water in the

undisturbed formation Rw.

Rw needs to be estimated. This can be done in either zone D or zone C, which have been identified as water zones.

Porosity is about 28 p.u., so the formation factor

F = 1/(0.28)2, or 12.8

Log Interpretation

apparent resistivity of about

0.2 ohm-m in these zones, which is assumed to be the fully water-saturated resistivity Ro, corresponds to a water resistivity of 0.2/12.8, or 0.016 ohm-m.

Rw= 0.016

Log Interpretation

It is clear that the increase in deep resistivity in zone C to about 4 ohm-m must correspond to a decrease in water saturation compared to zone C, the porosity seems to be constant at 28 p.u. over both zones. The saturation in zone C can be estimated from

so the hydrocarbon saturation is about 78%.

Zone of hydrocarbon A indicates the same resistivity value as zone C.

However, in the upper zone the porosity is much lower and can be estimated to be

about 8 p.u.

Thus the formation factor in zone A is 1/(0.08)2, or 156.

If it were water-filled, the resistivity would be expected to be

Rw x F= 0.016 x 156, about 2.5 ohm-m compared to the 4 ohm-m observed.

Thus the zone may contain hydrocarbons, but the water saturation can be expected to be higher than in zone C.

The water saturation in this zone can be estimated from Eq. 6 to be:

As Archie was aware, his equations worked well in rocks that have simple, uniform pore systems filled with saline water. Rocks with heterogeneous-pore systems, multiple-conduction mechanisms, or that are oil-wet need a more complete solution

The problems can be considered with reference to Archies three equations: the relation to porosity (m), the relation to Sw (n), and the definition of formation factor (F). We will consider m and n first, leaving the definition of F, which is mainly an

issue of clay conductivity

A NOTE OF CAUTION

The exponent m was named the cementation exponent, as it

was observed to increase with the cementation of the grains . In general, it was recognized that m increased with the tortuosity of the electric path through the pore space.

Early efforts focused on finding a relation with porosity, the idea being that as porosity decreased it was likely that the tortuosity, and hence m, increased.

Many relations were developed but proved to be specific to particular reservoirs or areas, and not generally applicable

The Porosity Exponent, m

Unlike m, it is not possible to derive n from logs in a water zone.

As a result there is much less data on n, and values other than 2 are less often used

However, laboratory experiments have highlighted two main conditions in which n can be significantly different than 2

wettability.

In lab, core samples were thoroughly cleaned of all their natural fluids

Experiments with native state have shown n values much larger than 2 in

oil-wet cores

Irregular pore space

water in some pore types may be displaced more easily than in others

Carbonates are heterogeneous, and are also more likely to be oil-wet, so

that for both reasons the relation between resistivity and Sw is

complicated, with n not equal to 2 and also varying with saturation

The Saturation Exponent, n

Clay appears to provide an additional conductivity

the structure of clay minerals produces a negative surface charge, because of substitution at the surface of the clay crystals of atoms of lower positive valence

The excess negative charge is neutralized by adsorption of hydrated cations

In an ionic solution, these cations can exchange with other ions in solution. A measurement of this property is called the cation exchange capacity, or CEC

Effect of Clay

Total porosity is the total nonsolid space, as measured by disaggregating a core sample

Effective porosity is less clearly defined.

For core analysts, effective porosity means the porosity measured after drying but before

disaggregation

For log analysts

For many production engineers, effective porosity means the pore space that contributes to

production

Total Porosity and Effective Porosity

Porosity determination using most of the logging devices presented in earlier

lesson relies on a knowledge of the parameters related to the type of rock being

investigated.

In the case of the density tool, the density of the rock matrix must be known.

The matrix travel time is used in interpreting the compressional wave interval transit time.

matrix setting for the neutron tool must correspond to the rock type for the value of n.

Determining these parameters is not much of a problem if one has good

geological knowledge of the formation and if the lithologies encountered are

simple, such as a clean sandstone or limestone reservoir.

Uncertain lithology?

Vary considerably in its composition?

Limestone formations with variable inclusions of dolomite and anhydrite

Sandstone with substantial calcite cementing

Lithology and Porosity Estimation

All three contain a dependence on porosity and a perturbation due to lithology.

Itseems natural to use these three measurements, two at a time, to eliminate porosity and thereby to obtain the lithology.

This is what is done in a number of wellknown cross plotting techniques which are presented next

GRAPHICAL APPROACH FOR BINARY MIXTURES

As can be seen from the figure, there is not a great deal of contrast between the matrix endpoints, so that a bit of uncertainty in the measured pair (b, t) could cause considerable confusion in the ascribed lithology

Density-sonic crossplot

The confusion is partially overcome in the neutron-sonic

more separation between the three principal matrices which are shown

Neutron-sonic

The neutrondensity cross plot is one of the oldest quantitative interpretation tools

Before the development of the photoelectric effect measurement, it was the principal method for determining the formation lithology.

It is still much used for matrix identification and estimating the formation porosity in gas-bearing formations

Neutrondensity cross plot

shows two apparent-porosity traces from the density and neutron devices, scaled in limestone units.

At the depth 15,335 ft, the density porosity reads about 2 p.u., and the neutron 14 p.u.

To determine the lithology, we need only to find the intersection of these two points

Use the porosity scaling on the matrix curve for which the log was run

Locating the 2 p.u. point on the limestone curve, we see that the corresponding density value is about 2.68 g/cm3

Dropping a vertical line from the 14 p.u. point for the neutron value, we see that the pair of points corresponds to a dolomite of about 11 p.u., which is marked as point a

If the logs had been run on a sandstone matrix

and yielded the same apparent porosity values,

the interpretation would be quite different

This can be seen by finding the 2 p.u. point on

the sandstone curve which corresponds to a

bulk density of about 2.62 g/cm3.

The 14 p.u. sandstone porosity for the neutron

is equivalent to the reading expected in a 9.5

p.u. limestone.

The intersection of these two points is marked

at b. This corresponds to a formation which

seems to be a mixture of limestone and

dolomite but could be a mixture of dolomite

and sandstone a less likely possibility.

Example which shows the evident separation in a 25 ft zone centered at about 1,900 ft

The neutron reading is about 6 p.u., and the density 24 p.u. Both are recorded on an apparent limestone porosity scale.

The location of this zone is shown as point c on the cross plot.

It is seen to be well to the left of the sandstone line. The trend of the gas effect is shown in the figure.

Following this trend, the estimated porosity is found to be about 17 p.u. if the matrix is assumed to be limestone.

Gas effect

Exercise

A neutron and density log in a sandstone

Plot a few points

It is Gas?

Use of the Pe, which can be obtained simultaneously with the density measurement

The companion Pe curve simplifies lithology determination in this sequence of alternating limestone and dolomites. The neutron and density information alone would not indicate gas in the lower interval

Before the availability of the Pe measurement, several methods were devised to combine the lithology information from the three porosity tools.

The first approach was called the M-N cross plot. It attempts to remove the gross effect of porosity from the three measurements before combining them to deduce the matrix parameters

The density-sonic cross plot yields a slope, designated as M

The neutron-density cross plot yields a slope, designated as N

COMBINING THREE POROSITY LOGS

M-N Plot

Apparent Total Porosity MID Plot

No computation required

Matrix point on MID plot arent dependent on porosity or salinity

M and N are abstract quantities

Advantage MID over M-N Plot