The importance of saturationmeasurements is reflected by

the time and effort which hasbeen devoted to gathering them.

The most fundamental reservoirparameters - oil, gas and watercontent - are critical factors indetermining how each oilf ield

should be developed.

In this article Jean-Louis Chardac,Mario Petricola, Scott Jacobsen and

Bob Dennis outline the importanceof saturation measurements and

reveal how the latest techniques arehelping reservoir engineers andgeoscientists to maximize production

and improve total recovery.

In search of saturation

Saturation, the proportion of oil, gas,

water and other fluids in a rock, is a

crucial factor in formation evalua-

tion. Without saturation values, fluid dis-

tribution can not be evaluated and no

informed decision can be made on the

development of an oil or gas reservoir.

When geologists and reservoir engi-

neers talk about oil ‘pools’, it sounds as

though there are large ‘bubbles’ of oil in

the rock sequence. In reality, the oil and

gas in hydrocarbon reservoirs is dis-

tributed through the pore space between

the sand or carbonate grains which com-

prise the reservoir layer (figure 2.1). In

the best reservoirs this porosity amounts

to between 25% and 35% of total volume.

This fraction of the reservoir is filled with

fluids in variable proportions and, as

reservoir conditions change through pro-

duction, the volumes which each occu-

pies will alter accordingly. For example,

as oil is produced, internal fluid pressure

drops and, in many reservoirs, this

releases gas from solution.

Saturation changes are critical to fluid

flow and must be carefully monitored to

optimize reservoir management, and

delay gas or water coning.

A great deal of effort has gone into the

collection and improvement of satura-

tion measurements. The wide range of

equations and models developed over

the years underlines the importance of

these measurements, and the complexity

of interactions between drilling mud,

rock, water and hydrocarbons around a

borehole.

Native metals and graphite conduct

electricity, but the vast majority of rock-

forming minerals are insulators. Electrical

current passes through a formation mainly

by the movement of ions in pore water.

Clearly, therefore, porosity is a critical fac-

tor determining resistivity - in short, high

porosity means low resistivity values.

Fluid saturation can be assessed indi-

rectly by measuring the resistivity or elec-

trical resistance of a rock layer. Some

fluids (e.g. gas and oil) have very high

resistivities while formation water and

shales have low resistivities. These varia-

tions can help to discriminate between flu-

ids, but the borehole and surrounding

rock layers are complex environments

where mixtures of mud, mud filtrate,

hydrocarbon, formation water and rock of

varying resistivity are encountered.

Attempts to understand and model

this situation would be difficult enough if

the mixture stayed in one place, unfortu-

nately it does not. Fluid properties

around every borehole change with time.

Invasion plansOne of the major problems with satura-

tion measurements is invasion - the

movement of drilling mud and mud fil-

trate into the formation (figure 2.2).

During drilling, mud is circulated from

the surface. Initially the formation is

invaded by a process referred to as

‘spurt’ invasion. This occurs as soon as

the drill bit exposes fresh rock surfaces,

with whole mud flowing directly into the

formation, replacing the water which

was present in the pore space.

However, within a few seconds, the

second stage of invasion begins. The

drilling mud forms a deposit (mud-cake)

on the side of the borehole and mud fil-

trate (a liquid filtered through the mud-

cake layer) oozes into the formation. The

depth and extent of invasion is controlled

by the physical properties of the mud,

the original formation fluid, and factors

such as porosity and permeability.

The mud filtrate invasion can be

modelled by resistivity measurements

which follow the ‘invasion front’

through the rock. This front is often rep-

resented as a single straight line but, in

22 Middle East Well Evaluation Review

Fig. 2.1: Oil and gas fills the pore space

between sand or carbonate grains. The

interactions between fluids and grains are

critical to oil and gas production. Initial fluid

saturation and wettability must be determined

to predict reservoir behaviour. Rocks may be

either water-wet (a) or oil-wet (b).

Fig. 2.2: Fluid distribution within a reservoir changes through time (a to d). Saturation, the relative

proportions of fluids in the reservoir will change with time and to model this change correctly it is

essential to measure initial oil and water saturations as accurately as possible. This measurement is

complicated by mud invasion - during drilling the undisturbed formation is modified by a rapid influx

of drilling muds which push oil and formation water away from the well.

Formation water Quartz grains Oil Mud

(a)

(b)

(b)

(d)(c)

(a)

Fig. 2.3: INVASION

PLANS: In vertical

wells the invasion zone

is more or less

symmetrical around

the borehole, with mud

filtrate reaching a

similar depth in similar

formations either side

of the hole (a). In

horizontal wells the

situation is more

complex. Thin beds

above and below the

borehole will be

invaded to a different

extent (b) while, in

other cases, invasion

may be controlled by

permeability variations

within a reservoir (c)

or by gravitational

effects (d).

23Number 17, 1996.

Fresh mud filtrate

Original pore fluids

(a) (b)

(c) (d)

thin beds

reality, the edges of the invasion zone

are usually ragged and its shape varies

in response to changing mud properties,

formation conditions and borehole

geometry, etc. (figure 2.3).

During the 1950s, when modern logging

techniques and tools were in their infancy,

the problem of invasion and water satura-

tion first became apparent. At that time,

invasion was seen as an inconvenient

environmental effect. The invaded zone (a

rock volume around the borehole which

has been filled by mud filtrate) affected all

shallow-reading tools such as density, neu-

tron porosity and micrologs. When water-

based oil was believed to have displaced

oil or gas, the logs from these tools had to

be interpreted very carefully. Even deep

resistivity logs, designed to record beyond

the invaded zone, could not be relied

upon in every well and corrections were

often necessary to evaluate the true forma-

tion resistivity (Rt).

In recent years technical advances

have helped to change attitudes to inva-

sion. The flushing of oil and gas away

from the wellbore presents a perfect

opportunity to study fluid displacement

within the reservoir. A technique - the

‘moved oil plot’ - has been developed to

take advantage of this. This plot com-

pares the volume of water in the invaded

and virgin zones. The difference

between these values is the volume of

hydrocarbon displaced.

In 1942 Gus Archie revolutionized the

way the oil industry looks at fluid satu-

ration in reservoirs. Before the publica-

tion of his ground-breaking paper

geoscientists found it difficult and

expensive to evaluate water saturation

and hydrocarbon reserves. The only

reliable method involved coring the for-

mation using oil-base mud and measur-

ing water saturation in the laboratory.

Logs measuring a formation’s electrical

resistivity were used to identify hydro-

carbon-bearing formations but could

not evaluate them quantitatively.

Archie’s equation relating saturation

to porosity and resistivity changed that.

Archie’s equation quantifies these

phenomena for clean, consolidated

sands with intergranular porosity. While

this provides a good solution in clastic

rocks, many carbonates, with their dif-

ferent pore geometries and variable size

are more difficult to evaluate.

The carbonate reservoirs of the

Middle East are characterized by mixed

wettabilities - micropores are water-wet

and filled with irreducible water, while

macropores contain oil and may be oil-

wet. The microporosity systems often

dominate resistivity measurements

from logs, giving apparent saturation

calculations which are inconsistent with

production data, e.g. dry oil from a zone

with computed Sw greater than 70%.

To overcome this problem both

porosity systems (and their wettabili-

ties) must be combined in a single equa-

tion for carbonate sequences. Recent

work in the Middle East has focused on

reliable measurements of the propor-

tions of micro- and macro- pores using

Nuclear Magnetic Resonance tech-

niques to evaluate pore size distribution

(see Microporosity Makes Sense) .

THE LONG ROAD TO SATURATION

Rt =Rw

φmSw

n

Electrical conduction in rocks is

mainly through ion movement in pore

filling brine. In rocks with open pores

ions move easily, giving low resistivity

values. In sinuous and restricted pore

systems, and those which contain hydro-

carbons, the flow of ions is reduced -

leading to higher resistivity values.

G.E. Archie (1942) The Electrical Resistivity Log as an

Aid in Determining Some Reservoir Characteristics.

Petroleum Transactions of the AIME 146, pp 54-62.

Where Rt = rock resistivity, Rw = waterresistivity, φ = porosity, Sw = watersaturation, m = porosity exponent and n =saturation exponent.

24 Middle East Well Evaluation Review

A ring of resistivity

In reservoir zones where there is fresh

mud invasion a characteristic low resis-

tivity zone, a ‘resistivity annulus’, devel-

ops. Moving out from the wellbore, logs

initially encounter a zone of high resistiv-

ity (containing oil and fresh mud filtrate),

then the annulus itself (a low resistivity

zone containing oil and saline formation

water displaced from the previous zone)

and finally, the high resistivities of the

original formation water/oil mixture.

A resistivity annulus probably exists

in every pay zone which is drilled with

fresh and oil-based mud - so it is vital

that the annulus is identified. If the

annulus is missed an oil or gas zone

may be overlooked. In wells where

saline mud is used the low resistivity

annulus does not develop.

Simplified models indicate the reasons

for a low resistivity anomaly (figure 2.4)

but do not represent the complex three-

dimensional distribution of oil, formation

water and fresh mud filtrate that mark the

saturation and salinity fronts. If detected,

the annulus is a clear indication that

hydrocarbons are present. However, if

the annulus effect develops beyond the

detection range of resistivity tools, Rt can

not be measured directly and a hydrocar-

bon zone may be overlooked.

This ‘high-low-high’ profile is very

important - when successfully recorded

it provides values for Rxo and Rt and,

more importantly, it indicates the pres-

ence of a ‘pay zone’. However, the low

resistivity annulus moves away from the

wellbore through time (as the mud fil-

trate continues to push low resistivity

formation water away from the well)

and, unfortunately, this movement pre-

sents yet another obstacle to resistivity

measurements.

How can we ensure that the annulus

is identified (to guarantee seeing a

hydrocarbon layer) and measure Rt as

the undisturbed reservoir zone is

pushed further from the well?

An annulus located a long way into

the formation (70 in. to 80 in. from the

wellbore) would give artificially low

readings on other deep reading induc-

tion curves and, in some cases, may be

beyond the maximum depth of investiga-

tion (figure 2.5). Fortunately, the AIT*

(Array Induction Imager Tool) can

record data from a zone centered 90 in.

from the borehole - much further than

any other deep resistivity logging tool.

This depth of penetration increases the

probability of identifying an annulus and

of obtaining a good value for Rt.

A deep induction log taking measure-

ments from the annulus would give val-

ues that were too low and an invasion

correction would probably be made to

account for these low values. However,

this would simply push the resistivity

value even lower.

Fig. 2.4: In reservoir

zones invaded by fresh

mud a characteristic

low resistivity zone,

or ‘resistivity

annulus’, develops.

When an annulus is

detected, we can be

sure that

hydrocarbons are

present. However, if

the annulus effect

develops beyond the

detection range of

resistivity tools, Rt

can not be measured

directly and a

hydrocarbon zone

may be overlooked.

Oil

Water

Distance from wellbore

Rxo

Rt

Rannulus

Freshmud

filtrate

Salinity front

Saturationfront

Res

istiv

ity

0 20 40 60 80 100

Medium

Deep

AIT 5

AIT 4AIT 3

AIT 2AIT 1

Depth of investigation (inches)

Fig. 2.5: DEEPER UNDERSTANDING: A resistivity annulus located 70 in. to 80 in.

from the wellbore could not be identified using deep induction. The deep induction

value recorded would be too low and if an invasion correction is made to account

for the low reading it will drive the resistivity value even lower.

25Number 17, 1996.

Standard inductionohm-m

Enhanced inductionohm-m1

50

100

150

200

1000 1 1000

Dep

th (

ft)Thin beds (figure 2.6) present some

unique logging problems. Enhancements

and elaborate processing of logs have

gone some of the way to overcoming the

thin bed problem. Induction measure-

ments are fundamental to formation

evaluation and, because of this, a great

deal of effort has been focused on

enhancing these logs. The methods

involved generally concentrate either on

signal processing or hardware improve-

ments. One of the most important signal

modification methods is deconvolution.

The measurement which appears on

a log is a convolved or ‘smoothed’ aver-

age of formation property variations

(figure 2.7a). Deconvolution extracts

actual depth variation of a formation

property (such as resistivity) by using

information on tool physics to sharpen

this vertically averaged measurement

(figure 2.7b). The key to this process is

knowing how the tool responds to a

vanishingly thin bed - the tool's vertical

response function (VRF). Once this has

been identified, it can be reversed and

the log deconvolved to reveal unaver-

aged formation properties.

Deconvolution must be carried out

with care. The process usually increases

noise and inaccurate results can be gen-

erated by mathematical instabilities.

Egyptian vision

Many of the oil and gas reservoirs in

Egypt's Western Desert are complex.

The Bahariya Formation, one of the

most important hydrocarbon units in

the region, is a prime example. The for-

mation is heterogeneous, mineralogi-

cally complex and very thinly layered

(figure 2.8).

Agiba Petroleum Company over-

came these problems by adopting the

latest advanced logging and interpreta-

tion techniques. High-resolution resis-

tivity imaging, coupled with saturation

imaging, gave a clearer indication of

radial fluid distribution around the

borehole. The radial coverage gave

good permeability indications and con-

tributed to a more realistic invasion

model. The AIT tool provides more

than resistivity measurements, it also

monitors borehole environment. This

has two benefits; the inputs required

by the environmental correction algo-

rithms are measured rather than esti-

mated and output logs are corrected in

real-time.

These real-time environmental correc-

tions and Rt calculations allow rapid

decisions based on high-quality data.

RESOLUTION REVOLUTION

Fig. 2.7: MODEL

PERFORMANCE:

Formation model

with marked

changes in

resistivity. The

standard log (a)

can not identify

subtle changes and

misses some peaks

completely. The

enhanced log (b)

identifies almost

every bed; the

thinnest being

about 2 ft thick.

Fig. 2.8: THIN BED BAHARIYA: The Bahariya

Formation in Egypt's Western Desert is a

heterogeneous, mineralogically complex

sequence of thin beds - in other words, a log

analyst's nightmare.

The ability to do all necessary process-

ing at the wellsite helps to accelerate

the entire evaluation process in com-

plex reservoirs.

As vertical resolution improves,

borehole effects become more pro-

nounced. This is a major problem in

bad borehole conditions, particularly if

very saline (conductive) borehole flu-

ids are present.

For one well in the Meleiha Field,

Agiba processed their data at all three

resolutions. The well was drilled with

water base mud. Borehole conditions

were fine and the logs were free from

unwanted borehole effects. At 4 ft resolu-

tion the logs are characterized by a very

smooth response, similar to conventional

induction logs, with few of the Bahariya

Formation's thin layers being detected.

At 2 ft resolution the logs show a lot

more detail, including the thin beds that

were missing in the 4 ft log. The 1 ft reso-

lution gives the thin bed information

and provides a more accurate estimate

of resistivity.

Fig. 2.6: THINK THIN: Thin beds can be a major problem in reservoir sequences. Alternations of

porous and tight rock types can alter well and reservoir performance dramatically - leading to

unpredictable early water production in some zones.

(a) (b)

26 Middle East Well Evaluation Review

Using the AIT tool, a resistivity annu-

lus can be identified more readily, and

the use of Tornado charts for correction

can be avoided.

The AIT tool was designed to tackle

three important problems:

• caving/borehole effects;

• invasion description;

• poor vertical resolution.

The AIT tool offers five fixed depths

of investigation, but the measurements

are not taken from single points in the

formation, but from areas that centre on

points 10, 20, 30, 60 or 90 inches into it.

Sampling at five depths of investiga-

tion offers many advantages over results

from just three depths. The high-low-high

resistivity variations we need to define

an annulus are more likely to be identi-

fied by five separate measurements

which can ‘see’ deeper into the forma-

tion. The AIT tool eases the analyst’s bur-

den - making 28 measurements and using

built-in borehole correction tables for

various borehole conditions (figure 2.9).

The latest development in AIT tool

technology has been specifically designed

for the Platform Express* system. It offers

the same five depths of measurement

but total tool length is only 16 ft. The

problem of erratic ‘stick-slip’ motion

encountered in some multiarray induc-

tion tools has been solved by adding an

accelerometer to provide real-time depth

correction for every tool on the string;

this also ensures that the tools are ‘on-

depth’ with each other.

New algorithms have been developed

and tested for a range of difficult logging

conditions. One of these gives better

readings in rugose boreholes and con-

ductive (saline) mud. Additional features

include correction to the resistivity logs

for dip or deviation up to 60°, and more

accurate estimates of Rt in the presence

of annulus.

However, when the annulus has

moved too far into the formation and has

passed beyond the maximum depth of

investigation for any available tool,

direct measurement of Rt is prevented.

Clearly, if Rt cannot be measured

directly, an estimation technique must

be devised. Experts are currently work-

ing on methods which will allow them to

invert resistivity profiles to obtain Rt and

Rxo mathematically, using five measure-

ments to evaluate five unknowns. At pre-

sent, this cannot be done quantitatively.

In addition to annulus identification,

the AIT tool helps to identify thin beds.

Many geoscientists are reaching the con-

clusion that thin bed analysis is important

in every reservoir. The majority of ‘thick’

reservoir intervals are usually layered -

made up of similar, but distinct thinner

units (figure 2.10). By identifying the

minor lithological contrasts which define

thin layers, it is possible to improve reser-

voir models and so enhance the predic-

tions which are based upon them.

Fig. 2.9: Borehole

corrections must be

carried out on the AIT

tool's 28 signals

before they can be

combined to form

logs. The corrections

are encoded as tables

for various borehole

conditions. The tables

were developed by

finite element

modelling of the

correction. This

complex 3D problem

required two years of

Cray computer time

to solve.

Fig. 2.10: The majority

of ‘thick’ reservoir

layers are actually

sequences of

lithologically similar

thin beds. Identifying

the minor differences

between these layers

improves the reservoir

model and, therefore,

the quality of

predictions and

simulations based

upon it. (Denise Stone,

AMOCO.)

When the resistivity of the invaded

zone is much lower than in the undis-

turbed reservoir, the ARI* (Azimuthal

Resistivity Imager) tool or standard dual

laterolog will give a more accurate deter-

mination of resistivity than the AIT tool.

It is, therefore, important to assess resis-

tivity contrasts before selecting tools.

In many Middle East reservoirs resis-

tivity contrasts mean that induction read-

ings are needed in the water layer, to

determine Rw (water resistivity) as accu-

rately as possible. When this is the case,

induction tools give the best results for

deep true resistivity. Accurate resistivity

measurements in water zones can be

vital. Indications of saturation within the

zone will influence major economic deci-

sions in the development of a reservoir.

For complete evaluation both types of

tool can be run together and this

arrangement would be of benefit in most

Middle East reservoirs. In practice, how-

ever, a choice is generally made and one

or other measurement is given priority.

27Number 17, 1996.

The AIT tool acquires data at three

vertical resolutions, but it is usually dis-

played at the highest (1 ft) resolution

(figure 2.11). In wells where conditions

are not good for resistivity determina-

tion, for example where borehole con-

ductivity is high or the borehole is

extremely rugose, there are no benefits

from processing data to display the high-

est resolution and logs are usually dis-

played at 2 ft or 4 ft resolution. However,

even at a vertical resolution of 4 ft, the

AIT is about twice as good as other stan-

dard fixed focus induction tools, an

important factor when investigating thin

beds with high resistivity.

The choice of vertical resolution at

which the log will be processed depends

on factors such as hole size and shape,

and the expected range of deep resistivi-

ties. In difficult environments the opera-

tor may decide to select a lower

processing resolution to make the data

more robust.

Sense and sensitivity

Calibration of the AIT tool requires a

‘zero conductivity’ environment, or con-

ditions which approximate this as closely

as possible. The process is carried out at

special facilities, using equipment which

contains no metallic components. During

calibration there must be no metal within

28 ft of the tool and there should be no

stray electrical signals (e.g. the charges

which build up during a thunderstorm)

to affect the settings. This extreme sensi-

tivity may seem inconvenient above

ground, but when the tool is where it

belongs - in the borehole - it can detect

the smallest fluctuations.

In many cases it could be beneficial to

run a FMI* (Fullbore Formation

MicroImager) or FMS (Formation

MicroScanner*) below the induction

tool. The AIT is the only induction tool

that can function in this configuration.

A through-wire sonde was specially

developed for the AIT tool which allows

other tools to be run below it in the

string. This seemingly simple task

required a great deal of engineering

effort. The AIT tool's conductivity mea-

surements detect minute voltage

changes and electrical connections run-

ning through the sonde were likely to

cause major problems unless the tools

could be shielded to eliminate their influ-

ence. Schlumberger has developed a

method which allows other tools to be

linked below the AIT tool without affect-

ing the very low signal levels measured

by the induction tool. This allows for

greater flexibility when a tool string is

being put together.

For the first time, tools such as the FMI

or FMS can be run in conjunction with an

induction log. Careful choice of scales

allows the operator to incorporate FMI or

FMS images into AIT images of resistivity,

Rwa or saturation without excessive dis-

tortion.

In too deep

In vertical wells, the assumption of sym-

metry around the borehole encouraged

the development of tools that looked

deeper into the formation as analysts

sought to measure values beyond the

zone invaded by mud filtrate. This

‘deeper is better’ philosophy is justified

in vertical wells, where the AIT tool can

‘see’ beyond the mud filtrate and mea-

sure Rt directly. Unfortunately, the

radial symmetry that is assumed in verti-

cal wells simply does not exist in highly-

deviated and horizontal wells (see figure

2.3). This asymmetry around the tool is

a problem. Induction tools measure σ(the conductivity of a bed) and interpre-

tation is based on a constant induced

conductivity along the measurement

loop. However, when the tool cuts differ-

ent layers (each having different con-

ductivities) a polarisation effect distorts

the readings.

Fig. 2.11: This figure

shows a saturation

map obtained from the

AIT tool and porosity

logs. The option of

running borehole

imaging tools, such as

the FMI and FMS, in

conjunction with an

induction log will

improve downhole

efficiency.

28 Middle East Well Evaluation Review

Over the past year a new generation of

Nuclear Magnetic Resonance (NMR)

tools has been introduced in the Middle

East. These tools, in contrast to the previ-

ous generation, no longer require mud

doping to kill the borehole signal and

this makes the technique applicable in

many more wells.

NMR measurements are made by

manipulating hydrogen protons in fluid

molecules. In a sense, the protons

behave as small bar magnets - their ori-

entations can be controlled by changes

in a magnetic field. A measurement

sequence starts with alignment of pro-

tons using powerful permanent magnets

(figure 2.12). The next step is spin tip-

ping. With the strong magnetic field B0

still applied, the aligned H nuclei are

tipped away from B0 by applying a high-

frequency oscillating magnetic field B1,

perpendicular to B0 (figure 2.13).

The H nuclei, now tipped in a plane

perpendicular to B0, rotate or ‘precess’

around the B0 axis. If the field B0 was per-

fectly homogeneous, all of the nuclei

would rotate in phase at a frequency

called the Larmor frequency. In reality,

some of the nuclei will collide with pore

walls (figure 2.14) and move back towards

the B0 direction while others may stay in

the plane of precession but be completely

out of phase with the rest of the nuclei. A

measurement of the small magnetic field

generated by the nuclei rotating in phase

will, therefore, decay as more and more

nuclei slip out of phase. In the laboratory

the longitudinal relaxation time (T1) is

usually evaluated but in the wellbore the

transverse relaxation time (T2) is mea-

sured instead. Both are directly related to

pore size (figure 2.14) but T2 is easier to

measure in a logging environment.

The theory set out above is compli-

cated by conditions in the oilfield.

Homogeneous magnetic fields can be

approximated in the laboratory, but not in

a borehole. The frequency of precession

is controlled by the magnitude of B0 and it

varies as B0 changes. Consequently, inho-

mogeneities in the field strength create

regions where the nuclei rotate at different

frequencies and are no longer in phase.

To counteract this ‘dephasing’ prob-

lem special sequences called CPMG

have been designed to re-focus those

nuclei which were no longer contribut-

ing to the measured signal, even though

they remained in the plane perpendicu-

lar to B0 and were precessing without

interacting with the rock surface.

B0 field Precessingmagneticmoments

Net magnetizationalong z-axis

z

y

x

z

y

x

B0 field

B1 field

Fig. 2.12: Proton alignment is the first step in

NMR measurement. Spinning protons are

aligned using powerful permanent magnets.

The protons precess around an axis parallel to

the B0 direction. In logging, B0 is perpendicular

to the borehole axis.

Fig. 2.13: Aligned protons are ‘tipped’ 90° by a

magnetic pulse oscillating at the resonance or

Larmor frequency.

Fig. 2.14: COLLISION COURSE: Precessing protons move about the pore space colliding with other

protons and with the grain surfaces. At every collision there is a possibility of a relaxation interaction.

Grain surface relaxation is the most important process affecting T1 and T2 relaxation times.

MICROPOROSITY MAKES SENSE

Ro

ck g

rain Rock grain

Rock grain

Ro

ck g

rain

Rock grain

Rock grain

Time, msec

Large pore

Am

plitu

de

Time, msec

Small pore

Am

plitu

de

Fig. 2.15: TIME TO

RELAX: Water in a

test tube has a long

T2 relaxation time,

3700 msec at 40°C.

Relaxation in a vuggy

carbonate might

approach this value

but water in normal

pore space has

shorter relaxation

times. In sandstones

relaxation times

range from 10 msec to

500 msec.

Middle East carbonate reservoirs often

display mixed wettabilities - their microp-

ores are water wet and filled with irre-

ducible water, while macropores in the

rock contain oil and are oil-wet. The

microporosity systems often dominate

resistivity measurements from logs, giving

apparent saturation calculations which

are inconsistent with production data, e.g.

dry oil may flow from a zone with a com-

puted water saturation greater than 70%.

To overcome this problem both poros-

ity systems (and their wettabilities) must

be considered for carbonate sequences.

This is achieved using the Combinable

Magnetic Resonance (CMR*) tool.

When saturations are computed using

an equation which accounts for the effect

of microporosity on the resistivity log a

different picture emerges.

This calculation reduces the water

saturation value slightly and, more

importantly, indicates that all of the

water is bound. Plotting the CMR-derived

bound fluid against the volume of water

computed from resistivity, with the spe-

cial saturation equation, shows a very

convincing match (figure 2.16).

29Number 17, 1996.

Fig. 2.16: UNTROUBLED

WATER: The high water

saturations recorded in some

reservoir zones can be

misleading. In this example,

conventional logs would

suggest that water might flow

from this zone. However, the

CMR tool shows that the water

is bound in the micropores and

the zone should flow dry oil.

The perforated zone, which

included porous zones with

high water saturations,

produced oil free of water.

The profiles match so well that adjust-

ing the cut-off to get the best possible fit

would seem a very good way to select

the correct value. This means that any

porous interval in this sequence can be

perforated and should flow oil without

any obvious risk of producing water.

When the interval in this example was

perforated it flowed dry oil for several

months. In the future, for a more com-

plete analysis, it may be advisable to

consider the relative permeabilities of

the various fluids as a function of satura-

tion but at this early stage simple empiri-

cal approaches are more likely to yield

useful results than more sophisticated

and theoretically rigorous methods.

Possible free water

Volume of water from RT

0.0 (PU) 25.0

0.0 0.25

CMR bound fluid

1:200ft

Boundirreducible water

Moved oil

Residual oil

X800

X900

-20 20(IN)

Diff. CaliperPerfs

Bound fluid

Water

Moved hydrocarbon

Oil

Water

Moved hydrocarbon

Oil

Residual oil

Porosity

Calcite

Dolomite

Anhydrite

3 3000

T2 THRESHOLD

T2 AMPLITUDE50.0 (PU) 0.0

M.J.C. Petricola and M.Watfa (1995) Effect of

Microporosity in Carbonates: Introduction of a Versatile

Saturation Equation. SPE paper 29841 presented at the

SPE Middle East Oil Show, Bahrain 1995.

M.J.C. Petricola and H. Takezaki (1996) Nuclear

Magnetic Resonance Logging: Can it minimize well

testing? 7th Abu Dhabi International Petroleum

Exhibition and Conference, SPE 36328 1996.

Fluid situations

In 1995 a comprehensive campaign of

NMR measurements was conducted in

Abu Dhabi. This involved eight wells and

four different operating companies. The

project was intended to evaluate the

NMR response of Cretaceous and

Jurassic carbonates which are the major

oil reservoirs across the region. In

parallel to the logging campaign, core

analysis was performed on samples from

five wells.

The main application of NMR mea-

surements in the Abu Dhabi study was

to understand pore size distribution in

reservoir zones, to determine bound

fluid volumes and, from this information,

improve predictions of the fluids which

will flow from any given zone.

However, there are a number of

major obstacles. Although the relaxation

time T2 is faster in rock pores than in a

test tube (figure 2.15), reduced logging

speeds were necessary to ensure full

characterization of the pore volume. The

average logging speed for the Abu Dhabi

project was between 200-300 feet per

hour. Faster logging rates (up to 900 feet

per hour) were possible when only

bound fluids were assessed; reflecting

the fact that these fluids are typically

contained in smaller pores.

Where:

Ct = total conductivity, Cw = water conductivity,

φ = porosity, Sw = water saturation, M denotes macro-

porosity and µ microporosity.

Note: fmod Sw depends on the distribution of micro-

porosity in the rock

Ct = Cw φMmM/X Sw nM/X + fmod SwM φµ

mµ/X Swµnµ/X X

Fig. 2.17: In a horizontal well the effects of nearby layers (in this case a shale cap rock) can

distort the resistivity measurements being taken in the oil or gas layer. The shale cap rock

with a resistivity of 4 Ωm lies approximately 5 ft above the reservoir layer. The oil resistivity is

200 Ωm, but a horizontal well less than 10 ft below the interface would record a value

somewhere between 40 and 170 Ωm.

30 Middle East Well Evaluation Review

In addition to the polarisation effect

there is an anisotropy effect. In horizon-

tal wells the hole is often situated at the

top of a reservoir zone - within a few feet

of an oil-shale interface - and deep resis-

tivity readings, influenced by the forma-

tion above the interface, are not helpful.

The effects of a shale cap rock, for

example, will distort the resistivity mea-

surements being taken in an oil reservoir

(figure 2.17). In this case a shale with a

resistivity of 4Ωm lies above the reservoir

layer. The oil has a resistivity of 200Ωm,

but measurements in a horizontal well

located less than 10 ft below the interface

would record a value between 40Ωm and

170Ωm. There are two possible solutions.

• Selection of deep readings in the appro-

priate direction (e.g. using the Azimuthal

Resistivity Imager, ARI* tool).

• Shallow readings taken before the

effects of invasion have pushed original

formation water away from the borehole

wall (e.g. using the Resistivity-at-the-Bit,

RAB* tool).

A sense of direction

Some tool developments have over-

come the asymmetry problem in hori-

zontal wells by offering directional

measurement. The ARI, for example,

makes 12 azimuthal (directional) read-

ings around the circumference of the

tool. Where the geometry of the well is

understood, it is possible to select read-

ings in the appropriate direction.

Resistivity readings of the LLd and

LLhr logs can be strongly affected by

azimuthal heterogeneities. In heteroge-

neous formations the ARI tool’s

azimuthal imaging can greatly improve

resistivity log interpretation - azimuthal

resistivity values can be selected and

the values obtained used in a model for

formation evaluation. This is particularly

important in horizontal wells, where the

selected measurement can be for the

zone below the well or, as is more likely,

along the target layer.

Figure 2.18 shows ARI and FMI

images, displayed with ARI resistivity

curves, in a formation which contains

some azimuthal heterogeneities.

The low resistivity readings at

x91.4 m and x92.2 m are clearly different.

This reflects the causes - the shallow low

reading is a continuous event (a low-

resistivity bed) whereas the deeper low

resistivity reading is due to a small het-

erogeneity which is almost certainly con-

fined to the area around the wellbore.

This resistivity low would almost cer-

tainly be mis-interpreted on a standard,

azimuthally-averaged, resistivity log.

Looking down

The ARI can differentiate between resis-

tivity above, below and in the plane of

the borehole. This is extremely useful

where anomalous resistivity conditions

Depth in

feet

-10

-5

0

5

10

Input model resistivity

Computed deep induction

Computed medium induction

1

1

1

1000

1000

1000

Shale 4Ωm

Oil 200Ωm

Fig. 2.18: The combination of ARI and FMI images with ARI resistivity curves clearly indicates that

the low resistivity readings at 91.4 m and 92.2 m are caused by different types of heterogeneity.

Standard, azimuthally-averaged logs would not reveal this difference.

Fig. 2.19: If a horizontal well is drilled accurately and is located close to the top of a reservoir zone,

the important formation properties are those below the well, not an average of properties above

and below. These graphs clearly indicate the value of the ARI tool.

31Number 17, 1996.

Flex joint

Flex joint

are encountered - for example when the

borehole is approaching a layer where

water breakthrough has occurred or is

close to a shale layer or crossing tight

layers, etc.

One benefit of using the ARI tool is

illustrated in figure 2.19. The first cross-

plot shows the ‘ARI down’ resistivity

plotted against bulk density while the

second shows standard LLd resistivity

versus bulk density. The ARI down cor-

relation is clearly better than that from

the LLd. The main reason for this is that

the ARI down is affected by the same for-

mation as the density since in a horizon-

tal well such as this the weight of the

density pad makes it very likely that it

will be facing the lower side of the hole.

The LLd is reading an average resistivity

from around the borehole and produces

a resistivity reading which is too low

when the formation under the borehole

has a high-resistivity and too high when

the formation below has a low resistivity.

Saturation estimates rely on accurate

resistivity values. Using the ARI tool the

operator can select the most appropriate

direction and, therefore, most realistic

value for formation resistivity.

The ARI tool has been used in the

Middle East to examine low resistivity

fractures in an effort to characterize poros-

ity. The challenge of logging horizontal

wells remains and ongoing research is

aimed at providing the answers.

Azimuthally averaged readings are of

little use in horizontal wells. LLd, LLs

and induction logs, for example, are

influenced by beds which are parallel

and close to the borehole. This can be

crucial to interpretation when a well is

steered close to the top of a reservoir.

Tools having different depths (or vol-

umes) of investigation may give very dif-

ferent results in the same horizontal

well. A density tool, which takes a very

shallow reading may indicate sands

while a neutron detector may indicate

an overlying shale. The quantitative

azimuthal image from the ARI tool helps

to detect and identify these beds and so

allow the most representative reading to

be selected from the azimuthal deep

resistivity measurements.

In practice, resistivity tools are seldom

run alone for complete formation evalua-

tion. Laterologs are often combined with

microresistivity tools and porosity tools

to produce the so-called ‘triple-combo’.

These combined strings are often

more than 90 ft long and, while they

improve efficiency by reducing the num-

ber of logging runs, they pose problems

in an extended rig up/rig down period,

reduced logging speed and the need to

drill more rathole (additional depth at

bottom of the well) to ensure complete

coverage by all three sections of the

‘triple-combo’.

2.0

10

LLH

R

100

2.2 2.4RHOB

RHOB vs ARI (LLHR down)Frequency crossplot

2.6 2.8 3.0 2.0

10

LLD

100

2.2 2.4RHOB

RHOB vs DLT (LLD)Frequency crossplot

2.6 2.8 3.0

A new laterolog tool, the HALS* (High

Resolution Azimuthal Laterolog Sonde)

has been developed to overcome these

problems. Only 16 ft long, HALS is half

the length of the dual laterolog, and has

an azimuthal resistivity array. Used cor-

rectly, directional measurements help to

clarify the situation in horizontal wells.

This tool has been designed to cope

with rough sections and deviated bore-

holes (figure 2.20). The flexible jointed

construction and short pad length help

to keep the tool pressed against the bore-

hole wall.

In some sequences, the complexity of

lithological variation makes results from

a single tool almost useless. In future,

efforts may focus on running several

resistivity tools during the same logging

run; and cross-referencing between them

to construct a clear picture of reservoir

lithology and relative bed thicknesses.

This 3D modelling will require advanced

software packages and a better under-

standing of reservoir geometry.

Fig. 2.20: Flexible

joints allow the HALS

to ‘hug’ the borehole

wall, thereby

ensuring accurate

measurement as the

tool body moves in

and out of rough

sections. The shorter

pad also improves

logging results in

deviated holes.

Fig. 2.21:

BUTTONS AND

RINGS: Using a

ring electrode Rt

can be measured

accurately when

the RAB tool is

run close to the

bit (i.e. when it

logs the formation

before significant

invasion effects

develop). The

button electrodes

measure

resistivity at

different depths

and can help to

identify the zones

where invasion

starts. In the right

conditions, they

can be used to

compute invasion

diameter.

32 Middle East Well Evaluation Review

The shallow end

One alternative to directional or deep

measurement of resistivity is to take shal-

low measurements during drilling - in the

very early stages of invasion. It is now

possible, using Logging While Drilling

(LWD) technology, to measure resistivity

at the bit.

Field tests conducted with the RAB*

(Resistivity-at-the-Bit) tool show that

measurements made using the ring elec-

trodes (figure 2.21a) record Rt accurately

when run close to the bit (i.e. when the

formation is logged before significant

invasion effects develop). Its perfor-

mance has been assessed using deep

resistivity tools such as Laterologs.

Transmitter

axial

Collar

Insulation

Ringelectrode

Buttonelectrode

Ringmeasurecurrent

Receivermeasurecurrent

Ammeter

Ammeter

Cross-section view

Fig. 2.22: The RAB tool's ring electrode

induces a voltage difference in the string,

causing current to flow into the formation.

As this returns (arrows), it is measured to

derive formation resistivity. Button resistivity

(red area) delivers good vertical resolution

and allows the borehole to be scanned as the

tool rotates.

(a)

(b)

When the RAB tool is run some time

after the drill bit, the resistivity value is

affected by invasion. However, ‘tornado’

charts can provide a reasonable correc-

tion in order to determine Rt and calcu-

late saturation.

When run directly at the bit and mak-

ing measurements using the bit itself, the

RAB tool provides critical information

for geosteering, or for selection of casing

and coring points as soon as the forma-

tion of interest is penetrated.

Sensors located very close to the drill

bit detect changes which indicate when a

well is about to leave the target zone and

move into adjacent shale or water layers.

This allows the driller and geologist to

steer a well in real-time, ensuring that as

much of the well as possible stays within

the reservoir layer. The RAB tool was

designed to perform this task and to mea-

sure Rt accurately in saline muds with

high resistivity formations. In these situa-

tions, borehole and invasion effects on

the tool are small.

The RAB tool has greatly extended

the range of conditions where accurate

formation resistivity measurements can

be made while drilling. It is suitable for

very high-resistivity formations, and can

make multiple measurements at four

depths of investigation.

33Number 17, 1996.

Fig. 2.23: DOWNHOLE

NAVIGATION:

Detailed images of the

borehole can be

recorded and stored

downhole in the RAB

tool for later analysis.

The imaging facility

can be switched on or

off, allowing the

operator to select

specific well intervals

for detailed

examination.The data

transfer rate from tool

to surface is the only

obstacle to real-time

resistivity imaging.

x015

x020

x025

x030

x035

x040

x045

x050

x055

Right on the button

The RAB tool’s button electrodes (figure

2.21b) measure resistivity at different

depths and can help to identify the

zones where invasion starts. In the right

conditions, they can be used to compute

invasion diameter.

As the tool rotates, the RAB buttons

take resistivity measurements from

around the wellbore (figure 2.22). This

azimuthal resistivity data is stored in the

RAB tool and can be retrieved when it

returns to surface. The image which is

generated allows computation of dips,

fracture detection and estimation of frac-

ture aperture and orientation. The fea-

tures shown are similar to those

obtained using the ARI tool, but offer

better resolution.

The RAB button measurements pro-

vide a good indication of movability

when a sufficient break is allowed after

drilling. This, however, conflicts with the

objectives of early logging - to establish a

value for Rt. One solution is to run two

RAB passes, one close to the bit to

assess Rt and another after invasion to

evaluate movability.

Additional resistivity data, including

detailed images of the borehole (figure

2.23) can be recorded and stored down-

hole for later inspection. Detailed resistiv-

ity imaging using the button electrodes is

possible because the resistivity measure-

ments are made in the very early stages

of invasion (figure 2.24).

The restricted data transfer rate

between tool and surface is the only

obstacle to real-time resistivity imaging.

Horizontal drilling can be compared

to driving your car or taking a bus across

a city. The RAB tool offers the freedom

of the car driver - the driller and geolo-

gist can stop at any time to consult a

‘map’ of changing borehole conditions,

take pictures of the borehole as they

pass through and change direction to

reach the right destination. Traditional

horizontal drilling, by comparison, is like

falling asleep on the bus and arriving

somewhere you may not want to be,

with no idea of how you got there.

Fig. 2.24: High quality

measurements are

possible with the

RAB tool because it

examines the

formation almost as

soon as it is drilled -

while invasion effects

are at a minimum.

Drilling mud

RAB tool

Invasion front

34 Middle East Well Evaluation Review

Cased hole choices

In cased holes, reservoir evaluation and

saturation monitoring are performed in

one of two ways. The first method TDT*

(Thermal Decay Time principle) mea-

sures the decay of thermal neutron pop-

ulations and the other uses tools such as

the RST* (Reservoir Saturation Tool) to

assess changes in a reservoir’s fluid satu-

rations.

The RST tool contains a minitron - an

electronic neutron source - which fires

high energy neutrons through the casing

and into the rock layers around the

borehole. These neutrons interact with

the borehole and formation fluids, pro-

ducing gamma rays. The RST tool mea-

sures the returning gamma rays to

identify water and oil saturations.

Setting your sights on sigma

There are two basic mechanisms which

help to identify saturation values - neu-

tron capture and inelastic scattering (fig-

ure 2.25). In neutron capture, the high

energy neutrons from the minitron

source, after slowing down to a thermal

energy level, are incorporated into the

nucleus of rock or fluid atoms - this is

the basis for Σ (sigma) measurements.

Inelastic scattering with fast neutrons

(where the neutron strikes the rock or

fluid nucleus but is not captured by it) is

the basis for C/O measurements (see

below).

The different atoms which comprise

oils, formation water, rock etc. capture

different amounts of neutrons. This cap-

ture value is referred to as the material's

capture cross-section. The capture cross-

section for formations which contain a

lot of high-salinity water is large. Rocks

that contain oil and little or no saline

water have a low capture cross-section.

Typical capture cross-section (Σ) values

for salt water are in the range 80 to 100,

while the values for oil are usually

around 20 (figure 2.26).

There is a simple, linear relationship

between saturation and Σ which, in ideal

conditions, allows a quick and accurate

determination. However, there are possi-

ble complications. For example, if there is

mud filtrate behind the pipe, the Σ values

will reflect this and, in non-perforated

zones, there is no way to estimate the

effect of any residual mud. In perforated

zones it is likely that the mud has been

removed by the perforation process and

the pressure of flowing hydrocarbon, but

even here the Σ values can not be relied

on entirely. The measured values at and

around the perforation reflect a disturbed

reservoir state and may not be character-

istic of the rest.

This problem is particularly acute in

the Middle East where perforated zones

are often acidized to improve permeabil-

ity. The acid reacts with the formation car-

0

20

40

60

80

100

Oil Injected Water

Saline FormationWater

Salinity of pore fluid

Cap

ture

cro

ss-s

ectio

n

Slow neutron

Fast neutron

Nucleus

Excited nucleus

γ-ray

Nucleus

Excited nucleus

γ-ray

Neutron capture

Inelastic scattering

Fig. 2.25: In neutron capture, neutrons are

incorporated into the nucleus of the fluid atoms

- the gamma-rays released are recorded to

derive the Σ measurements. Inelastic scattering

with fast neutrons (where the neutron strikes

the rock or fluid nucleus but is not captured by

it) and associated gamma-ray release, is the

basis for C/O measurements.

Fig. 2.26: Capture cross-

sections for various

atoms can help to

characterize the fluid

content of formations.

The difference between

oil’s capture cross-

section (around 20)

and water (in the range

80 to 100) is a simple

way to distinguish

reservoir zone from

aquifer. However, it is

impossible to

differentiate between

oil and injected water

using this method.

bonate to give a high capture cross-section

reading with the TDT tool. Consequently,

potential oil zones in acidized wells can

give a typical water zone reading. This

‘acid effect’ is one of the main reasons

why saturation monitoring should take

place in observation wells - not producers.

In most wells, the Σ values provide a

good approximation of saturation. The

high-salinity formation water is easily dis-

tinguished from hydrocarbons. However,

fresh water injected into the well (and, in

comparison to formation water, seawater

can be considered ‘fresh’) will give values

close to those for oil. So, in places where

fresh water is being injected another type

of measurement is required.

Carbon and oxygen

In C/O logging the relative concentra-

tions of carbon and oxygen atoms in the

formation fluids are measured to assess

saturation. In the past, this method was

restricted to relatively shallow depths of

investigation, producing results which

were difficult to interpret (influenced by

the carbon in carbonate minerals,

cement etc.) as well as being relatively

slow (about 20 ft/hour).

35Number 17, 1996.

2 3 4 5 6 7

Oxygen

Silicon

Calcium

Iron

Carbon

Energy (MeV)

Rel

ativ

e co

unts

0

104

105

106

107

2 4 6

Energy (MeV)

Rel

ativ

e co

unts

Hydrogen

Carbon

Oxygen

Inelasticoil

Inelasticwater

Fig. 2.28:

ELEMENTAL

FINGERPRINTS: This

plot of standard

spectra for the RST

tool can be used to

‘finger print’ the five

elements shown.

Although oxygen and

carbon are the most

important elements

for saturation

monitoring, the

presence of carbon

and oxygen in rocks

(e.g. limestones) and

in cement means that

formation corrections

may have to be made

in order to identify

true saturation effects.

Fig. 2.27: Inelastic

burst spectra. This

example shows a test

set-up with the tool's

far detector immersed

in tanks of oil and

water. Peaks for

carbon atoms (in the

oil) and oxygen

atoms (in the water)

are easily identified.

The previous generation of logging

tools were large and operated at very

slow speeds. An additional problem was

their sensitivity to borehole fluid which

restricted the use of carbon-oxygen log-

ging. In cases where C/O logging was

required, the well usually had to be

killed and the production tubing pulled.

Given all of these problems and limi-

tations it is not surprising that time and

effort was devoted to improving the tech-

nique. When there is fresh water in the

formation this is the only method that

can be used.

Hardware improvements and the

development of systems, such as the

RST tool, have been the main focus of

research efforts.

The compact design of the RST tool

means that a well can be logged quickly

without killing the well or pulling the pro-

duction tubing. The tool can compensate

for borehole fluid composition; allowing

formation oil saturation to be measured

and borehole oil/water fraction to be

assessed while the well is flowing.

All the right elements

The RST tool can analyze the energy of

returning gamma rays to identify chemi-

cal elements in the formation. A standard

spectrum has been obtained for the tool

as a result of extensive testing and this

can be used to identify the elements pre-

sent in the formation. For saturation mon-

itoring, the most important elements are

oxygen and carbon which provide infor-

mation on the presence of water and

hydrocarbons respectively (figure 2.27).

However, since many rock types con-

tain carbon and oxygen (e.g. limestones -

CaCO3 and organic-rich shales), it is

important that the elements contained in

rock-forming minerals can be identified.

Some of the most important rock con-

stituents are calcium, silicon and iron.

The RST tool can identify these elements

(figure 2.28), give an indication of lithol-

ogy and, therefore, provide a more accu-

rate assessment of saturation.

A slimhole tonic?

The RST tool is available in two sizes -

small and smaller. The standard RST tool

has a diameter of 21/2 inches, while the

slim RST tool, measures just 111/16 inch-

es Eliminating the need to kill a well and

pull the tubing cuts out the associated

risks and minimizes production loss.

Interpretation is enhanced because kill

fluids do not invade the formation. The

smaller RST tool does not offer all of the

larger tool’s features, but it is designed

for use in shut-in wells.

The carbon/oxygen ratios from RST

analysis are plotted to assess the proba-

ble saturation values for rocks of a partic-

ular porosity (figure 2.29). All data should

fall within the box defined by the four oil

and water values (w-w, o-w, o-o and w-o).

00

0.2

0.4

0.6

0.8

1

1.2

0.2 0.4 0.6 0.8 1

Dual detector COR modelfor 21/2 in RST tool

o-o

o-w

w-w

w-o

Borehole oil

Form

atio

n oi

l

yo so

Near carbon/oxygen plots

Far

car

bon/

oxyg

en r

atio

w-w: water in boreholeo-w: oil in boreholeo-o: oil in boreholew-o: water in borehole

water in formationwater in formationoil in formationoil in formation

Fig. 2.29: This type of plot is used for

interpretation of RST results. This plot shows

the expected range of values for a 43 porosity

unit limestone formation, with the tool in an

81/2 in. borehole with 7 in. casing. All data

should fall within the box.

36 Middle East Well Evaluation Review

In gas-bearing sandstones, mud filtrate

invasion is often very deep. When this

occurs it can be difficult to discriminate

gas-bearing intervals from those con-

taining oil or water. Shaliness and the

extreme effects of invasion can mask

the familiar ‘gas crossover’ between

neutron and density logs. Recorded

water saturations can reach 80% in

some formations, even with deep resis-

tivity measurements. The low resistivity

annulus has long been considered a

good hydrocarbon indicator, but in some

formations the time delay between

drilling and logging can mean a very

deep annulus which is beyond the inves-

tigation depth of standard resistivity log-

ging tools. The resulting low recorded in

deep resistivity can lead to an unduly

pessimistic evaluation of the well.

The Catoosa drilling project was set

up to investigate the effects of different

types of mud systems on invasion

depth. The drilling and logging were car-

ried out under carefully controlled con-

ditions. The gas-bearing formation

selected for the study was the

Bartlesville sandstone, a shallow, low-

pressured (depleted) section at Amoco's

test drilling site in Oklahoma, USA.

Three test wells were drilled with differ-

ent fluid loss control systems. However,

some important aspects of log analysis

in gas reservoirs were examined.

Three wells were drilled with potas-

sium chloride (KCl) mud, one with a

high fluid loss, the second with a low

fluid loss, while the third was drilled

with a partially hydrolized polyacry-

lamide polymer system (PHPA) - an

inhibitive system used to prevent shale

sloughing, differential sticking and skin

damage. Although this mud system is

thought to limit mud filtrate invasion,

the invasion depth in this well was

greater than in the other test wells.

New generation logging tools with

new or additional measurements indi-

cated that there were some fundamen-

tal problems with the ways in which

conventional logs are often used. The

neutron-density gas crossover is

affected by formation shaliness and can

be totally eliminated by an invasion

which exceeds 10 in.

The AIT resistivity logs indicated

that the invasion in all three test wells

had formed an annulus and an inver-

sion of the logs allowed an accurate

estimate of Rt. In one instance (the

Bartlesville sandstone) the resulting sat-

uration proved to be one third less than

the value derived from the Phasor

Induction tool (figure 2.30).

In the Bartlesville sandstone the AIT

tool’s 60 in. and 90 in. logs are in reverse

order - indicating an annulus in this

zone. Figure 2.31 shows a plot of the

sweep of the annulus inner radius for

final saturation values in this unit at

887 ft. This point was chosen because it

represented the largest curve separation.

Differences in curve separation at other

depths are probably due to changes in

porosity and depth of invasion.

R.L. Terry, T.D. Barber, S. Jacobsen and K.C. Henry.The

Use of Modern Logging Measurements and New

Processing Algorithms to Provide Improved Evaluation in

Deeply Invaded Gas Sands. Presented at the 35th

SPWLA Logging Symposium, Tulsa, Oklahoma, USA.

June 19-22 1994.

87010

AIT resistivity (ohm-m)

AO10Vsh/2

ϕ SFLIMVRIDVR

AO20AO30AO60AO90

Fractional volume DIL resistivity (ohm-m)0.3 0.2 0.1 0.0 10

880

890

Dep

th (

ft)

900

910

920

THE CATOOSA DRILLING PROJECT

Fig. 2.30: A direct comparison of AIT and Phasor Induction logs in the

Bartlesville sandstone. Porosity and Vshale logs for reference.

Fig. 2.31: AIT log

values as a function

of radial depth at the

annulus. The annulus

position, indicated by

the green vertical

line, most closely

matches the log

values in figure 2.30

at the well depth

indicated.

Bartlesville Sandstone

Petrophysical parameters:

Sw = 0.35Sxo = 1.0

Rw = 0.085Rmf = 0.98

ϕ = 0.17Vsh = 0.25

Rsh = 8.5Rwlrr = 0.025

10 20 30 40 50 60 70 80 90 100

Pet

roph

ysic

al p

aram

eter

s10

110

0

r1 (in.)

Annulus positionat 887ft

RxoRannRT10 In

20 In30 In60 In90 In

In one example, a well producing from

a carbonate reservoir - with porosity

between 5pu and 30pu - produced oil with

a watercut of about 20%. Figure 2.32 shows

a crossplot of the near and far carbon-oxy-

gen data from this well compared with lab-

oratory data for a limestone saturated with

water or oil with a density of 0.85g/cm3.

The large bounded area shows the

dynamic range for a 43pu limestone and

the inner area that for a 17pu limestone.

Some of the data points fall outside the

bounded area - this is due to statistical

variations, a borehole which was slightly

larger than the assumed 6 in. diameter

and a low oil density (0.715g/cm3) at

reservoir conditions.

The RST can be used for a variety of

tasks - reservoir monitoring, detection of

water breakthrough and fluid contact

monitoring.

Gas and gravity

There are alternative methods for deter-

mining gas and oil saturations. In reser-

voirs where gas is present, gas neutron

measurement techniques are used to

evaluate the Hydrogen Index within a

layer. From this it is possible to derive

the gas-oil saturation value.

The density contrast between gas and

water is the key to the borehole gravime-

try technique. It is used to measure gas

cap expansion or to track the entry of

gas from injection wells - gas displacing

oil, not water displacing oil.

As oil is produced from a reservoir it

is replaced by gas. However, the density

contrast to be assessed covers very

large areas and the changes which have

to be detected call for very accurate

measurements.

Enter the third dimension

Since the 1950s, research into resistivity

tools and techniques has continued with-

out interruption. Many of the analyses

which can be made today would have

seemed impossible twenty or even ten

years ago. However, the oil industry’s

appetite for information, gathered more

rapidly and with greater accuracy than

before, has not yet been satisfied.

New software is under development

which will combine all of the resistivity

tools, including LWD measurements, to

derive the best possible resistivity value

in all borehole conditions - variable bore-

hole size, formation resistivity, mud

resistivity Rt /Rxo contrast etc.

However, there are many more possi-

bilities to be explored to make the most

of the 3D aspect of the new resistivity

measurements provided by tools such as

the AIT. For example, running the AIT

tool in combination with an ARI tool

would allow the use of ARI electrical

stand-off and calliper information to

refine the AIT borehole correction.

-0.2 00

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.2Carbon/oxygen ratio (near)

Car

bon/

oxyg

en r

atio

(fa

r)0.4 0.6 0.8 1

Shut in

Flowing

Lab data 43 p.u.

Lab data 17 p.u.

Fig. 2.32: This

crossplot compares

near and far

carbon/oxygen

ratios (with the test

well shut in and

flowing) with

laboratory data for

limestone saturated

with either oil or

water having a

density of

0.85 g/cm3.

Number 17, 1996. 37

Fig. 2.33: The

combination of ARI

and AIT tools will

allow the user to

establish a 3D picture

of formation

resistivity, apparent

water resistivity and

hydrocarbon

saturation (from the

AIT) and to link these

values to wellbore

features recorded by

the ARI tool.

When running together, these tools

provide a radial description of resistivity

variations (from the AIT) and an

azimuthal measurement (from the ARI).

If these can be combined, a true 3D rep-

resentation of resistivity around the well-

bore might become available at some

future date (figure 2.33).

At present, however, there is no soft-

ware capable of delivering a true 3D

resistivity image. Combining both types

of logs may be a starting point in the

development of this kind of system.

If a 3D method could be developed

one of the most obvious applications

would be in horizontal wells where the

resistivity measured on the lower side of

the borehole can generally be better cor-

related with the density/porosity mea-

surements which are themselves affected

mainly by the petrophysical properties of

rocks and fluids in that location.

While it may be some time before true

3D imaging can be developed, the consid-

ered combination of radial and azimuthal

resistivity information we have at present

will greatly enhance our understanding

of invasion and reservoir heterogeneity.

Another possibility would be to com-

bine ADN (Azimuthal Density Neutron)

and RAB tools. This arrangement has not

yet been run in the Middle East, but it

would provide four porosities and four

resistivity measurements which could be

combined to give four saturation values.

The pursuit of high-quality saturation

data has been a long and difficult pro-

cess. The new generation of tools and

techniques offer a wealth of information

which is helping to transform our per-

ceptions of reservoir behaviour.